e424b5
CALCULATION OF
REGISTRATION FEE
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Maximum
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Maximum
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Amount of
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Title of Each Class of
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Amount to be
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Offering Price per
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Aggregate Offering
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Registration
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Securities to be Registered
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Registered
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Unit
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Price
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Fee(1)
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8.625% Senior Notes due 2017
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$300,000,000
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98.578%
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$295,734,000
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$16,501.96
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(1) |
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Calculated in accordance with Rule 457(r) under the
Securities Act of 1933. |
Filed Pursuant to
Rule 424(b)(5)
Registration Number 333-161809
Prospectus supplement
(To prospectus dated September 9, 2009)
Concho Resources Inc.
$300,000,000
8.625% Senior Notes due
2017
We are offering $300,000,000 of our 8.625% Senior Notes due
2017, which we refer to as the notes. The notes will mature on
October 1, 2017. We will pay interest on the notes on
each April 1 and October 1, beginning on April 1,
2010.
We may redeem some or all of the notes at any time on or after
October 1, 2013 at the redemption prices set forth
under Description of notesOptional redemption
and prior to such date at a make-whole redemption
price. We may also redeem up to 35% of the notes prior to
October 1, 2012 with cash proceeds we receive from certain
equity offerings. If we sell certain assets and do not reinvest
the proceeds or repay senior indebtedness or if we experience
specific kinds of changes of control, we must offer to
repurchase the notes.
The notes will be our unsecured obligations and will rank
equally in right of payment with all of our existing and future
senior indebtedness and senior in right of payment to all of our
future subordinated indebtedness. The notes will be structurally
subordinated to any of our existing and future secured debt to
the extent of the value of the collateral securing such
indebtedness, including all borrowings under our credit
facility. The notes will be structurally subordinated to all
liabilities of any of our subsidiaries that do not issue
guarantees of the notes.
The obligations under the notes will be fully and
unconditionally guaranteed by all of our current subsidiaries
and by certain of our future restricted subsidiaries. The
guarantee of any subsidiary will be released when such
subsidiary no longer guarantees certain specified indebtedness,
when such subsidiary is no longer a subsidiary of ours or when
such subsidiary is designated an unrestricted subsidiary under
the terms of the indenture. The guarantees will rank equally in
right of payment with the existing and future senior
indebtedness of the guarantors, including their guarantees of
our borrowings under our credit facility, and will rank senior
to any future subordinated indebtedness of the guarantors. The
guarantees will be structurally subordinated to all existing and
future secured indebtedness of the guarantors, including
guarantees of our borrowings under our credit facility, to the
extent of the value of the collateral securing such indebtedness.
Investing in the notes involves risk. See Risk
factors beginning on
page S-17
of this prospectus supplement.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or determined if this prospectus supplement or the
accompanying prospectus is truthful or complete. Any
representation to the contrary is a criminal offense.
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Underwriting
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Proceeds, before
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discounts and
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expenses, to Concho
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Price to
public1
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commissions
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Resources Inc.
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Per note
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98.578%
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2.500%
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96.078%
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Total
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$
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295,734,000
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$
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7,500,000
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$
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288,234,000
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(1)
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Plus accrued interest, if any, from
September 18, 2009.
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The notes will not be listed on a securities exchange.
Currently, there is no public market for the notes.
The underwriters expect to deliver the notes on or about
September 18, 2009 in book-entry form through The
Depository Trust Company for the account of its
participants, including Clearstream Banking société
anonyme and Euroclear Bank S.A./N.V.
Joint book-running managers
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J.P.
Morgan |
BofA Merrill Lynch |
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BNP
PARIBAS |
Wells Fargo Securities |
Co-managers
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CALYON
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Scotia Capital
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SunTrust Robinson Humphrey
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Deutsche Bank Securities
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ING Wholesale
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KeyBanc Capital Markets
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Mitsubishi UFJ Securities
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Natixis Bleichroeder Inc.
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Raymond James
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September 15, 2009
Table of
contents
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Prospectus supplement
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S-ii
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S-ii
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S-iii
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S-1
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S-17
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S-41
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S-42
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S-43
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S-44
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S-48
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S-86
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S-102
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S-106
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S-110
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S-112
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S-176
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S-181
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S-186
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S-188
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S-191
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S-192
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S-192
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G-1
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F-1
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Prospectus
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About this prospectus
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1
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The company
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1
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Where you can find more information
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2
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Cautionary statement regarding forward-looking statements
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3
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Risk factors
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4
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Ratios of earnings to fixed charges and earnings to fixed
charges and preferred stock dividends
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4
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Use of proceeds
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5
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Description of debt securities
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6
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Description of capital stock
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18
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Description of warrants
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22
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Plan of distribution
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23
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Legal matters
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24
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Experts
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24
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S-i
About this
prospectus supplement
This document is in two parts. The first part is the prospectus
supplement and the documents incorporated herein, which
describes the specific terms of this offering of the notes. The
second part is the accompanying prospectus, which gives more
general information, some of which may not apply to the notes or
this offering. If the information relating to the offering
varies between the prospectus supplement and the accompanying
prospectus, you should rely on the information in this
prospectus supplement.
You should rely only on the information contained in or
incorporated by reference into this prospectus supplement, the
accompanying prospectus and any related free writing prospectus.
We have not authorized any dealer, salesman or other person to
provide you with additional or different information. If anyone
provides you with different or inconsistent information, you
should not rely on it. This prospectus supplement and the
accompanying prospectus are not an offer to sell or the
solicitation of an offer to buy any securities other than the
securities to which they relate and are not an offer to sell or
the solicitation of an offer to buy securities in any
jurisdiction to any person to whom it is unlawful to make an
offer or solicitation in that jurisdiction. You should not
assume that the information contained in this prospectus
supplement is accurate as of any date other than the date on the
front cover of this prospectus supplement, or that the
information contained in any document incorporated by reference
is accurate as of any date other than the date of the document
incorporated by reference, regardless of the time of delivery of
this prospectus supplement or any sale of a security.
Unless otherwise indicated or the context otherwise requires,
all references in this prospectus supplement to we,
our, us, the Company or
Concho are to Concho Resources Inc., a Delaware
corporation, and its subsidiaries. See Glossary of oil and
natural gas terms beginning on
page G-1
for abbreviations and definitions commonly used in the oil and
natural gas industry that are used in this prospectus supplement.
Where you can
find more information
We file annual, quarterly and current reports and other
information with the SEC (File
No. 001-33615)
pursuant to the Securities Exchange Act of 1934 (the
Exchange Act). You may read and copy any documents
that are filed at the SECs public reference room at
100 F Street, N.E., Washington, D.C. 20549. You
may also obtain copies of these documents at prescribed rates
from the public reference section of the SEC at its Washington
address. Please call the SEC at
1-800-SEC-0330
for further information.
Our filings are also available to the public through the
SECs website at
http://www.sec.gov.
The SEC allows us to incorporate by reference
information that we file with them, which means that we can
disclose important information to you by referring you to
documents previously filed with the SEC. The information
incorporated by reference is an important part of this
prospectus supplement, and the information that we later file
with the SEC will automatically update and supersede this
information. The following documents we filed with the SEC
pursuant to the Exchange Act are incorporated herein by
reference:
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our Annual Report on
Form 10-K
for the year ended December 31, 2008;
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our Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2009;
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S-ii
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our Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2009; and
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our Current Reports on
Form 8-K
and 8-K/A
filed on each of August 6, 2008, October 7, 2008,
January 28, 2009, March 4, 2009, April 9, 2009,
June 12, 2009, August 12, 2009 and September 9,
2009 (excluding any information furnished pursuant to
Item 2.02 or Item 7.01 of any such Current Report on
Form 8-K).
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These reports contain important information about us, our
financial condition and our results of operations.
All future documents filed pursuant to Sections 13(a),
13(c), 14 and 15(d) of the Exchange Act (excluding any
information furnished pursuant to Item 2.02 or
Item 7.01 on any Current Report on
Form 8-K)
before the termination of the offering of securities under this
prospectus supplement shall be deemed to be incorporated in this
prospectus supplement by reference and to be a part hereof from
the date of filing of such documents. Any statement contained
herein, or in a document incorporated or deemed to be
incorporated by reference herein, shall be deemed to be modified
or superseded for purposes of this prospectus supplement to the
extent that a statement contained herein or in any subsequently
filed document that also is or is deemed to be incorporated by
reference herein, modifies or supersedes such statement. Any
such statement so modified or superseded shall not be deemed,
except as so modified or superseded, to constitute a part of
this prospectus supplement.
You may request a copy of these filings at no cost by writing or
telephoning us at the following address and telephone number:
Concho Resources
Inc.
550 West Texas Avenue, Suite 100
Midland, Texas 79701
Attention: General Counsel
(432) 683-7443
We also maintain a website at
http://www.conchoresources.com.
However, the information on our website is not part of this
prospectus supplement.
Cautionary
statement regarding forward-looking statements
Various statements contained in or incorporated by reference
into this prospectus supplement our filings with the SEC and our
public releases, including those that express a belief,
expectation, or intention, as well as those that are not
statements of historical fact, are forward-looking statements
within the meaning of Section 27A of the Securities Act of
1933 (the Securities Act) and Section 21E of
the Exchange Act. These forward-looking statements may include
projections and estimates concerning capital expenditures, our
liquidity and capital resources, the timing and success of
specific projects, outcomes and effects of litigation, claims
and disputes, elements of our business strategy and other
statements concerning our operations, economic performance and
financial condition. Forward-looking statements are generally
accompanied by words such as estimate,
project, predict, believe,
expect, anticipate,
potential, could, may,
foresee, plan, goal or other
words that convey the uncertainty of future events or outcomes.
We have based these forward-looking statements on our current
expectations and assumptions about future events. These
statements are based on
S-iii
certain assumptions and analyses made by us in light of our
experience and our perception of historical trends, current
conditions and expected future developments as well as other
factors we believe are appropriate under the circumstances.
These forward-looking statements speak only as of the date of
this prospectus supplement; we disclaim any obligation to update
or revise these statements unless required by securities law,
and we caution you not to rely on them unduly. While our
management considers these expectations and assumptions to be
reasonable, they are inherently subject to significant business,
economic, competitive, regulatory and other risks, contingencies
and uncertainties relating to, among other matters, the risks
discussed in Risk factors, our Annual Report on
Form 10-K
for the year ended December 31, 2008, our Quarterly Reports
on
Form 10-Q
for the quarters ended March 31, 2009 and June 30, 2009 and
our subsequent SEC filings, as well as those factors summarized
below:
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our business and financial strategy;
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the estimated quantities of oil and natural gas reserves;
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our use of industry technology;
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our realized oil and natural gas prices;
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the timing and amount of the future production of our oil and
natural gas;
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the amount, nature and timing of our capital expenditures;
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the drilling of our wells;
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our competition and government regulations;
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the marketing of our oil and natural gas;
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our exploitation activities or property acquisitions;
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the costs of exploiting and developing our properties and
conducting other operations;
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general economic and business conditions;
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our cash flow and anticipated liquidity;
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hedging results;
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uncertainty regarding our future operating results;
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our plans, objectives, expectations and intentions contained in
this prospectus supplement that are not historical; and
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our ability to integrate acquisitions.
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Reserve engineering is a process of estimating underground
accumulations of oil and natural gas that cannot be measured in
an exact way. The accuracy of any reserve estimate depends on
the quality of available data, the interpretation of such data
and price and cost assumptions made by our reserve engineers. In
addition, the results of drilling, testing and production
activities may justify revisions of estimates that were made
previously. If significant, such revisions would change the
schedule of any further production and development drilling.
Accordingly, reserve estimates may differ from the quantities of
oil and natural gas that are ultimately recovered.
S-iv
Summary
This summary highlights selected information contained
elsewhere in this prospectus supplement, the accompanying
prospectus and the documents we incorporate by reference. It
does not contain all of the information you should consider
before making an investment decision. You should read the entire
prospectus supplement, the accompanying prospectus, the
documents incorporated by reference and the other documents to
which we refer for a more complete understanding of our business
and this offering. Please read the section entitled Risk
factors commencing on page S-17 of this prospectus
supplement and additional information contained in our Annual
Report on
Form 10-K
for the year ended December 31, 2008 and our Quarterly
Reports on
Form 10-Q
for the quarters ended March 31, 2009 and June 30,
2009 incorporated by reference in this prospectus supplement for
more information about important factors you should consider
before investing in the notes in this offering.
Our
business
We are an independent oil and natural gas company engaged in the
acquisition, development, exploitation and exploration of oil
and natural gas properties. Our core operating areas are located
in the Permian Basin region of Southeast New Mexico and West
Texas, the largest onshore oil and gas basin in the United
States. The Permian Basin is one of the most prolific oil and
gas producing regions in the United States and is characterized
by an extensive production history, mature infrastructure, long
reserve life, multiple producing horizons and enhanced recovery
potential. We refer to our two core operating areas as the
(i) New Mexico Permian, where we primarily target the Yeso
formation, and (ii) Texas Permian, where we primarily
target the Wolfberry, a term applied to the combined Wolfcamp
and Spraberry horizons. These core operating areas are
complemented by activities in our emerging plays, which include
the Lower Abo horizontal play in Southeast New Mexico and the
Bakken/Three Forks play in North Dakota. We intend to grow our
reserves and production through development drilling,
exploitation and exploration activities on our multi-year
project inventory and through acquisitions that meet our
strategic and financial objectives.
Approximately 67.1 percent of our oil and natural gas sales
volumes during the six month period ended June 30, 2009
were oil, with 92.7 percent of the oil being produced from
our two core operating areas in the Permian Basin. Our reserves
in our core operating areas are characterized by long-lived
predictable production, providing us with strong operating
margins and a steady source of cash flow. The cash flow from
these properties funds a significant part of our activities on
our drilling inventory and the development of our undeveloped
reserves. We have hedged approximately 62 percent and
43 percent of our anticipated oil and natural gas
production for the second half of 2009 and 2010, respectively.
Our strong hedge position, our ability to generate free cash
flow and our operating control of 93.3 percent of our PV-10
on our assets further enhances our ability to perform in
volatile economic conditions.
At December 31, 2008, our core operating areas had
estimated net proved reserves of 134.4 MMBoe, which
accounted for 97.9 percent of our total estimated net
proved reserves. At June 30, 2009, we owned interests in
3,544 gross wells in our core operating areas, of which we
operated 2,424 (gross). At June 30, 2009, we had identified
3,212 drilling locations in our core operating areas, with
proved undeveloped reserves attributed to 967 of such locations.
S-1
The following table provides a summary of selected operating
information in our core operating areas, our emerging plays and
our other oil and natural gas assets.
PV-10
includes the present value of our estimated future abandonment
and site restoration costs for proved properties net of the
present value of estimated salvage proceeds from each of these
properties. We set forth our definition of
PV-10 (a
non-GAAP financial measure) and a reconciliation of
PV-10 to the
standardized measure of discounted net cash flows under
Non-GAAP financial measures and
reconciliations.
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Quarter
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ended June 30,
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December 31, 2008
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2009
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June 30, 2009
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Average net
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Total
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daily
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proved
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production
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Identified
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Total
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Total
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reserves
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PV-10
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% Proved
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(Boe per
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drilling
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gross
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net
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Areas
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(MBoe)
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($ in millions)
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% Oil
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developed
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day)
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locations
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acreage
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acreage
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Core Operating Areas:
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New Mexico Permian
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95,055
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$
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1,242.8
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59.3%
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52.9%
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18,847
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1,654
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151,766
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70,868
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Texas Permian
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39,392
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378.0
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71.9%
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62.9%
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8,709
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1,558
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283,043
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77,784
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Emerging Plays:
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Lower Abo
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2,127
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34.4
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67.8%
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39.3%
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1,939
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152
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31,978
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27,805
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Bakken/Three Forks
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206
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3.8
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83.2%
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100.0%
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376
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150
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44,221
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11,661
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Other
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495
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4.2
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6.2%
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87.1%
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166
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8
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147,715
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68,645
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Total
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137,275
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$
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1,663.2
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62.9%
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55.7%
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30,037
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3,522
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658,723
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256,763
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Capital
expenditure budget
As a result of significant decreases in commodity prices during
the fourth quarter of 2008, we reduced our 2009 expenditures
under our $500 million capital expenditure budget in
January 2009 to approximately $300 million. Due to recent
improvements in commodity prices, in particular oil prices, we
have increased our estimated capital expenditures for 2009 to
approximately $400 million. We believe that we can
substantially fund such amount within our cash flow. We will
continue to monitor our capital expenditures, at least on a
quarterly basis, in relation to our cash flow and expect to
adjust our activity and capital spending level based on changes
in commodity prices and the cost of goods and services and other
considerations.
During the first half of 2009, we incurred approximately
$207 million of capital expenditures (excluding the effects
of asset retirement obligations and adjustments relating to the
acquisition of the Henry Properties). For the balance of 2009,
we expect to use the remaining approximately $193 million
of our planned capital expenditures to pursue increased
opportunities in our core operating areas along with targeted
opportunities in our emerging plays.
S-2
Summary of oil
and gas operations and properties
Core operating
areas
New Mexico Permian. This area represents our most
significant concentration of assets and, at December 31,
2008, estimated proved reserves of 95.1 MMBoe, or
69.2 percent of our total net proved reserves and
74.7 percent of our
PV-10.
During the second quarter of 2009, our average net daily
production from this area was approximately 18.8 MBoe per
day, representing 62.8 percent of our total production for
that time period.
Within this area we target two distinct producing areas, which
we refer to as the shelf properties and the basinal properties.
The shelf properties generally produce from the Yeso,
San Andres and Grayburg formations, with producing depths
ranging from about 900 feet to 7,500 feet. The basinal
properties generally produce from the Strawn, Atoka and Morrow
formations, with producing depths generally ranging from
7,500 feet to 15,000 feet.
During the six months ended June 30, 2009, we commenced
drilling or participation in the drilling of
90 (83.3 net) wells in this area, of which 70 (65.2
net) were completed as producers and 20 (18.1 net) were in
various stages of drilling and completion at June 30, 2009.
During the first half of 2009, we continued our
(i) development of the Blinebry interval of the Yeso
formation, the top of which is located approximately
400 feet below the top of the Paddock interval of the Yeso
formation, (ii) evaluation of drilling on ten acre spacing
in the Blinebry interval and (iii) evaluation of the use of
larger fracture stimulation procedures in the completion of
certain wells.
At June 30, 2009, we had 151,766 gross (70,868 net)
acres in this area. At June 30, 2009, on our properties in
this area, we had identified 1,654 drilling locations, with
proved undeveloped reserves attributed to 478 of such locations.
Of these drilling locations, we identified 984 locations
intended to evaluate both the Blinebry and the Paddock intervals.
Texas Permian. We acquired the majority of our
properties in this area from Henry Petroleum LP and certain
affiliated entities in 2008. At December 31, 2008, our
estimated proved reserves of 39.4 MMBoe in this area
accounted for 28.7 percent of our total net proved reserves
and 22.7 percent of our
PV-10.
During the second quarter of 2009, our average net daily
production from this area was approximately 8.7 MBoe per
day, or 29 percent of our total production for that time
period.
Our primary objective in the Texas Permian area is the Wolfberry
in the Midland Basin. Wolfberry is the term applied
to the combined production from the Spraberry and Wolfcamp
formations, which are typically encountered at depths of 7,500
to 10,500 feet. These formations are comprised of a
sequence of basinal, interbedded shales and carbonates. We also
operate and develop properties on the Central Basin Platform
targeting the Grayburg, San Andres and Clearfork
formations, which are shallower and are typically encountered at
depths of 4,500 to 7,500 feet. The reservoirs in these
formations are largely carbonates, limestones and dolomites.
At June 30, 2009, we had 283,043 gross (77,784 net)
acres in this area. In addition, at June 30, 2009, we had
identified 1,558 drilling locations, with proved undeveloped
reserves attributed to 489 of such locations.
During the six months ended June 30, 2009, we commenced
drilling or participation in the drilling of
44 (12.1 net) wells in this area, of which 33 (9.1
net) were completed as producers, two (0.4 net) were
unsuccessful and nine (2.6 net) wells were in various stages of
drilling and
S-3
completion at June 30, 2009. In addition, during the first
six months of 2009, we commenced the recompletion of two (1.1
net) wells, which were producing at June 30, 2009.
Emerging
plays
We are actively involved in drilling or participating in
drilling activities in two emerging plays, in which we had
2.3 MMBoe of proved reserves at December 31, 2008.
Lower Abo horizontal play. The Lower Abo horizontal
play is an oil play along the northwestern rim of the Delaware
Basin in Lea, Eddy and Chaves Counties, New Mexico. This play is
found at vertical depths ranging from 6,500 feet to
10,000 feet and is being exploited utilizing horizontal
drilling techniques.
At June 30, 2009, we held interests in 31,978 gross
(27,805 net) acres in this play. During the six months ended
June 30, 2009, we commenced participation in the drilling
of one (0.4 net) well in this play, which was waiting on
completion at June 30, 2009. At December 31, 2008, we
had 2.1 MMBoe of proved reserves in this play.
Bakken/Three Forks play. Our acreage in the
Bakken/Three Forks play is in the Williston Basin in North
Dakota, primarily in Mountrail and McKenzie Counties. These
Mississippian/Devonian age horizons consist of siltstones
encased within and below a highly organic oil-rich shale
package. These horizons are found at vertical depths ranging
from 9,000 feet to 11,000 feet and are being exploited
utilizing horizontal drilling techniques.
At June 30, 2009, we held interests in 44,221 gross
(11,661 net) acres in this play. During the six months ended
June 30, 2009, we commenced participation in the drilling
of twelve wells in this play with nine wells producing and three
in various stages of drilling and completion at June 30,
2009. At December 31, 2008, we had 0.2 MMBoe of proved
reserves in this play.
Our business
strategy
Our goal is to enhance value through profitably increasing
reserves, production and cash flow by executing our business
strategy as described below:
|
|
|
Exploit our multi-year project inventory. We believe
our multi-year drilling and exploitation inventory of 3,522
drilling locations on our existing properties at June 30,
2009 should allow us to grow our proved reserves and production
for the next several years.
|
|
|
Continue to focus on the Permian Basin. The Permian
Basin is one of the largest and most prolific oil and gas basins
in the United States. Members of our management have spent
significant portions of their careers in the Permian Basin. We
believe our presence and relationships in the Permian Basin are
an advantage for the acquisition and development of new
opportunities.
|
|
|
Make opportunistic acquisitions that meet our strategic and
financial objectives. We seek to acquire oil and natural gas
properties that we believe complement our existing properties in
our core areas of operation, as well as other properties that
provide opportunities for the addition of reserves and
production through a combination of exploitation, development,
high-potential exploration and control of operations.
|
|
|
Pursue the exploration and development of opportunities in
emerging plays. Our team has the necessary experience and
expertise to allow us to take advantage of the growth
|
S-4
|
|
|
opportunities in emerging plays. We apply current geologic,
drilling and completion practices to increase the predictability
and reproducibility of finding and recovering resources in
emerging plays.
|
Our
strengths
We have a number of strengths that we believe will help us
successfully execute our business strategy, including:
|
|
|
High operational success rate. As a result of our
experience and knowledge, we have been successful in our
drilling operations. For the three and one-half years ended
June 30, 2009, we drilled and completed 625 (414.5 net)
wells, including 266 (186.6 net) exploratory wells, with over a
98% rate of success.
|
|
|
Large inventory of drilling locations and recompletion
opportunities. We have identified multiple undrilled well
locations and recompletion opportunities in our core operating
areas, with proved reserves attributed to a portion of such
locations and opportunities. This large inventory provides us
with a solid operational and financial foundation from which to
pursue additional growth opportunities.
|
|
|
Favorable operating cash margins and low cost structure.
During the first half of 2009, we had favorable operating cash
margins relative to our peer group of companies, with the sale
of oil and natural gas liquids contributing over 80 percent
of our revenue. We maintain a favorable cost structure through
our concentration of assets in our core operating areas.
|
|
|
Significant economies of scale and highly focused asset
base. The geographic concentration of our current operations
in the Permian Basin allows us to establish economies of scale
with respect to drilling, production, operating and
administrative costs, in addition to further leveraging our base
of technical expertise in this region. Our high percentage of
operated properties enables us to exercise a significant level
of control over the amount and timing of expenses, capital
allocation and other aspects of exploration and development.
|
|
|
Experienced management team. Our executive officers
average over 20 years of experience in the oil and gas
industry, having led both public and private oil and natural gas
exploration and production companies, all of which have had
substantial operations in our core operating areas in the
Permian Basin.
|
|
|
Financial flexibility. We are committed to
maintaining a conservative financial position, ample liquidity
and a strong balance sheet. Our ratio of total debt to EBITDAX
has been less than 2.0x since December 31, 2007. At
June 30, 2009, we had $660 million borrowed under our
credit facility, which has a current borrowing base of
$960 million, and expect to have $582.8 million of
liquidity available following the application of the proceeds of
this offering and giving effect to the reduction to our
borrowing base as a result of the issuance of the notes. For
further discussion, see Description of other
indebtednessSenior secured credit facility.
Furthermore, we have prudently raised equity throughout industry
cycles to keep our balance sheet strong, as demonstrated most
recently with our acquisition of the Henry Petroleum entities.
We believe that our cash flow, expected proceeds from this
offering and our borrowing capacity under our credit facility
will provide us with the financial flexibility to pursue our
longer-term capital expenditure plans.
|
S-5
|
|
|
Manage risk exposure through an active hedging program.
We have hedged approximately 62 percent and 43 percent
of our anticipated oil and natural gas production for the second
half of 2009 and 2010, respectively.
|
Corporate
information
We were formed in February 2006 as a result of the combination
of Concho Equity Holdings Corp. and a portion of the oil and
natural gas properties and related assets owned by Chase Oil
Corporation and certain of its affiliates. Concho Equity
Holdings Corp., which was subsequently merged into one of our
wholly-owned subsidiaries, was formed in April 2004 and
represented the third of three Permian Basin-focused companies
that have been formed since 1997 by certain members of our
current management team (the prior two companies were sold to
large domestic independent oil and gas companies).
Concho Resources Inc. is a Delaware corporation. Our principal
executive offices are located at 550 West Texas Avenue,
Suite 100, Midland, Texas 79701. Our common stock is listed
on the New York Stock Exchange under the symbol CXO.
We maintain a web site at
http://www.conchoresources.com.
The information on our website is not part of this prospectus
supplement, and you should rely only on the information
contained in this prospectus supplement and in the documents
incorporated herein by reference when making a decision as to
whether to purchase notes in this offering.
S-6
The
offering
The following summary contains basic information about the notes
and is not intended to be complete. For a more complete
understanding of the notes, please refer to the section in this
prospectus supplement entitled Description of notes
and the section in the accompanying prospectus entitled
Description of debt securities.
|
|
|
Issuer |
|
Concho Resources Inc. |
|
The notes |
|
$300,000,000 aggregate principal amount of 8.625% Senior
Notes due 2017. |
|
Maturity |
|
October 1, 2017. |
|
Interest payment dates |
|
Interest is payable on the notes on April 1 and
October 1 of each year, beginning on April 1, 2010. |
|
Optional redemption |
|
We may, at our option, redeem all or part of the notes at any
time prior to October 1, 2013 at a make-whole price, and at
any time on or after October 1, 2013 at fixed redemption
prices, plus accrued and unpaid interest, if any, to the date of
redemption, as described under Description of
notesOptional redemption. In addition, prior to
October 1, 2012, we may, at our option, redeem up to 35% of
the notes with the proceeds of certain equity offerings. |
|
Guarantees |
|
The payment of the principal, premium and interest on the notes
will be fully and unconditionally guaranteed on a senior
unsecured basis by all of our existing subsidiaries and by
certain of our future restricted subsidiaries. In the future,
the guarantees may be released or terminated under certain
circumstances. See Description of notesSubsidiary
guarantees. |
|
Ranking |
|
The notes and the guarantees will be our and the
guarantors senior unsecured obligations and will: |
|
|
|
rank equally in right of payment with all our and
the guarantors existing and future senior indebtedness;
|
|
|
|
rank senior in right of payment to all our and the
guarantors future subordinated indebtedness;
|
|
|
|
be structurally subordinated in right of payment to
all our and the guarantors existing and future secured
indebtedness to the extent of the value of the collateral
securing such indebtedness (including all of our borrowings and
the guarantors guarantees under our credit facility); and
|
|
|
|
be structurally subordinated in right of payment to
all existing and future indebtedness and other liabilities of
any of our subsidiaries that is not also a guarantor of the
notes.
|
|
|
|
As of June 30, 2009, after giving effect to the issuance
and sale of the notes and the application of the net proceeds
therefrom as set forth |
S-7
|
|
|
|
|
under Use of proceeds to repay a portion of the
borrowings outstanding under our credit facility, we would have
had total consolidated indebtedness of $668.7 million (net
of discount), consisting of $373.0 million of secured
indebtedness outstanding under our credit facility and
$295.7 million (net of discount) of the notes offered
hereby, the subsidiary guarantors would have had total
indebtedness of $668.7 million (net of discount) consisting
of $373.0 million of secured guarantees under our credit
facility and $295.7 million (net of discount) of guarantees
of the notes offered hereby, excluding intercompany
indebtedness, and we would have been able to incur an additional
$582.8 million of secured indebtedness under our credit
facility (after giving effect to the reduction in our borrowing
base as a result of the issuance of the notes). For further
discussion, see Description of other
indebtednessSenior secured credit facility. |
|
Covenants |
|
The indenture governing the notes will contain covenants that,
among other things, limit our ability and the ability of our
restricted subsidiaries to: |
|
|
|
incur additional debt;
|
|
|
|
make certain investments or pay dividends or
distributions on our capital stock or purchase, redeem or retire
capital stock;
|
|
|
|
sell assets, including capital stock of our
restricted subsidiaries;
|
|
|
|
restrict dividends or other payments by restricted
subsidiaries;
|
|
|
|
create liens that secure debt;
|
|
|
|
enter into transactions with affiliates; and
|
|
|
|
merge or consolidate with another company.
|
|
|
|
These covenants are subject to a number of important limitations
and exceptions. See Description of notesCertain
covenants. However, most of the covenants will terminate
if both Standard & Poors Ratings Services and
Moodys Investors Service, Inc. assign the notes an
investing grade rating and no default exists with respect to the
notes. |
|
Change of control offer |
|
If we experience certain kinds of changes of control, we must
give the holders of the notes the opportunity to sell us their
notes at 101% of their principal amount, plus accrued and unpaid
interest, if any, to the repurchase date. |
|
No public market |
|
The notes are a series of securities for which there is
currently no established trading market. The underwriters have
advised us that they presently intend to make a market in the
notes. However, you should be aware that they are not obligated
to make a market in the notes and may discontinue their
market-making activities at any time without notice. As a
result, a liquid market for the notes may not be available if
you try to sell your notes. We do not intend to apply for |
S-8
|
|
|
|
|
a listing of the notes on any securities exchange or any
automated dealer quotation system. |
|
Use of proceeds |
|
We will use the net proceeds from this offering of approximately
$287.0 million to repay a portion of the outstanding borrowings
under our credit facility. See Use of proceeds. |
|
Form |
|
The notes will be represented by one or more registered global
securities registered in the name of Cede & Co., the
nominee of the depositary, The Depository Trust Company.
Beneficial interests in the notes will be shown on, and
transfers of beneficial interests will be effected through,
records maintained by The Depository Trust Company and its
participants. |
|
Conflicts of interest |
|
Affiliates of certain of the underwriters are lenders under our
credit facility and will receive a portion of the net proceeds
from this offering. For more information, see Conflicts of
interest. |
Risk
factors
Investing in the notes involves substantial risk. You should
carefully consider the risk factors set forth in the section
entitled Risk factors and the other information
contained in this prospectus supplement and the accompanying
prospectus and the documents incorporated by reference therein,
prior to making an investment in the notes. See Risk
factors beginning on page S-17.
S-9
Summary
consolidated historical financial data
Set forth below is our summary consolidated historical financial
data for the periods indicated. The historical financial data
for the periods ended December 31, 2008, 2007 and 2006 and
the balance sheet data as of December 31, 2008, 2007 and
2006 have been derived from our audited financial statements
included elsewhere in this prospectus supplement. Our historical
financial data as of June 30, 2009 and 2008 and for the six
months ended June 30, 2009 and 2008 are derived from our
unaudited financial statements included elsewhere in this
prospectus supplement and include all adjustments, consisting of
normal recurring adjustments, necessary for a fair statement of
this information. You should read the following summary
financial data in conjunction with Managements
discussion and analysis of financial condition and results of
operations and our historical financial statements and
related notes thereto included elsewhere in this prospectus
supplement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months
|
|
|
|
|
|
|
ended June 30,
|
|
|
Year ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
(in thousands)
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
166,485
|
|
|
$
|
171,226
|
|
|
$
|
390,945
|
|
|
$
|
195,596
|
|
|
$
|
131,773
|
|
Natural gas sales
|
|
|
46,849
|
|
|
|
72,868
|
|
|
|
142,844
|
|
|
|
98,737
|
|
|
|
66,517
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
213,334
|
|
|
|
244,094
|
|
|
|
533,789
|
|
|
|
294,333
|
|
|
|
198,290
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
50,583
|
|
|
|
38,874
|
|
|
|
91,234
|
|
|
|
54,267
|
|
|
|
37,822
|
|
Exploration and abandonments
|
|
|
7,419
|
|
|
|
3,464
|
|
|
|
38,468
|
|
|
|
29,098
|
|
|
|
5,612
|
|
Depreciation, depletion and amortization
|
|
|
103,150
|
|
|
|
43,294
|
|
|
|
123,912
|
|
|
|
76,779
|
|
|
|
60,722
|
|
Accretion of discount on asset retirement obligations
|
|
|
579
|
|
|
|
301
|
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
Impairments of long-lived assets
|
|
|
8,555
|
|
|
|
69
|
|
|
|
18,417
|
|
|
|
7,267
|
|
|
|
9,891
|
|
General and administrative (including non-cash stock-based
compensation of $4,113 and $3,029 for the six months ended
June 30, 2009 and 2008, respectively, and $5,223, $3,841
and $9,144 for the years ended December 31, 2008, 2007 and
2006, respectively)
|
|
|
25,918
|
|
|
|
16,266
|
|
|
|
40,776
|
|
|
|
25,177
|
|
|
|
21,721
|
|
Bad debt expense
|
|
|
|
|
|
|
1,799
|
|
|
|
2,905
|
|
|
|
|
|
|
|
|
|
Contract drilling feesstacked rigs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,269
|
|
|
|
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
(920
|
)
|
|
|
(1,336
|
)
|
|
|
821
|
|
|
|
(1,193
|
)
|
(Gain) loss on derivatives not designated as hedges
|
|
|
86,652
|
|
|
|
119,634
|
|
|
|
(249,870
|
)
|
|
|
20,274
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
282,856
|
|
|
|
222,781
|
|
|
|
65,395
|
|
|
|
218,396
|
|
|
|
134,862
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(69,522
|
)
|
|
|
21,313
|
|
|
|
468,394
|
|
|
|
75,937
|
|
|
|
63,428
|
|
|
|
|
|
|
|
S-10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months
|
|
|
|
|
|
|
ended June 30,
|
|
|
Year ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
(in thousands)
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(10,570
|
)
|
|
|
(9,500
|
)
|
|
|
(29,039
|
)
|
|
|
(36,042
|
)
|
|
|
(30,567
|
)
|
Other, net
|
|
|
(148
|
)
|
|
|
1,331
|
|
|
|
1,432
|
|
|
|
1,484
|
|
|
|
1,186
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(10,718
|
)
|
|
|
(8,169
|
)
|
|
|
(27,607
|
)
|
|
|
(34,558
|
)
|
|
|
(29,381
|
)
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(80,240
|
)
|
|
|
13,144
|
|
|
|
440,787
|
|
|
|
41,379
|
|
|
|
34,047
|
|
Income tax (expense) benefit
|
|
|
33,797
|
|
|
|
(5,199
|
)
|
|
|
(162,085
|
)
|
|
|
(16,019
|
)
|
|
|
(14,379
|
)
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(46,443
|
)
|
|
|
7,945
|
|
|
|
278,702
|
|
|
|
25,360
|
|
|
|
19,668
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
(1,244
|
)
|
Effect of induced conversion of preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
|
|
|
|
Net income (loss) applicable to common shareholders
|
|
$
|
(46,443
|
)
|
|
$
|
7,945
|
|
|
$
|
278,702
|
|
|
$
|
25,315
|
|
|
$
|
30,025
|
|
|
|
|
|
|
|
Other financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
118,232
|
|
|
$
|
162,948
|
|
|
$
|
391,397
|
|
|
$
|
169,769
|
|
|
$
|
112,181
|
|
Net cash used in investing activities
|
|
|
(162,828
|
)
|
|
|
(142,127
|
)
|
|
|
(946,050
|
)
|
|
|
(160,353
|
)
|
|
|
(596,852
|
)
|
Net cash provided by (used in) financing activities
|
|
|
29,925
|
|
|
|
(19,529
|
)
|
|
|
541,981
|
|
|
|
19,886
|
|
|
|
476,611
|
|
Capital expenditures on oil and natural gas properties
|
|
|
223,283
|
|
|
|
122,757
|
|
|
|
347,702
|
|
|
|
162,378
|
|
|
|
182,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
(in thousands)
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,081
|
|
|
$
|
31,716
|
|
|
$
|
17,752
|
|
|
$
|
30,424
|
|
|
$
|
1,122
|
|
Property and equipment, net
|
|
|
2,487,166
|
|
|
|
1,475,521
|
|
|
|
2,401,404
|
|
|
|
1,394,994
|
|
|
|
1,320,655
|
|
Total assets
|
|
|
2,764,799
|
|
|
|
1,634,233
|
|
|
|
2,815,203
|
|
|
|
1,508,229
|
|
|
|
1,390,072
|
|
Long-term debt, including current maturities
|
|
|
660,000
|
|
|
|
300,953
|
|
|
|
630,000
|
|
|
|
327,404
|
|
|
|
495,500
|
|
Stockholders equity
|
|
|
1,289,555
|
|
|
|
783,959
|
|
|
|
1,325,154
|
|
|
|
775,398
|
|
|
|
575,156
|
|
|
|
S-11
The following table includes the non-GAAP financial measure
EBITDAX. For a definition of this measure and a reconciliation
to its most directly comparable financial measure calculated and
presented in accordance with generally accepted accounting
principles (GAAP), see Non-GAAP
financial measures and reconciliations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
months
|
|
|
Six months ended
|
|
|
Year ended
|
|
|
|
ended
|
|
|
June 30,
|
|
|
December 31,
|
|
(dollars in thousands)
|
|
June 30, 2009
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Key statistics (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAXa
|
|
$
|
427,416
|
|
|
$
|
202,263
|
|
|
$
|
176,927
|
|
|
$
|
402,080
|
|
|
$
|
217,760
|
|
|
$
|
149,077
|
|
Total interest
|
|
|
30,109
|
|
|
|
10,570
|
|
|
|
9,500
|
|
|
|
29,039
|
|
|
|
36,042
|
|
|
|
30,567
|
|
Ratio of total debt to
EBITDAXa
|
|
|
1.5x
|
|
|
|
|
|
|
|
|
|
|
|
1.6x
|
|
|
|
1.5x
|
|
|
|
3.3x
|
|
Ratio of
EBITDAXa
to total interest
|
|
|
14.2x
|
|
|
|
|
|
|
|
|
|
|
|
13.8x
|
|
|
|
6.0x
|
|
|
|
4.9x
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
EBITDAX is defined as net income
(loss), plus (1) exploration and abandonments expense,
(2) depreciation, depletion and amortization expense,
(3) accretion expense, (4) impairments of long-lived
assets, (5) non-cash stock-based compensation expense,
(6) ineffective portion of cash flow hedges and unrealized
(gain) loss on derivatives not designated as hedges,
(7) interest expense, (8) bad debt expense and
(9) federal and state income taxes. See
Non-GAAP financial measures and
reconciliations.
|
Summary reserve
and production and operating data
The following estimates of net proved oil and natural gas
reserves as of December 31, 2008, 2007 and 2006 are based
on reports prepared by Cawley, Gillespie & Associates,
Inc. and Netherland, Sewell & Associates, Inc.,
independent petroleum engineers. No reserve estimate has been
filed with any federal authority or agency since January 1,
2008. In preparing their reports, Cawley, Gillespie &
Associates, Inc. and Netherland, Sewell & Associates,
Inc. evaluated properties representing 100% of our
PV-10 as of
the end of the applicable periods. All calculations of estimated
net proved reserves have been made in accordance with the rules
and regulations of the SEC. You should refer to Risk
factors, Managements discussion and analysis
of financial condition and results of operations and
Business in evaluating the material presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
86,285
|
|
|
|
53,361
|
|
|
|
44,322
|
|
Natural gas (MMcf)
|
|
|
305,948
|
|
|
|
225,837
|
|
|
|
200,818
|
|
Oil equivalent (MBoe)
|
|
|
137,275
|
|
|
|
91,000
|
|
|
|
77,791
|
|
Proved developed reserves percentage
|
|
|
55.7%
|
|
|
|
54.0%
|
|
|
|
54.2%
|
|
Standardized measure of discounted future cash flows
(in millions)
|
|
$
|
1,199.0
|
|
|
$
|
1,431.8
|
|
|
$
|
710.3
|
|
PV-10 (in
millions)a
|
|
$
|
1,663.2
|
|
|
$
|
2,138.5
|
|
|
$
|
954.0
|
|
Estimated reserve life (in
years)b
|
|
|
19.4
|
|
|
|
18.1
|
|
|
|
20.0
|
|
|
|
|
|
|
(a)
|
|
PV-10
is a non-GAAP financial measure and generally differs from
standardized measure, the most directly comparable GAAP
financial measure, because it does not include the effects of
income taxes on future net revenues. See Non-GAAP
financial measures and reconciliations. Prices used in the
computation of future net cash flows were adjusted for location
and quality by field, and were $41.00 per Bbl and $5.71 per
MMBtu for 2008, $92.50 per Bbl and $6.80 per MMBtu for 2007 and
$57.75 per Bbl and $5.64 per MMBtu for 2006.
|
S-12
|
|
|
(b)
|
|
Calculated by dividing historical
proved reserves by historical production volumes for the years
indicated. The historical production does not include the
production from assets that we acquired in 2008 and 2006 before
the time we acquired them. Pro forma for a full year of
production from the acquired assets, the estimated reserve life
in 2008 and 2006 would have been 16.8 years and
18.2 years, respectively.
|
The following table sets forth summary information concerning
our production results, average sales prices and operating costs
and expenses for the six months ended June 30, 2009 and
2008 and years ended December 31, 2008, 2007 and 2006. The
actual historical data in this table excludes production from
the (i) Chase Group Properties for periods prior to
February 27, 2006 and (ii) Henry Properties for
periods prior to August 1, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months
|
|
|
|
|
|
|
ended June 30,
|
|
|
Years ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
3,518
|
|
|
|
1,786
|
|
|
|
4,586
|
|
|
|
3,014
|
|
|
|
2,295
|
|
Natural gas (MMcf)
|
|
|
10,369
|
|
|
|
6,451
|
|
|
|
14,968
|
|
|
|
12,064
|
|
|
|
9,507
|
|
Total (MBoe)
|
|
|
5,246
|
|
|
|
2,861
|
|
|
|
7,081
|
|
|
|
5,025
|
|
|
|
3,880
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
19,436
|
|
|
|
9,813
|
|
|
|
12,530
|
|
|
|
8,258
|
|
|
|
6,288
|
|
Natural gas (Mcf)
|
|
|
57,287
|
|
|
|
35,445
|
|
|
|
40,896
|
|
|
|
33,052
|
|
|
|
26,047
|
|
Total (Boe)
|
|
|
28,984
|
|
|
|
15,721
|
|
|
|
19,347
|
|
|
|
13,767
|
|
|
|
10,630
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without hedges (Bbl)
|
|
$
|
47.32
|
|
|
$
|
107.39
|
|
|
$
|
91.92
|
|
|
$
|
68.58
|
|
|
$
|
60.47
|
|
Oil, with hedges
(Bbl)a
|
|
$
|
63.36
|
|
|
$
|
86.93
|
|
|
$
|
83.55
|
|
|
$
|
64.90
|
|
|
$
|
57.42
|
|
Natural gas, without hedges (Mcf)
|
|
$
|
4.52
|
|
|
$
|
11.33
|
|
|
$
|
9.59
|
|
|
$
|
8.08
|
|
|
$
|
6.87
|
|
Natural gas, with hedges
(Mcf)a
|
|
$
|
5.08
|
|
|
$
|
11.23
|
|
|
$
|
9.64
|
|
|
$
|
8.33
|
|
|
$
|
7.00
|
|
Total, without hedges (Boe)
|
|
$
|
40.67
|
|
|
$
|
92.59
|
|
|
$
|
79.80
|
|
|
$
|
60.54
|
|
|
$
|
52.62
|
|
Total, with hedges
(Boe)a
|
|
$
|
52.53
|
|
|
$
|
79.59
|
|
|
$
|
74.49
|
|
|
$
|
58.93
|
|
|
$
|
51.12
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs
|
|
$
|
6.24
|
|
|
$
|
5.86
|
|
|
$
|
6.31
|
|
|
$
|
5.56
|
|
|
$
|
5.40
|
|
Oil and natural gas taxes
|
|
$
|
3.40
|
|
|
$
|
7.73
|
|
|
$
|
6.57
|
|
|
$
|
5.24
|
|
|
$
|
4.35
|
|
General and administrative
|
|
$
|
4.93
|
|
|
$
|
5.69
|
|
|
$
|
5.76
|
|
|
$
|
5.01
|
|
|
$
|
5.60
|
|
Depreciation, depletion and amortization
|
|
$
|
19.66
|
|
|
$
|
15.13
|
|
|
$
|
17.50
|
|
|
$
|
15.28
|
|
|
$
|
15.65
|
|
|
|
S-13
|
|
|
(a)
|
|
Includes the effect of
(i) commodity derivatives designated as hedges and reported
in oil and natural gas sales and (ii) includes the cash
payments/receipts from commodity derivatives not designated as
hedges and reported in operating costs and expenses. The
following table reflects the amounts of cash payments/receipts
from commodity derivatives not designated as hedges that were
included in computing average prices with hedges and reconciles
to the amount in gain (loss) on derivatives not designated as
hedges as reported in the statement of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
|
Years ended December 31,
|
|
(in thousands)
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Oil and natural gas sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments from oil derivatives
|
|
$
|
|
|
|
$
|
(20,573
|
)
|
|
$
|
(30,591
|
)
|
|
$
|
(11,091
|
)
|
|
$
|
(7,000
|
)
|
Cash receipts from natural gas derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
188
|
|
|
|
1,232
|
|
Designated natural gas cash flow hedges reclassified from
accumulated other comprehensive income
|
|
|
|
|
|
|
(222
|
)
|
|
|
(696
|
)
|
|
|
1,103
|
|
|
|
|
|
|
|
|
|
|
|
Total effect on oil and natural gas sales
|
|
$
|
|
|
|
$
|
(20,795
|
)
|
|
$
|
(31,287
|
)
|
|
$
|
(9,800
|
)
|
|
$
|
(5,768
|
)
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash (payments) receipts from oil derivatives
|
|
$
|
56,412
|
|
|
$
|
(15,965
|
)
|
|
$
|
(7,780
|
)
|
|
$
|
|
|
|
$
|
|
|
Cash (payments) receipts from natural gas derivatives
|
|
|
5,832
|
|
|
|
(422
|
)
|
|
|
1,426
|
|
|
|
1,815
|
|
|
|
|
|
Cash payments from interest rate derivatives
|
|
|
(779
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
mark-to-market
gain (loss) on commodity and interest rate derivatives
|
|
|
(148,117
|
)
|
|
|
(103,247
|
)
|
|
|
256,224
|
|
|
|
(22,089
|
)
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges
|
|
$
|
(86,652
|
)
|
|
$
|
(119,634
|
)
|
|
$
|
249,870
|
|
|
$
|
(20,274
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
The presentation of average prices
with hedges is a non-GAAP measure as a result of including the
cash payments/receipts from commodity derivatives that are
presented in gain (loss) on derivatives not designated as hedges
in the statements of operations. This presentation of average
prices with hedges is a means by which to reflect the actual
cash performance of our commodity derivatives for the respective
periods and presents oil and natural gas prices with hedges in a
manner consistent with the presentation generally used by the
investment community.
|
Non-GAAP
financial measures and reconciliations
PV-10
PV-10 is
derived from the standardized measure of discounted future net
cash flows, which is the most directly comparable GAAP financial
measure.
PV-10 is a
computation of the standardized measure of discounted future net
cash flows on a pre-tax basis.
PV-10 is
equal to the standardized measure of discounted future net cash
flows at the applicable date, before deducting future income
taxes, discounted at 10%. We believe that the presentation of
the PV-10 is
relevant and useful to investors because it presents the
discounted future net cash flows attributable to our estimated
net proved reserves prior to taking into account future
corporate income taxes, and it is a useful measure for
evaluating the relative monetary significance of our oil and
natural gas properties. Further, investors may utilize the
measure as a basis for comparison of the relative size and value
of our reserves to other companies. We use this measure when
assessing the potential return on investment related to our oil
and natural gas properties.
PV-10,
however, is not a substitute for the standardized measure of
discounted future net cash flows. Our
PV-10
measure and the standardized measure of discounted future net
cash flows do not purport to present the fair value of our oil
and natural gas reserves.
The following table provides a reconciliation of the
standardized measure of future net cash flows to
PV-10 at
December 31, 2008, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
(in millions)
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
PV-10
|
|
$
|
1,663.2
|
|
|
$
|
2,138.5
|
|
|
$
|
954.0
|
|
Present value of future income tax discounted at 10%
|
|
|
(464.2
|
)
|
|
|
(706.7
|
)
|
|
|
(243.7
|
)
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
1,199.0
|
|
|
$
|
1,431.8
|
|
|
$
|
710.3
|
|
|
|
S-14
EBITDAX
We define EBITDAX as net income (loss), plus
(1) exploration and abandonments expense,
(2) depreciation, depletion and amortization expense,
(3) accretion expense, (4) impairments of long-lived
assets, (5) non-cash stock-based compensation expense,
(6) ineffective portion of cash flow hedges and unrealized
(gain) loss on derivatives not designated as hedges,
(7) interest expense, (8) bad debt expense and
(9) federal and state income taxes. EBITDAX is not a
measure of net income or cash flow as determined by GAAP.
Our EBITDAX measure provides additional information which may be
used to better understand our operations, and it is also a
material component of one of the financial covenants under our
credit facility. EBITDAX is one of several metrics that we use
as a supplemental financial measurement in the evaluation of our
business and should not be considered as an alternative to, or
more meaningful than, net income, as an indicator of our
operating performance. Certain items excluded from EBITDAX are
significant components in understanding and assessing a
companys financial performance, such as a companys
cost of capital and tax structure, as well as the historic cost
of depreciable assets, none of which are components of EBITDAX.
EBITDAX as used by us may not be comparable to similarly titled
measures reported by other companies. We believe that EBITDAX is
a widely followed measure of operating performance and is one of
many metrics used by our management team and by other users of
our consolidated financial statements, including by lenders
pursuant to a covenant in our credit facility. For example,
EBITDAX can be used to assess our operating performance and
return on capital in comparison to other independent exploration
and production companies without regard to financial or capital
structure, and to assess the financial performance of our assets
and our company without regard to capital structure or
historical cost basis. Further, under our credit facility, an
event of default could arise if we were not able to satisfy and
remain in compliance with specified financial ratios, including
the maintenance of a quarterly ratio of total debt to
consolidated EBITDAX of no greater than 4.0 to 1.0.
Non-compliance with this ratio could trigger an event of default
under our credit facility.
S-15
The following table provides a reconciliation of net income
(loss) to EBITDAX for the six months ended June 30, 2009
and 2008 and for the years ended December 31, 2008, 2007
and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months
|
|
|
|
|
|
|
ended June 30,
|
|
|
Years ended December 31,
|
|
(in thousands)
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Net income (loss)
|
|
$
|
(46,443
|
)
|
|
$
|
7,945
|
|
|
$
|
278,702
|
|
|
$
|
25,360
|
|
|
$
|
19,668
|
|
Exploration and abandonments
|
|
|
7,419
|
|
|
|
3,464
|
|
|
|
38,468
|
|
|
|
29,098
|
|
|
|
5,612
|
|
Depreciation, depletion and amortization
|
|
|
103,150
|
|
|
|
43,294
|
|
|
|
123,912
|
|
|
|
76,779
|
|
|
|
60,722
|
|
Accretion of discount on asset retirement obligations
|
|
|
579
|
|
|
|
301
|
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
Impairment of long-lived assets
|
|
|
8,555
|
|
|
|
69
|
|
|
|
18,417
|
|
|
|
7,267
|
|
|
|
9,891
|
|
Non-cash stock-based compensation
|
|
|
4,113
|
|
|
|
3,029
|
|
|
|
5,223
|
|
|
|
3,841
|
|
|
|
9,144
|
|
Bad debt expense
|
|
|
|
|
|
|
1,799
|
|
|
|
2,905
|
|
|
|
|
|
|
|
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
(920
|
)
|
|
|
(1,336
|
)
|
|
|
821
|
|
|
|
(1,193
|
)
|
Unrealized (gain) loss on derivatives not designated as hedges
|
|
|
148,117
|
|
|
|
103,247
|
|
|
|
(256,224
|
)
|
|
|
22,089
|
|
|
|
|
|
Interest expense
|
|
|
10,570
|
|
|
|
9,500
|
|
|
|
29,039
|
|
|
|
36,042
|
|
|
|
30,567
|
|
Income tax expense (benefit)
|
|
|
(33,797
|
)
|
|
|
5,199
|
|
|
|
162,085
|
|
|
|
16,019
|
|
|
|
14,379
|
|
|
|
|
|
|
|
EBITDAX
|
|
$
|
202,263
|
|
|
$
|
176,927
|
|
|
$
|
402,080
|
|
|
$
|
217,760
|
|
|
$
|
149,077
|
|
|
|
S-16
Risk
factors
An investment in the notes involves risk. In addition to the
risks described below, you should also carefully read all of the
other information included in this prospectus supplement, the
accompanying prospectus and the documents we have incorporated
by reference into this prospectus supplement in evaluating an
investment in the notes. If any of the described risks actually
were to occur, our business, financial condition or results of
operations could be affected materially and adversely. In that
case, our ability to fulfill our obligations under the notes
could be materially affected and you could lose all or part of
your investment.
The risks described below are not the only ones facing our
company. Additional risks not presently known to us or that we
currently deem immaterial individually or in the aggregate may
also impair our business operations.
This prospectus supplement and documents incorporated by
reference also contain forward-looking statements that involve
risks and uncertainties, some of which are described in the
documents incorporated by reference in this prospectus
supplement and the accompanying prospectus. Our actual results
could differ materially from those anticipated in these
forward-looking statements as a result of various factors,
including the risks and uncertainties faced by us described
below or incorporated by reference in this prospectus supplement
and the accompanying prospectus.
Risks related to
our business
Oil and
natural gas prices are volatile. A decline in oil and natural
gas prices could adversely affect our financial position,
financial results, cash flow, access to capital and ability to
grow.
Our future financial condition, revenues, results of operations,
rate of growth and the carrying value of our oil and gas
properties depend primarily upon the prices we receive for our
oil and natural gas production and the prices prevailing from
time to time for oil and natural gas. Oil and natural gas prices
historically have been volatile, and are likely to continue to
be volatile in the future, especially given current geopolitical
conditions. This price volatility also affects the amount of our
cash flow we have available for capital expenditures and our
ability to borrow money or raise additional capital. The prices
for oil and natural gas are subject to a variety of factors
beyond our control, including:
|
|
|
the level of consumer demand for oil and natural gas;
|
|
|
the domestic and foreign supply of oil and natural gas;
|
|
|
commodity processing, gathering and transportation availability,
and the availability of refining capacity;
|
|
|
the price and level of imports of foreign oil and natural gas;
|
|
|
the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
|
|
|
domestic and foreign governmental regulations and taxes;
|
|
|
the price and availability of alternative fuel sources;
|
|
|
weather conditions;
|
S-17
|
|
|
political conditions or hostilities in oil and gas producing
regions, including the Middle East, Africa and South America;
|
|
|
technological advances affecting energy consumption; and
|
|
|
worldwide economic conditions.
|
Furthermore, oil and natural gas prices were particularly
volatile in the first six months of 2009. For example, the NYMEX
oil prices during the six months ended June 30, 2009 ranged
from a high of $72.68 to a low of $33.98 per Bbl, and the NYMEX
natural gas prices during that time ranged from a high of $6.07
to a low of $3.25 per MMBtu. During the period from July 1,
2009 to September 8, 2009, oil prices ranged from a high of
$74.37 to a low of $59.52 per Bbl, and natural gas prices ranged
from a high of $4.04 to a low of $2.51 per MMBtu.
Further declines in oil and natural gas prices would not only
reduce our revenue, but could further reduce the amount of oil
and natural gas that we can produce economically and, as a
result, could have a material adverse effect on our financial
condition, results of operations and reserves. If the oil and
gas industry continues to experience significant price declines,
we may, among other things, be unable to maintain or increase
our borrowing capacity, repay current or future indebtedness
(including payments of interest and principal on the notes) or
obtain additional capital on attractive terms, all of which can
adversely affect the value of our securities, including the
notes.
Drilling for
and producing oil and natural gas are high-risk activities with
many uncertainties that could cause our expenses to increase or
our cash flows and production volumes to decrease.
Our future financial condition and results of operations will
depend on the success of our exploitation, exploration,
development and production activities. Our oil and natural gas
exploration and production activities are subject to numerous
risks, including the risk that drilling will not result in
commercially viable oil or natural gas production. Our decisions
to purchase, explore, develop or otherwise exploit prospects or
properties will depend in part on the evaluation of data
obtained through geophysical and geological analyses, production
data and engineering studies, the results of which are often
inconclusive or subject to varying interpretations. Our cost of
drilling, completing, equipping and operating wells is often
uncertain before drilling commences. Overruns in budgeted
expenditures are common risks that can make a particular project
uneconomical or less economic than forecasted. Further, many
factors may curtail, delay or cancel drilling, including the
following:
|
|
|
delays imposed by or resulting from compliance with regulatory
and contractual requirements;
|
|
|
pressure or irregularities in geological formations;
|
|
|
shortages of or delays in obtaining equipment and qualified
personnel;
|
|
|
equipment failures or accidents;
|
|
|
adverse weather conditions;
|
|
|
reductions in oil and natural gas prices;
|
|
|
surface access restrictions;
|
|
|
loss of title or other title related issues;
|
S-18
|
|
|
oil, natural gas liquids or natural gas gathering,
transportation and processing availability restrictions or
limitations; and
|
|
|
limitations in the market for oil and natural gas.
|
Estimates of
proved reserves and future net cash flows are not precise. The
actual quantities of our proved reserves and our future net cash
flows may prove to be lower than estimated.
Numerous uncertainties exist in estimating quantities of proved
reserves and future net cash flows therefrom. Our estimates of
proved reserves and related future net cash flows are based on
various assumptions, which may ultimately prove to be inaccurate.
Petroleum engineering is a subjective process of estimating
accumulations of oil
and/or
natural gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and natural gas
reserves and of future net cash flows depend upon a number of
variable factors and assumptions, including the following:
|
|
|
historical production from the area compared with production
from other producing areas;
|
|
|
the quality, quantity and interpretation of available relevant
data;
|
|
|
the assumed effects of regulations by governmental agencies;
|
|
|
the assumed effects of regulations by governmental agencies;
|
|
|
assumptions concerning future commodity prices; and
|
|
|
assumptions concerning future operating costs; severance, ad
valorem and excise taxes; development costs; and workover and
remedial costs.
|
Because all reserve estimates are to some degree subjective,
each of the following items, or other items not identified
below, may differ materially from those assumed in estimating
reserves:
|
|
|
the quantities of oil and natural gas that are ultimately
recovered;
|
|
|
the production and operating costs incurred;
|
|
|
the amount and timing of future development
expenditures; and
|
|
|
future commodity prices.
|
Furthermore, different reserve engineers may make different
estimates of reserves and cash flows based on the same data. Our
actual production, revenues and expenditures with respect to
reserves will likely be different from estimates and the
differences may be material.
As required by the rules and regulations of the SEC, the
estimated discounted future net cash flows from proved reserves
are based on prices and costs as of the date of the estimate,
while actual future prices and costs may be materially higher or
lower. For example, the estimated discounted future net cash
flows from our proved reserves at December 31, 2008 were
calculated using the West Texas Intermediate posted oil price of
$41.00 per Bbl and the NYMEX
S-19
natural gas price of $5.71 per MMBtu, adjusted for location and
quality by field, while the actual future net cash flows also
will be affected by other factors, including:
|
|
|
the amount and timing of actual production;
|
|
|
levels of future capital spending;
|
|
|
increases or decreases in the supply of or demand for oil and
gas; and
|
|
|
changes in governmental regulations or taxation.
|
Standardized Measure is a reporting convention that provides a
common basis for comparing oil and gas companies subject to the
rules and regulations of the SEC. It requires the use of
commodity prices, as well as operating and development costs,
prevailing as of the date of computation. Consequently, it may
not reflect the prices ordinarily received or that will be
received for oil and natural gas production because of seasonal
price fluctuations or other varying market conditions, nor may
it reflect the actual costs that will be required to produce or
develop the oil and gas properties. Accordingly, estimates
included herein of future net cash flows may be materially
different from the future net cash flows that are ultimately
received. In addition, the ten percent discount factor, which is
required by the rules and regulations of the SEC to be used in
calculating discounted future net cash flows for reporting
purposes, may not be the most appropriate discount factor based
on interest rates in effect from time to time and risks
associated with our company or the oil and gas industry in
general. Therefore, the estimates of discounted future net cash
flows or Standardized Measure included or incorporated by
reference in this prospectus supplement should not be construed
as accurate estimates of the current market value of our proved
reserves. If oil prices were $1.00 per Bbl lower than the price
we used, our
PV-10 at
December 31, 2008 would have decreased from
$1,663 million to $1,622 million. If natural gas
prices were $0.10 per Mcf lower than the price we used, our
PV-10 at
December 31, 2008 would have decreased from
$1,663 million to $1,646 million. Any adjustments to
the estimates of proved reserves or decreases in the price of
oil or natural gas may decrease the value of our common stock
and the notes.
Our business
requires substantial capital expenditures. We may be unable to
obtain needed capital or financing on satisfactory terms or at
all, which could lead to a decline in our oil and natural gas
reserves.
The oil and gas industry is capital intensive. We make and
expect to continue to make substantial capital expenditures for
the acquisition, exploration and development of oil and natural
gas reserves. At June 30, 2009, total debt outstanding
under our credit facility was $660 million, and
$300 million was available to be borrowed. Following the
application of the proceeds of this offering in the manner
described in Use of proceeds and giving effect to
the reduction to our borrowing base as a result of the issuance
of the notes, we expect to have approximately
$582.8 million of availability under our credit facility
and a revised borrowing base of $955.9 million. For further
discussion, see Description of other
indebtednessSenior secured credit facility.
Expenditures for exploration and development of oil and gas
properties are the primary use of our capital resources. We
invested approximately $202.7 million in exploration and
development activities, excluding asset retirement obligations,
during the six months ended June 30, 2009 on our properties
under our capital budget and anticipate we could invest up to an
additional approximately $193 million in 2009 for exploration
and development activities, dependent on our cash flow.
S-20
We intend to finance our future capital expenditures primarily
through cash flow from operations and through borrowings under
our credit facility; however, our financing needs may require us
to alter or increase our capitalization substantially through
the issuance of debt or equity securities. The issuance of
additional equity securities could have a dilutive effect on the
value of our common stock. Additional borrowings under our
credit facility or the issuance of additional debt will require
that a greater portion of our cash flow from operations be used
for the payment of interest and principal on our debt, thereby
reducing our ability to use cash flow to fund working capital,
capital expenditures and acquisitions. In addition, our credit
facility imposes, and the indenture governing the notes will
impose, certain limitations on our ability to incur additional
indebtedness, subject to certain exceptions. If we desire to
issue additional debt securities other than as expressly
permitted under our credit facility, we will be required to seek
the consent of the lenders in accordance with the requirements
of the facility, which consent may be withheld by the lenders
under our credit facility in their discretion. If we incur
certain additional indebtedness, including the notes, our
borrowing base under our credit facility will be reduced. For
further discussion, see Description of other
indebtednessSenior secured credit facility.
Additional financing also may not be available on acceptable
terms or at all. In the event additional capital resources are
unavailable, we may curtail drilling, development and other
activities or be forced to sell some of our assets on an
untimely or unfavorable basis.
Our cash flow from operations and access to capital are subject
to a number of variables, including:
|
|
|
our proved reserves;
|
|
|
the level of oil and natural gas we are able to produce from
existing wells;
|
|
|
the prices at which our oil and natural gas are sold; and
|
|
|
our ability to acquire, locate and produce new reserves.
|
If our revenues or the borrowing base under our credit facility
decrease as a result of lower oil or natural gas prices,
operating difficulties, declines in reserves, lending
requirements or regulations, or for any other reason, we may
have limited ability to obtain the capital necessary to sustain
our operations at current levels. As a result, we may require
additional capital to fund our operations, and we may not be
able to obtain debt or equity financing to satisfy our capital
requirements. If cash generated from operations or cash
available under our credit facility is not sufficient to meet
our capital requirements, the failure to obtain additional
financing could result in a curtailment of our operations
relating to the development of our prospects, which in turn
could lead to a decline in our oil and natural gas reserves, and
could adversely affect our production, revenues and results of
operations.
We may not be
able to obtain funding at all, or obtain funding on acceptable
terms, to meet our future capital needs because of the
deterioration of the credit and capital markets.
Global financial markets and economic conditions have been, and
will likely continue to be, disrupted and volatile. The debt and
equity capital markets have become uncertain. These issues,
along with significant write-offs in the financial services
sector, the re-pricing of credit risk and the current weak
economic conditions have made, and will likely continue to make,
it difficult to obtain funding.
In particular, the cost of raising money in the debt and equity
capital markets has increased substantially while the
availability of funds from those markets has diminished
significantly. Also, as a result of concern about the stability
of financial markets generally and the solvency of
S-21
counterparties specifically, the cost of obtaining money from
the credit markets has increased as many lenders and
institutional investors have increased interest rates, enacted
tighter lending standards and reduced and, in some cases, ceased
to provide funding to borrowers.
In addition, our ability to obtain capital under our credit
facility may be impaired because of the recent downturn in the
financial market, including the issues surrounding the solvency
of certain institutional lenders and the recent failure of
several banks. Specifically, we may be unable to obtain adequate
funding under our credit facility because:
|
|
|
our lending counterparties may be unwilling or unable to meet
their funding obligations;
|
|
|
the borrowing base under our credit facility is redetermined at
least twice a year and may decrease due to a decrease in oil or
natural gas prices, operating difficulties, declines in
reserves, lending requirements or regulations, or for other
reasons; or
|
|
|
if any lender is unable or unwilling to fund their respective
portion of any advance under our credit facility, then the other
lenders thereunder are not required to provide additional
funding to make up the portion of the advance that the
defaulting lender refused to fund.
|
Due to these factors, we cannot be certain that funding will be
available if needed and to the extent required, on acceptable
terms. If funding is not available when needed, or is available
only on unfavorable terms, we may be unable to implement our
development plan, enhance our existing business, complete
acquisitions or otherwise take advantage of business
opportunities or respond to competitive pressures, any of which
could have a material adverse effect on our production, revenues
and results of operations.
Our lenders
can limit our borrowing capabilities, which may materially
impact our operations.
At June 30, 2009, we had approximately $660 million of
outstanding debt under our credit facility, and our borrowing
base was $960 million. Following the application of the
proceeds of this offering in the manner described in Use
of proceeds and giving effect to the reduction to our
borrowing base as a result of the issuance of the notes, we
expect to have approximately $582.8 million of availability
under our credit facility and a revised borrowing base of
$955.9 million. The borrowing base limitation under our
credit facility is semi-annually redetermined based upon a
number of factors, including commodity prices and reserve
levels. In addition to such semi-annual redeterminations, our
lenders may request one additional redetermination during any
twelve-month period. Upon a redetermination, our borrowing base
could be substantially reduced, and in the event the amount
outstanding under our credit facility at any time exceeds the
borrowing base at such time, we may be required to repay a
portion of our outstanding borrowings. If we incur certain
additional indebtedness, including the notes, our borrowing base
under our credit facility will be reduced. For further
discussion, see Description of other
indebtedness Senior secured credit facility.
We utilize cash flow from operations, bank borrowings and equity
financings to fund our acquisition, exploration and development
activities. A reduction in our borrowing base could limit our
activities.
In addition, we may significantly alter our capitalization in
order to make future acquisitions or develop our properties.
These changes in capitalization may significantly increase our
level of debt. If we incur additional debt for these or other
purposes, the related risks that we now face could intensify. A
higher level of debt also increases the risk that we may default
on our debt obligations. Our ability to meet our debt
obligations (including our ability to pay interest and principal
on the notes) and to reduce our level of debt depends on our
future performance
S-22
which is affected by general economic conditions and financial,
business and other factors, many of which are beyond our control.
Our producing
properties are located in the Permian Basin of Southeast New
Mexico and West Texas, making us vulnerable to risks associated
with operating in one major geographic area. In addition, we
have a large amount of proved reserves attributable to a small
number of producing horizons within this area.
Our producing properties in our core operating areas are
geographically concentrated in the Permian Basin of Southeast
New Mexico and West Texas. At December 31, 2008,
97.4 percent of our
PV-10 was
attributable to properties located in our core operating areas.
As a result of this concentration, we may be disproportionately
exposed to the impact of regional supply and demand factors,
delays or interruptions of production from wells in this area
caused by governmental regulation, processing or transportation
capacity constraints, market limitations, or interruption of the
processing or transportation of oil, natural gas or natural gas
liquids.
In addition to the geographic concentration of our producing
properties described above, at December 31, 2008,
approximately (i) 52.0 percent of our proved reserves
were attributable to the Yeso formation, which includes both the
Paddock and Blinebry intervals, underlying our oil and gas
properties located in Southeast New Mexico; and
(ii) 15.1 percent of our proved reserves were
attributable to the Wolfberry play in West Texas. This
concentration of assets within a small number of producing
horizons exposes us to additional risks, such as changes in
field-wide rules and regulations that could cause us to
permanently or temporarily shut-in all of our wells within a
field.
Future price
declines could result in a reduction in the carrying value of
our proved oil and gas properties, which could adversely affect
our results of operations.
Declines in commodity prices may result in having to make
substantial downward adjustments to our estimated proved
reserves. If this occurs, or if our estimates of production or
economic factors change, accounting rules may require us to
write-down, as a noncash charge to earnings, the carrying value
of our oil and gas properties for impairments. We are required
to perform impairment tests on proved assets whenever events or
changes in circumstances warrant a review of our proved oil and
gas properties. To the extent such tests indicate a reduction of
the estimated useful life or estimated future cash flows of our
oil and gas properties, the carrying value may not be
recoverable and therefore require a write-down. We may incur
impairment charges in the future, which could materially
adversely affect our results of operations in the period
incurred.
Part of our
strategy involves exploratory drilling, including drilling in
new or emerging plays. As a result, our drilling results in
these areas are uncertain, and the value of our undeveloped
acreage will decline if drilling results are
unsuccessful.
The results of our exploratory drilling in new or emerging areas
are more uncertain than drilling results in areas that are
developed and have established production. Since new or emerging
plays and new formations have limited or no production history,
we are unable to use past drilling results in those areas to
help predict our future drilling results. As a result, our cost
of drilling, completing and operating wells in these areas may
be higher than initially expected, and the value of our
undeveloped acreage will decline if drilling results are
unsuccessful.
S-23
Our commodity
price risk management program may cause us to forego additional
future profits or result in our making cash payments to our
counterparties.
To reduce our exposure to changes in the prices of oil and
natural gas, we have entered into and may in the future enter
into additional commodity price risk management arrangements for
a portion of our oil and natural gas production. The agreements
that we have entered into generally have the effect of providing
us with a fixed price for a portion of our expected future oil
and natural gas production over a fixed period of time.
Commodity price risk management arrangements expose us to the
risk of financial loss and may limit our ability to benefit from
increases in oil and natural gas prices in some circumstances,
including the following:
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the counterparty to a commodity price risk management contract
may default on its contractual obligations to us;
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there may be a change in the expected differential between the
underlying price in a commodity price risk management agreement
and actual prices received; or
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market prices may exceed the prices which we are contracted to
receive, resulting in our need to make significant cash payments
to our counterparties.
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Our commodity price risk management activities could have the
effect of reducing our revenues, net income and the value of our
common stock. At June 30, 2009, the net unrealized asset on
our commodity price risk management contracts was
$24.4 million. An average increase in the commodity price
of $10.00 per barrel of oil and $1.00 per Mcf for natural gas
from the commodity prices at June 30, 2009 would have
resulted in a net unrealized liability on our commodity price
risk management contracts, as reflected on our consolidated
balance sheet at June 30, 2009, of approximately
$81.0 million. We may continue to incur significant
unrealized gains or losses in the future from our commodity
price risk management activities to the extent market prices
increase or decrease and our derivatives contracts remain in
place.
We have
entered into interest rate derivative instruments that may
subject us to loss of income.
We have entered into derivative instruments designed to limit
the interest rate risk under our current credit facility or any
credit facilities we may enter into in the future. These
derivative instruments can involve the exchange of a portion of
our floating rate interest obligations for fixed rate interest
obligations or a cap on our exposure to floating interest rates
to reduce our exposure to the volatility of interest rates.
While we may enter into instruments limiting our exposure to
higher market interest rates, we cannot assure you that any
interest rate derivative instruments we implement will be
effective. Furthermore, even if effective these instruments may
not offer complete protection from the risk of higher interest
rates.
All interest rate derivative instruments involve certain
additional risks, such as:
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the counterparty may default on its contractual obligations to
us;
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there may be issues with regard to the legal enforceability of
such instruments;
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the early repayment of our interest rate derivative instruments
could lead to prepayment penalties; or
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unanticipated and significant changes in interest rates may
cause a significant loss of basis in the instrument and a change
in current period expense.
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S-24
If we enter
into derivative instruments that require us to post cash
collateral, our cash otherwise available for use in our
operations would be reduced, which could limit our ability to
make future capital expenditures.
The use of derivatives may, in some cases, require the posting
of cash collateral with counterparties. If we enter into
derivative instruments that require cash collateral and
commodity prices or interest rates change in a manner adverse to
us, our cash otherwise available for use in our operations would
be reduced, which could limit our ability to make future capital
expenditures and make payments on our indebtedness, including
the notes. Future collateral requirements will depend on
arrangements with our counterparties and highly volatile oil and
natural gas prices and interest rates.
Nonperformance
by the counterparties to our derivative instruments and
commodity purchase agreements could adversely affect our
financial condition and results of operations.
We routinely enter into derivative instruments with a number of
counterparties to reduce our exposure to changes in oil and
natural gas prices and interest rates. Recently, a number of
financial institutions similar to those that serve as
counterparties to our derivative instruments have been adversely
affected by the global credit crisis. If a counterparty to one
of these derivative instruments cannot or will not perform under
the contract, we will not realize the benefit of the derivative,
which could adversely affect our financial condition and results
of operations.
Additionally, substantially all of our accounts receivable
result from oil and natural gas sales to third parties in the
energy industry. Recent market conditions have resulted in
downgrades to credit ratings of energy industry merchants and
financial institutions, affecting the liquidity of several of
our purchasers and counterparties. We extend credit to our
purchasers based on each partys creditworthiness, but we
generally have not required our purchasers to provide collateral
support for their obligations to us and therefore have no
assurances that our counterparties will have the ability to pay
us. If a purchaser of our oil and natural gas production fails
to meet its obligations under our commodity purchase agreement,
our financial condition and results of operations could be
adversely affected.
Our identified
inventory of drilling locations are scheduled out over several
years, making them susceptible to uncertainties that could
materially alter the occurrence or timing of their
drilling.
We have identified and scheduled the drilling of certain of our
drilling locations as an estimation of our future multi-year
development activities on our existing acreage. At June 30,
2009, we had identified 3,522 drilling locations with proved
undeveloped reserves attributable to 1,005 of such locations.
These identified locations represent a significant part of our
growth strategy. Our ability to drill and develop these
locations depends on a number of uncertainties, including
(i) our ability to timely drill wells on lands subject to
complex development terms and circumstances; (ii) the
availability of capital, equipment, services and personnel;
(iii) seasonal conditions; (iv) regulatory and third
party approvals; (v) oil and natural gas prices, and
(vi) drilling and recompletion costs and results. Because
of these uncertainties, we may never drill the numerous
potential locations we have identified or produce oil or natural
gas from these or any other potential locations. As such, our
actual development activities may materially differ from those
presently identified, which could adversely affect our
production, revenues and results of operations.
S-25
Approximately
44.3 percent of our total estimated net proved reserves at
December 31, 2008, were undeveloped, and those reserves may
not ultimately be developed.
At December 31, 2008, approximately 44.3 percent of
our total estimated net proved reserves were undeveloped.
Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling. Our reserve data assumes
that we can and will make these expenditures and conduct these
operations successfully. These assumptions, however, may not
prove correct. If we choose not to spend the capital to develop
these reserves, or if we are not otherwise able to successfully
develop these reserves, we will be required to write-off these
reserves. Any such write-offs of our reserves could reduce our
ability to borrow money and could reduce the value of our
securities, including the notes.
Because we do
not control the development of certain of the properties in
which we own interests, but do not operate, we may not be able
to achieve any production from these properties in a timely
manner.
At December 31, 2008, approximately 6.7 percent of our
PV-10 was
attributable to properties for which we were not the operator.
As a result, the success and timing of drilling and development
activities on such nonoperated properties depend upon a number
of factors, including:
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the nature and timing of drilling and operational activities;
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the timing and amount of capital expenditures;
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the operators expertise and financial resources;
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the approval of other participants in such properties; and
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the selection of suitable technology.
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If drilling and development activities are not conducted on
these properties or are not conducted on a timely basis, we may
be unable to increase our production or offset normal production
declines or we will be required to write-off the reserves
attributable thereto, which may adversely affect our production,
revenues and results of operations. Any such write-offs of our
reserves could reduce our ability to borrow money and could
reduce the value of our securities, including the notes.
Unless we
replace our oil and natural gas reserves, our reserves and
production will decline, which would adversely affect our cash
flow and ability to pay interest and principal on our
indebtedness, including the notes, our ability to raise capital
and the value of our securities.
Unless we conduct successful development, exploitation and
exploration activities or acquire properties containing proved
reserves, our proved reserves will decline as those reserves are
produced. Producing oil and natural gas reservoirs generally are
characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Our future oil
and natural gas reserves and production, and therefore our cash
flow and results of operations, are highly dependent on our
success in efficiently developing and exploiting our current
reserves and economically finding or acquiring additional
recoverable reserves. The value of our securities, including the
notes, and our ability to raise capital and ability to pay
interest and principal on our indebtedness, including the notes,
will be adversely impacted if we are not able to replace our
reserves that are depleted by production or otherwise lost. We
may
S-26
not be able to develop, exploit, find or acquire sufficient
additional reserves to replace our current and future production.
We may be
unable to make attractive acquisitions or successfully integrate
acquired companies, and any inability to do so may disrupt our
business and hinder our ability to grow.
One aspect of our business strategy calls for acquisitions of
businesses that complement or expand our current business. We
may not be able to identify attractive acquisition
opportunities. Even if we do identify attractive candidates, we
may not be able to complete the acquisition of them or do so on
commercially acceptable terms.
In addition, our credit facility imposes, and the indenture
governing the notes will impose, certain direct limitations on
our ability to enter into mergers or combination transactions
involving our company. Our credit facility also limits, and the
indenture governing the notes will limit, our ability to incur
certain indebtedness, which could indirectly limit our ability
to engage in acquisitions of businesses. If we desire to engage
in an acquisition that is otherwise prohibited by our credit
facility, we will be required to seek the consent of our lenders
in accordance with the requirements of the facility, which
consent may be withheld by the lenders under our credit facility
in their discretion. Furthermore, given the current situation in
the credit markets, many lenders are reluctant to provide
consents in any circumstances, including to allow accretive
transactions.
If we acquire another business, we could have difficulty
integrating its operations, systems, management and other
personnel and technology with our own. These difficulties could
disrupt our ongoing business, distract our management and
employees, increase our expenses and adversely affect our
results of operations. In addition, we may incur additional debt
or issue additional equity to pay for any future acquisitions,
subject to the limitations described above.
The
acquisition of the Henry Entities could expose us to potentially
significant liabilities.
In connection with the acquisition of the Henry Entities, we
purchased all of the sellers interests in the Henry
Entities, rather than individual assets; therefore, the Henry
Entities retained their liabilities, subject to certain
exclusions and limitations contained in the purchase agreement,
including certain unknown and contingent liabilities. We
performed limited due diligence in connection with the
acquisition of the Henry Entities and attempted to verify the
representations of the sellers and of the former management of
the Henry Entities, but there may be threatened, contemplated,
asserted or other claims against the Henry Entities related to
environmental, title, regulatory, tax, contract, litigation or
other matters of which we are unaware, which could materially
adversely affect our production, revenues and results of
operations. In addition, although the sellers agreed to
indemnify us on a limited basis against certain liabilities,
these indemnification obligations will expire over time and
expose us to potential unindemnified liabilities, which could
materially adversely affect our production, revenues and results
of operations.
Properties
acquired may prove to be worth less than what we paid because of
uncertainties in evaluating recoverable reserves and potential
liabilities.
We obtained the majority of our current reserve base through
acquisitions of producing properties and undeveloped acreage,
including those owned by the Henry Entities. We expect that
acquisitions will continue to contribute to our future growth.
Successful acquisitions of oil and gas properties require an
assessment of a number of factors, including estimates of
recoverable reserves, the timing of recovering reserves,
exploration potential, future oil and
S-27
natural gas prices, operating costs and potential environmental
and other liabilities. Such assessments are inexact and we
cannot make these assessments with a high degree of accuracy. In
connection with our assessments, we perform a review of the
acquired properties. However, such a review will not reveal all
existing or potential problems. In addition, our review may not
permit us to become sufficiently familiar with the properties to
fully assess their deficiencies and capabilities. We do not
inspect every well. Even when we inspect a well, we do not
always discover structural, subsurface and environmental
problems that may exist or arise. We are sometimes able to
obtain contractual indemnification for preclosing liabilities,
including environmental liabilities, but we generally acquire
interests in properties on an as is basis with
limited remedies for breaches of representations and warranties.
Competition in
the oil and gas industry is intense, making it more difficult
for us to acquire properties, market oil and natural gas and
secure trained personnel.
We operate in a highly competitive environment for acquiring
properties, marketing oil and natural gas and securing trained
personnel. Many of our competitors possess and employ financial,
technical and personnel resources substantially greater than
ours, which can be particularly important in the areas in which
we operate. Those companies may be able to pay more for
productive oil and gas properties and exploratory prospects and
to evaluate, bid for and purchase a greater number of properties
and prospects than our financial or personnel resources permit.
In addition, those companies may be able to offer better
compensation packages to attract and retain qualified personnel
than we are able to offer. The cost to attract and retain
qualified personnel has increased over the past few years due to
competition and may increase substantially in the future. Our
ability to acquire additional prospects and to find and develop
reserves in the future will depend on our ability to evaluate
and select suitable properties and to consummate transactions in
a highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and
gas industry. We may not be able to compete successfully in the
future in acquiring prospective reserves, developing reserves,
marketing hydrocarbons, attracting and retaining quality
personnel and raising additional capital. Our failure to acquire
properties, market oil and natural gas and secure trained
personnel and adequately compensate personnel could have a
material adverse effect on our production, revenues and results
of operations.
Shortages of
oilfield equipment, services and qualified personnel could delay
our drilling program and increase the prices we pay to obtain
such equipment, services and personnel.
The demand for qualified and experienced field personnel to
drill wells and conduct field operations, geologists,
geophysicists, engineers and other professionals in the oil and
gas industry can fluctuate significantly, often in correlation
with oil and natural gas prices, causing periodic shortages.
Historically, there have been shortages of drilling and workover
rigs, pipe and other oilfield equipment as demand for rigs and
equipment has increased along with the number of wells being
drilled. These factors also cause significant increases in costs
for equipment, services and personnel. Higher oil and natural
gas prices generally stimulate demand and result in increased
prices for drilling and workover rigs, crews and associated
supplies, equipment and services. It is beyond our control and
ability to predict whether these conditions will exist in the
future and, if so, what their timing and duration will be. These
types of shortages or price increases could significantly
decrease our profit margin, cash flow and operating results, or
restrict our ability to drill the wells and conduct the
operations which we currently have planned and budgeted or which
we may plan in the future.
S-28
Our
exploration and development drilling may not result in
commercially productive reserves.
Drilling activities are subject to many risks, including the
risk that commercially productive reservoirs will not be
encountered. New wells that we drill may not be productive, or
we may not recover all or any portion of our investment in such
wells. The seismic data and other technologies we use do not
allow us to know conclusively prior to drilling a well that oil
or natural gas is present or may be produced economically.
Drilling for oil and natural gas often involves unprofitable
results, not only from dry holes but also from wells that are
productive but do not produce sufficient net reserves to return
a profit at then realized prices after deducting drilling,
operating and other costs. The cost of drilling, completing and
operating a well is often uncertain, and cost factors can
adversely affect the economics of a project. Further, our
drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or lost circulation in formations;
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equipment failures or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental or
contractual requirements; and
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increases in the cost of, or shortages or delays in the
availability of, electricity, supplies, materials, drilling or
workover rigs, equipment and services.
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We
periodically evaluate our unproved oil and gas properties for
impairment, and could be required to recognize noncash charges
to earnings of future periods.
At June 30, 2009, we carried unproved property costs of
$277.1 million. GAAP requires periodic evaluation of these
costs on a
project-by-project
basis in comparison to their estimated fair value. These
evaluations will be affected by the results of exploration
activities, commodity price circumstances, planned future sales
or expiration of all or a portion of the leases, contracts and
permits appurtenant to such projects. If the quantity of
potential reserves determined by such evaluations is not
sufficient to fully recover the cost invested in each project,
we will recognize noncash charges to earnings in future periods.
We may incur
substantial losses and be subject to substantial liability
claims as a result of our oil and natural gas operations. In
addition, we may not be insured for, or our insurance may be
inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities
arising from uninsured and underinsured events could materially
and adversely affect our business, financial condition or
results of operations. Our oil and natural gas exploration and
production activities are subject to all of the operating risks
associated with drilling for and producing oil and natural gas,
including the possibility of:
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environmental hazards, such as uncontrollable flows of oil,
natural gas, brine, well fluids, toxic gas or other pollution
into the environment, including groundwater contamination;
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abnormally pressured or structured formations;
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S-29
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mechanical difficulties, such as stuck oilfield drilling and
service tools and casing collapse;
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fires, explosions and ruptures of pipelines;
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personal injuries and death; and
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natural disasters.
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Any of these risks could adversely affect our ability to conduct
operations or result in substantial losses to us as a result of:
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injury or loss of life;
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damage to and destruction of property, natural resources and
equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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suspension of our operations; and
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repair and remediation costs.
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We may elect not to obtain insurance if we believe that the cost
of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks
generally are not fully insurable. The occurrence of an event
that is not covered or not fully covered by insurance could have
a material adverse effect on our production, revenues and
results of operations.
Market
conditions or operational impediments may hinder our access to
oil and natural gas markets or delay our
production.
Market conditions or the unavailability of satisfactory oil and
natural gas processing or transportation arrangements may hinder
our access to oil and natural gas markets or delay our
production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including
the demand for and supply of oil and natural gas, the proximity
of reserves to pipelines and terminal facilities, competition
for such facilities and the inability of such facilities to
gather, transport or process our production due to shutdowns or
curtailments arising from mechanical, operational or weather
related matters, including hurricanes and other severe weather
conditions. Our ability to market our production depends in
substantial part on the availability and capacity of gathering
and transportation systems, pipelines and processing facilities
owned and operated by third parties. Our failure to obtain such
services on acceptable terms could have a material adverse
effect on our business, financial condition and results of
operations. We may be required to shut in or otherwise curtail
production from wells due to lack of a market or inadequacy or
unavailability of oil, natural gas liquids or natural gas
pipeline or gathering, transportation or processing capacity. If
that were to occur, then we would be unable to realize revenue
from those wells until suitable arrangements were made to market
our production.
We are subject
to complex federal, state, local and other laws and regulations
that could adversely affect the cost, timing, manner or
feasibility of conducting our operations.
Our oil and natural gas exploration, development and production,
and related saltwater disposal operations are subject to complex
and stringent laws and regulations. In order to conduct our
operations in compliance with these laws and regulations, we
must obtain and
S-30
maintain numerous permits, approvals and certificates from
various federal, state, local and governmental authorities. We
may incur substantial costs and experience delays in order to
maintain compliance with these existing laws and regulations. In
addition, our costs of compliance may increase or our operations
may be otherwise adversely affected if existing laws and
regulations are revised or reinterpreted, or if new laws and
regulations become applicable to our operations. These and other
costs could have a material adverse effect on our production,
revenues and results of operations.
Our business is subject to federal, state and local laws and
regulations as interpreted and enforced by governmental
authorities possessing jurisdiction over various aspects of the
exploration for, and the production of, oil and natural gas.
Failure to comply with such laws and regulations, as interpreted
and enforced, could have a material adverse effect on our
production, revenues and results of operations.
Our operations
expose us to significant costs and liabilities with respect to
environmental and operational safety matters.
We may incur significant delays, costs and liabilities as a
result of environmental, health and safety requirements
applicable to our oil and natural gas exploration, development
and production, and related saltwater disposal activities. These
delays, costs and liabilities could arise under a wide range of
federal, state and local laws and regulations relating to
protection of the environment, health and safety, including
regulations and enforcement policies that have tended to become
increasingly strict over time. Failure to comply with these laws
and regulations may result in the assessment of administrative,
civil and criminal penalties, imposition of cleanup and site
restoration costs and liens, and, in some instances, issuance of
orders or injunctions limiting or requiring discontinuation of
certain operations. In addition, claims for damages to persons
or property, including natural resources, may result from the
environmental, health and safety impacts of our operations.
Strict as well as joint and several liability may be imposed
under certain environmental laws, which could cause us to become
liable for the conduct of others or for consequences of our own
actions that were in compliance with all applicable laws at the
time those actions were taken. New laws, regulations or
enforcement policies could be more stringent and impose
unforeseen liabilities or significantly increase compliance
costs. If we were not able to recover the resulting costs
through insurance or increased revenues, our production,
revenues and results of operations could be adversely affected.
The adoption
of climate change legislation by Congress could result in
increased operating costs and reduced demand for the oil and
natural gas we produce.
On June 26, 2009, the U.S. House of Representatives
approved adoption of the American Clean Energy and
Security Act of 2009, also known as the
Waxman-Markey
cap-and-trade
legislation or ACESA. The purpose of ACESA is to control
and reduce emissions of greenhouse gases, or
GHGs, in the United States. GHGs are certain gases,
including carbon dioxide and methane, that may be contributing
to warming of the Earths atmosphere and other climatic
changes. ACESA would establish an economy-wide cap on emissions
of GHGs in the United States and would require an overall
reduction in GHG emissions of 17% (from 2005 levels) by 2020,
and by over 80% by 2050. Under ACESA, most sources of GHG
emissions would be required to obtain GHG emission
allowances corresponding to their annual emissions
of GHGs. The number of emission allowances issued each year
would decline as necessary to meet ACESAs
S-31
overall emission reduction goals. As the number of GHG emission
allowances declines each year, the cost or value of allowances
is expected to escalate significantly. The net effect of ACESA
would be to impose increasing costs on the combustion of
carbon-based fuels such as oil, refined petroleum products, and
natural gas.
The U.S. Senate has begun work on its own legislation for
controlling and reducing emissions of GHGs in the United States.
If the Senate adopts GHG legislation that is different from
ACESA, the Senate legislation would need to be reconciled with
ACESA and both chambers would be required to approve identical
legislation before it could become law. President Obama has
indicated that he is in support of the adoption of legislation
to control and reduce emissions of GHGs through an emission
allowance permitting system that results in fewer allowances
being issued each year but that allows parties to buy, sell and
trade allowances as needed to fulfill their GHG emission
obligations. Although it is not possible at this time to predict
whether or when the Senate may act on climate change legislation
or how any bill approved by the Senate would be reconciled with
ACESA, any laws or regulations that may be adopted to restrict
or reduce emissions of GHGs could require us to incur increased
operating costs, and could have an adverse effect on demand for
the oil and natural gas we produce.
The adoption
of derivatives legislation by Congress could have an adverse
impact on our ability to hedge risks associated with our
business.
Congress is currently considering legislation to impose
restrictions on certain transactions involving derivatives,
which could affect the use of derivatives in hedging
transactions. ACESA contains provisions that would prohibit
private energy commodity derivative and hedging transactions.
ACESA would expand the power of the Commodity Futures Trading
Commission, or CFTC, to regulate derivative transactions related
to energy commodities, including oil and natural gas, and to
mandate clearance of such derivative contracts through
registered derivative clearing organizations. Under ACESA, the
CFTCs expanded authority over energy derivatives would
terminate upon the adoption of general legislation covering
derivative regulatory reform. The CFTC is conducting hearings to
determine whether to set limits on trading and positions in
commodities with finite supply, particularly energy commodities,
such as oil, natural gas and other energy products. The CFTC
also is evaluating whether position limits should be applied
consistently across all markets and participants. In addition,
the Treasury Department recently has indicated that it intends
to propose legislation to subject all
over-the-counter,
or OTC, derivative dealers and all other major OTC derivatives
market participants to substantial supervision and regulation,
including by imposing conservative capital and margin
requirements and strong business conduct standards. Derivatives
contracts that are not cleared through central clearinghouses
and exchanges may be subject to substantially higher capital and
margin requirements. Although it is not possible at this time to
predict whether or when the Senate may act on derivatives
legislation or how any bill approved by the Senate would be
reconciled with ACESA, any laws or regulations that may be
adopted that subject us to additional capital or margin
requirements relating to, or additional restrictions on, our
trading and commodity positions could have an adverse impact on
our ability to hedge risks associated with our business.
Federal and
state legislation and regulatory initiatives relating to
hydraulic fracturing could result in increased costs and
additional operating restrictions or delays.
Legislation has been proposed in Congress to amend the federal
Safe Drinking Water Act to require the disclosure of chemicals
used by the oil and gas industry in the hydraulic fracturing
process.
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Hydraulic fracturing involves the injection of water, sand and
chemicals under pressure into rock formations to stimulate oil
and natural gas production. Sponsors of bills currently pending
before the Senate and House of Representatives have asserted
that chemicals used in the fracturing process may be impacting
drinking water supplies. The proposed legislation would require
the reporting and public disclosure of chemicals used in the
fracturing process, which could make it easier for third parties
opposing the hydraulic fracturing process to initiate legal
proceedings based on allegations that specific chemicals used in
the fracturing process are impairing groundwater or causing
other damage. In addition, these bills, if adopted, could
establish an additional level of regulation at the federal level
that could lead to operational delays or increased operating
costs and could result in additional regulatory burdens that
could make it more difficult to perform hydraulic fracturing and
increase our costs of compliance and doing business.
The loss of
our chief executive officer or other key personnel could
negatively impact our ability to execute our business
strategy.
We depend, and will continue to depend in the foreseeable
future, on the services of our chief executive officer, Timothy
A. Leach, and other officers and key employees who have
extensive experience and expertise in evaluating and analyzing
producing oil and gas properties and drilling prospects,
maximizing production from oil and gas properties, marketing oil
and gas production, and developing and executing acquisition,
financing and hedging strategies. Our ability to hire and retain
our officers and key employees is important to our continued
success and growth. The unexpected loss of the services of one
or more of these individuals could negatively impact our ability
to execute our business strategy.
Uncertainties
associated with enhanced recovery methods may result in us not
realizing an acceptable return on our investments in such
projects.
We inject water into formations on some of our properties to
increase the production of oil and natural gas. We may in the
future expand these efforts to more of our properties or employ
other enhanced recovery methods in our operations. The
additional production and reserves, if any, attributable to the
use of enhanced recovery methods are inherently difficult to
predict. If our enhanced recovery methods do not allow for the
extraction of oil and natural gas in a manner or to the extent
that we anticipate, we may not realize an acceptable return on
our investments in such projects. In addition, if proposed
legislation and regulatory initiatives relating to hydraulic
fracturing become law, the cost of some of these enhanced
recovery methods could increase substantially.
Our
indebtedness could restrict our operations and make us more
vulnerable to adverse economic conditions.
We now have, and will continue to have, a significant amount of
indebtedness, and the terms of our credit facility require us to
pay higher interest rate margins as we utilize a larger
percentage of our available borrowing base. At June 30,
2009, after giving effect to the issuance and sale of the notes
and the application of the net proceeds therefrom as set forth
under Use of proceeds to repay a portion of the
borrowings under our credit facility, we would have had total
consolidated indebtedness of $668.7 million (net of
discount). Assuming our total debt outstanding at June 30,
2009 was held constant, if interest rates had been higher or
lower by one percent per annum, on our variable interest rate
indebtedness, our interest expense for the six months ended
June 30, 2009 would have increased or decreased by
approximately $1.9 million. Following the application of
the proceeds of this offering in the manner described in
Use of proceeds and
S-33
giving effect to the reduction to our borrowing base as a result
of the issuance of the notes, we expect to have approximately
$582.8 million of availability under our credit facility
and a revised borrowing base of $955.9 million. For further
discussion, see Description of other
indebtednessSenior secured credit facility.
Our current and future indebtedness could have important
consequences to you. For example, it could:
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impair our ability to make investments and obtain additional
financing for working capital, capital expenditures,
acquisitions or other general corporate purposes;
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limit our ability to use operating cash flow in other areas of
our business because we must dedicate a substantial portion of
these funds to make principal and interest payments on our
indebtedness;
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limit our ability to borrow funds that may be necessary to
operate or expand our business;
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put us at a competitive disadvantage to competitors that have
less debt;
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increase our vulnerability to interest rate increases; and
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hinder our ability to adjust to rapidly changing economic and
industry conditions.
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Our ability to meet our debt service and other obligations,
including our obligations with respect to the notes, may depend
in significant part on the extent to which we can successfully
implement our business strategy. We may not be able to implement
or realize the benefits of our business strategy.
A terrorist
attack or armed conflict could harm our business by decreasing
our revenues and increasing our costs.
Terrorist activities, anti-terrorist efforts and other armed
conflict involving the United States may adversely affect the
United States and global economies and could prevent us from
meeting our financial and other obligations. If any of these
events occur or escalate, the resulting political instability
and societal disruption could reduce overall demand for oil and
natural gas, potentially putting downward pressure on demand for
our services and causing a reduction in our revenue. Oil and
natural gas related facilities could be direct targets of
terrorist attacks, and our operations could be adversely
impacted if significant infrastructure or facilities used for
the production, transportation, processing or marketing of oil
and natural gas production are destroyed or damaged. Costs for
insurance and other security may increase as a result of these
threats, and some insurance coverage may become more difficult
to obtain, if available at all.
Risks related to
the notes
We and the
guarantors may incur substantial additional indebtedness,
including indebtedness ranking equal to the notes and the
guarantees.
At June 30, 2009, after giving effect to the issuance and
sale of the notes and the application of the net proceeds
therefrom as set forth under Use of proceeds to
repay a portion of the borrowings outstanding under our credit
facility, we and the guarantors would have had total
consolidated indebtedness of $668.7 million (net of
discount), (including $373.0 million of secured
indebtedness and guarantees under our credit facility) and we
would have been able to incur an additional $582.8 million
of secured indebtedness under our credit facility (after giving
effect to the
S-34
automatic reduction in the borrowing base under our credit
facility resulting from the issuance of the notes). For further
discussion, see Description of other
indebtednessSenior secured credit facility.
Subject to the restrictions in the indenture governing the notes
and in other instruments governing our other outstanding
indebtedness (including our credit facility), we and our
subsidiaries may incur substantial additional indebtedness
(including secured indebtedness) in the future. Although the
indenture governing the notes and the instruments governing
certain of our other outstanding indebtedness contain
restrictions on the incurrence of additional indebtedness, these
restrictions are subject to waiver and a number of significant
qualifications and exceptions, and indebtedness incurred in
compliance with these restrictions could be substantial.
If we or any subsidiary guarantor incurs any additional
indebtedness that ranks equally with the notes (or with the
guarantee thereof), including trade payables, the holders of
that indebtedness will be entitled to share ratably with
noteholders in any proceeds distributed in connection with any
insolvency, liquidation, reorganization, dissolution or other
winding-up
of us or such subsidiary guarantor. This may have the effect of
reducing the amount of proceeds paid to noteholders in
connection with such a distribution.
Any increase in our level of indebtedness will have several
important effects on our future operations, including, without
limitation:
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we will have additional cash requirements in order to support
the payment of interest on our outstanding indebtedness;
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increases in our outstanding indebtedness and leverage will
increase our vulnerability to adverse changes in general
economic and industry conditions, as well as to competitive
pressure; and
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depending on the levels of our outstanding indebtedness, our
ability to obtain additional financing for working capital,
capital expenditures, general corporate and other purposes may
be limited.
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Our credit facility and the indenture governing the notes
have restrictive covenants that could limit our financial
flexibility.
The indenture related to the notes and our credit facility
contain restrictive covenants that limit our ability to engage
in activities that may be in our long-term best interests. Our
ability to borrow under our credit facility is subject to
compliance with certain financial covenants, including
(i) maintenance of a quarterly ratio of total debt to
consolidated earnings before interest expense, income taxes,
depletion, depreciation, and amortization, exploration expense
and other noncash income and expenses to be no greater than 4.0
to 1.0, and (ii) maintenance of a ratio of current assets
to current liabilities, excluding noncash assets and liabilities
related to financial derivatives and asset retirement
obligations and including the unfunded amounts under the credit
facility, to be no less than 1.0 to 1.0. Our credit facility
also includes other restrictions that, among other things, limit
our ability to incur certain additional indebtedness and certain
types of liens, to effect mergers and sales or transfer of
assets and to pay cash dividends.
The indenture governing the notes will contain covenants that,
among other things, limit our ability and the ability of our
restricted subsidiaries to:
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incur additional debt;
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make certain investments or pay dividends or distributions on
our capital stock or purchase, redeem or retire capital stock;
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S-35
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sell assets, including capital stock of our restricted
subsidiaries;
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restrict dividends or other payments by restricted subsidiaries;
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create liens that secure debt;
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enter into transactions with affiliates; and
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merge or consolidate with another company.
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See Description of other indebtedness and
Description of notes. Our failure to comply with
these covenants could result in an event of default that, if not
cured or waived, could result in the acceleration of all of our
indebtedness. We do not have sufficient working capital to
satisfy our debt obligations in the event of an acceleration of
all or a significant portion of our outstanding indebtedness.
We may not be
able to generate sufficient cash to service all of our
indebtedness, including the notes, and may be forced to take
other actions to satisfy our obligations under our indebtedness,
which may not be successful.
Our ability to make scheduled payments on or to refinance our
debt obligations depends on our financial condition and
operating performance, which is subject to prevailing economic
and competitive conditions and to certain financial, business
and other factors beyond our control. We may not be able to
maintain a level of cash flows from operating activities
sufficient to permit us to pay the principal, premium, if any,
and interest on our indebtedness, including the notes.
If our cash flows and capital resources are insufficient to fund
our debt service obligations, we may be forced to reduce or
delay planned investments and capital expenditures, or to sell
assets, seek additional financing in the debt or equity markets
or restructure or refinance our indebtedness, including the
notes. Our ability to restructure or refinance our debt will
depend on the condition of the capital markets and our financial
condition at such time. Any refinancing of our debt could be at
higher interest rates and may require us to comply with more
onerous covenants, which could further restrict our business
operations. The terms of existing or future debt instruments and
the indenture governing the notes may restrict us from adopting
some of these alternatives. In addition, any failure to make
payments of interest and principal on our outstanding
indebtedness on a timely basis would likely result in a
reduction of our credit rating, which could harm our ability to
incur additional indebtedness. In the absence of such operating
results and resources, we could face substantial liquidity
problems and might be required to dispose of material assets or
operations to meet our debt service and other obligations. Our
credit facility and the indenture governing the notes offered
hereby restrict our ability to dispose of assets and use the
proceeds from the disposition. We may not be able to consummate
those dispositions or to obtain the proceeds that we could have
realized from them and any proceeds may not be adequate to meet
any debt service obligations then due. These alternative
measures may not be successful and may not permit us to meet our
debt service obligations.
Your right to
receive payments on the notes is structurally subordinated to
the right of lenders who have a security interest in our assets
to the extent of the value of those assets.
Our obligations under the notes and the guarantors
obligations under their guarantees of the notes will be
unsecured, but our obligations under our credit facility and
certain other financing
S-36
arrangements with lenders under our credit facility and each
guarantors obligations under its guarantee of our credit
facility are secured by a security interest in substantially all
of our oil and natural gas properties and the ownership
interests of all of our subsidiaries. If we are declared
bankrupt or insolvent, or if we default under our credit
facility, the funds borrowed thereunder, together with accrued
interest, could become immediately due and payable. If we were
unable to repay such indebtedness, the lenders under our credit
facility could foreclose on the pledged assets to the exclusion
of holders of the notes, even if an event of default exists
under the indenture governing the notes at such time.
Furthermore, if the lenders foreclose and sell the pledged
equity interests in any guarantor in a transaction permitted
under the terms of the indenture governing the notes, then such
guarantor will be released from its guarantee of the notes
automatically and immediately upon such sale. In any such event,
because the notes are not secured by any of such assets or by
the equity interests in any such guarantor, it is possible that
there would be no assets from which your claims could be
satisfied or, if any assets existed, they might be insufficient
to satisfy your claims in full. Please see
Managements discussion and analysis of financial
condition and results of operationsCapital commitments,
capital resources and liquidity.
As of June 30, 2009, after giving effect to the issuance
and sale of the notes and the application of the net proceeds
therefrom as set forth under Use of proceeds to pay
down a portion of the borrowings outstanding under our credit
facility, we would have had total consolidated indebtedness of
$668.7 million (net of discount), consisting of
$373.0 million of secured indebtedness outstanding under
our credit facility and $295.7 million (net of discount) of
the notes offered hereby, the subsidiary guarantors would have
had total indebtedness of $668.7 million (net of discount)
consisting of $373.0 million of secured guarantees under
our credit facility and $295.7 million (net of discount) of
guarantees of the notes offered hereby, excluding intercompany
indebtedness, and we would have been able to incur an additional
$582.8 million of secured indebtedness under our credit
facility (after giving effect to the reduction in our borrowing
base as a result of the issuance of the notes). See
Description of other indebtednessSenior secured
credit facility.
Our ability to
repay our debt, including the notes, is affected by the cash
flow generated by our subsidiaries.
Our subsidiaries own substantially all of our assets and conduct
all of our operations. Accordingly, repayment of our
indebtedness, including the notes, will be dependent on the
generation of cash flow by our subsidiaries and their ability to
make such cash available to us, by dividend, debt repayment or
otherwise. All of our existing subsidiaries on the date of
completion of this offering will guarantee our obligations under
the notes. Unless they guarantee the notes, any of our future
subsidiaries will not have any obligation to pay amounts due on
the notes or to make funds available for that purpose. Our
subsidiaries may not be able to, or may not be permitted to,
make distributions to enable us to make payments in respect of
our indebtedness, including the notes. Each subsidiary is a
distinct legal entity and, under certain circumstances, legal
and contractual restrictions may limit our ability to obtain
cash from our subsidiaries. While the indenture governing the
notes limits the ability of our subsidiaries to incur consensual
encumbrances or restrictions on their ability to pay dividends
or make other intercompany payments to us, these limitations are
subject to waiver and certain qualifications and exceptions. In
the event that we do not receive distributions from our
subsidiaries, we may be unable to make required principal,
premium, if any, and interest payments on our indebtedness,
including the notes.
S-37
Claims of
noteholders will be structurally subordinated to claims of
creditors of any of our future subsidiaries that do not
guarantee the notes.
We conduct all of our operations through our subsidiaries.
Subject to certain limitations, the indenture governing the
notes permits us to form or acquire certain subsidiaries that
are not guarantors of the notes and to permit such non-guarantor
subsidiaries to acquire assets and incur indebtedness, and
noteholders would not have any claim as a creditor against any
of our non-guarantor subsidiaries to the assets and earnings of
those subsidiaries. The claims of the creditors of those
subsidiaries, including their trade creditors, banks and other
lenders, would have priority over any of our claims or those of
our other subsidiaries as equity holders of the non-guarantor
subsidiaries. Consequently, in any insolvency, liquidation,
reorganization, dissolution or other
winding-up
of any of the non-guarantor subsidiaries, creditors of those
subsidiaries would be paid before any amounts would be
distributed to us or to any of the guarantors as equity, and
thus be available to satisfy our obligations under the notes and
other claims against us or the guarantors.
If we default
on our obligations to pay our other indebtedness, we may not be
able to make payments on the notes.
Any default under the agreements governing our indebtedness,
including a default under our credit facility, that is not
waived, and the remedies sought by the holders of such
indebtedness, could prevent us from paying principal, premium,
if any, and interest on the notes and substantially decrease the
market value of the notes. If we are unable to generate
sufficient cash flow and are otherwise unable to obtain funds
necessary to meet required payments of principal, premium, if
any, and interest on our indebtedness, or if we otherwise fail
to comply with the various covenants, including covenants in the
instruments governing our indebtedness (including covenants in
our credit facility and the indenture governing the notes), we
could be in default under the terms of the agreements governing
such indebtedness, including our credit facility and the
indenture governing the notes. In the event of such default:
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the holders of such indebtedness could elect to declare all the
funds borrowed thereunder to be due and payable, together with
accrued and unpaid interest;
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the lenders under our credit facility could elect to terminate
their commitments thereunder, cease making further loans and
institute foreclosure proceedings against our assets; and
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we could be forced into bankruptcy or liquidation.
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If our operating performance declines, we may in the future need
to obtain waivers under our credit facility to avoid being in
default. If we breach our covenants under our credit facility
and seek a waiver, we may not be able to obtain a waiver from
the required lenders. If this occurs, we would be in default
under our credit facility, the lenders could exercise their
rights, as described above, and we could be forced into
bankruptcy or liquidation.
We may not be
able to repurchase the notes upon a change of
control.
Upon the occurrence of specific kinds of change of control
events, we may be required to offer to repurchase all
outstanding notes at 101% of their principal amount plus accrued
and unpaid interest, if any. The source of funds for any such
purchase of the notes will be our available cash or cash
generated from the operations of our subsidiaries or other
sources, including borrowings, sales of assets or sales of
equity or debt securities. We may not be able to repurchase the
S-38
notes upon a change of control because we may not have
sufficient financial resources to purchase all of the notes that
are tendered upon a change of control. Our failure to repurchase
the notes upon a change of control would cause a default under
the indenture governing the notes and could lead to a cross
default under our credit facility.
The change of
control put right might not be enforceable.
In a recent decision, the Chancery Court of Delaware raised the
possibility that a change of control put right occurring as a
result of a failure to have continuing directors
comprising a majority of a board of directors might be
unenforceable on public policy grounds.
Federal
bankruptcy and state fraudulent transfer laws and other
limitations may preclude the recovery of payments under the
guarantees.
Initially, all of our subsidiaries will guarantee the notes.
Federal bankruptcy and state fraudulent transfer laws permit a
court, if it makes certain findings, to avoid all or a portion
of the obligations of the guarantors pursuant to their
guarantees of the notes, or to subordinate any such
guarantors obligations under such guarantee to claims of
its other creditors, reducing or eliminating the
noteholders ability to recover under such guarantees.
Although laws differ among these jurisdictions, in general,
under applicable fraudulent transfer or conveyance laws, a
guarantee could be voided as a fraudulent transfer or conveyance
if (1) the guarantee was incurred with the intent of
hindering, delaying or defrauding creditors; or (2) the
guarantor received less than reasonably equivalent value or fair
consideration in return for incurring the guarantee and, in the
case of (2) only, one of the following is also true:
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the guarantor was insolvent or rendered insolvent by reason of
the incurrence of the guarantee or subsequently become insolvent
for other reasons;
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the incurrence of the guarantee left the guarantor with an
unreasonably small amount of capital to carry on the
business; or
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the guarantor intended to, or believed that it would, incur
debts beyond its ability to pay such debts as they mature.
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A court would likely find that a guarantor did not receive
reasonably equivalent value or fair consideration for its
guarantee if the guarantor did not substantially benefit
directly or indirectly from the issuance of the notes. If a
court were to void a guarantee, you would no longer have a claim
against the guarantor. Sufficient funds to repay the notes may
not be available from other sources, including the remaining
guarantors, if any. In addition, the court might direct you to
repay any amounts that you already received from the guarantor.
The measures of insolvency for purposes of fraudulent transfer
laws vary depending upon the governing law. Generally, a
guarantor would be considered insolvent if:
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the sum of its debts, including contingent liabilities, was
greater than the fair saleable value of all its assets;
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the present fair saleable value of its assets was less than the
amount that would be required to pay its probable liability on
its existing debts, including contingent liabilities, as they
became absolute and mature; or
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it could not pay its debts as they became due.
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S-39
Each guarantee will contain a provision intended to limit the
guarantors liability to the maximum amount that it could
incur without causing the incurrence of obligations under its
guarantee to be a fraudulent transfer. This provision may not be
effective to protect the guarantees from being voided under
fraudulent transfer law.
An active
trading market for the notes may not develop.
There is no existing market for the notes. The notes will not be
listed on any securities exchange. There can be no assurance
that a trading market for the notes will ever develop or will be
maintained. Further, there can be no assurance as to the
liquidity of any market that may develop for the notes, your
ability to sell your notes or the price at which you will be
able to sell your notes. Future trading prices of the notes will
depend on many factors, including prevailing interest rates, our
financial condition and results of operations, the then-current
ratings assigned to the notes and the market for similar
securities. Any trading market that develops would be affected
by many factors independent of and in addition to the foregoing,
including the:
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time remaining to the maturity of the notes;
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outstanding amount of the notes;
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terms related to optional redemption of the notes; and
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level, direction and volatility of market interest rates
generally.
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If an active market does not develop or is not maintained, the
market price and liquidity of the notes may be adversely
affected.
Many of the
covenants contained in the indenture will terminate if the notes
are rated investment grade by both of Standard &
Poors Ratings Services and Moodys Investors Service,
Inc.
Many of the covenants in the indenture governing the notes will
terminate if the notes are rated investment grade by both of
Standard & Poors Ratings Service and
Moodys Investors Service, Inc., provided at such time no
default under the indenture has occurred and is continuing.
These covenants will restrict, among other things, our ability
to pay dividends, to incur debt and to enter into certain other
transactions. There can be no assurance that the notes will ever
be rated investment grade, or that if they are rated investment
grade, that the notes will maintain such ratings. However,
termination of these covenants would allow us to engage in
certain transactions that would not be permitted while these
covenants were in force. Please see Description of
notesCovenant termination.
S-40
Ratios of
earnings to fixed charges and earnings to fixed charges and
preferred stock dividends
The following table contains our consolidated ratios of earnings
to fixed charges and earnings to fixed charges and preferred
stock dividends for the periods indicated.
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Concho Resources Inc.
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Chase Group Properties
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Years ended
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Inception (April 21,
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Years ended
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Six months ended
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December 31,
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2004) through
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December 31,
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June 30, 2009
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2008
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2007
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2006
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2005
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December 31, 2004
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2005
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2004
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Ratios of earnings to fixed
chargesa
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c
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15.36
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2.00
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1.97
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2.01
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c
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NMd
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NM
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d
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Ratios of earnings to fixed charges and preferred stock
dividendsb
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e
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15.36
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2.00
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1.90
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f
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e
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NMd
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NM
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d
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(a)
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The ratio has been computed by
dividing earnings by fixed charges. For purposes of computing
the ratio:
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earnings include income (loss) before income taxes, adjusted for
interest expense and the portion of rental expense deemed to be
representative of the interest component of rental
expense; and
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fixed charges consist of interest expense, capitalized interest
and the portion of rental expense deemed to be representative of
the interest component of rental expense.
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(b)
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The ratio has been computed by
dividing earnings by fixed charges and preferred stock
dividends. For purposes of computing the ratio:
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earnings include income (loss) before income taxes, adjusted for
interest expense and the portion of rental expense deemed to be
representative of the interest component of rental
expense; and
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fixed charges and preferred stock dividends consist of interest
expense, capitalized interest, the portion of rental expense
deemed to be representative of the interest component of rental
expense and preferred stock dividends.
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(c)
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Due to our net loss for the six
months ended June 30, 2009 and from inception
(April 21, 2004) through December 31, 2004, the
ratio coverage was less than 1:1. To achieve ratio coverage of
1:1, we would have needed additional earnings of approximately
$80.3 million and $3.6 million, respectively.
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(d)
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Not meaningful, as there were no
fixed charges or preferred stock dividends for these periods.
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(e)
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Due to our net loss for the six
months ended June 30, 2009 and from inception
(April 21, 2004) through December 31, 2004, the
ratio coverage was less than 1:1. To achieve a ratio coverage of
1:1, we would have needed additional earnings of approximately
$80.3 million and $4.4 million, respectively.
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(f)
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Due to the fixed charges and
preferred stock dividends exceeding earnings for the period, we
would have needed additional earnings of approximately
$1.1 million to achieve a ratio coverage of 1:1.
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S-41
Use of
proceeds
The net proceeds from this offering will be approximately
$287.0 million, after deducting fees and estimated expenses
(including underwriting discounts and commissions). We intend to
use the net proceeds from this offering to repay a portion of
the outstanding borrowings under our credit facility.
Our credit facility matures on July 31, 2013. At
June 30, 2009, we had outstanding borrowings thereunder of
approximately $660 million, which bore interest at a rate
of approximately 2.82%. Borrowings under the credit facility are
incurred for general corporate purposes, including the funding
of our capital budget. Any amounts repaid with the proceeds from
this offering may be reborrowed in the future. As of
June 30, 2009, after giving effect to the issuance and sale
of the notes and the application of the net proceeds therefrom
and the automatic reduction in the borrowing base under our
credit facility resulting from the issuance of the notes, we
would have been able to incur an additional $582.8 million
of indebtedness under our credit facility. For further
discussion, see Description of other
indebtednessSenior secured credit facility.
S-42
Capitalization
The following table sets forth our capitalization at
June 30, 2009:
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on an actual basis; and
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on an as adjusted basis to give effect to (i) the
completion of this offering and (ii) our application of the
net proceeds from this offering in the manner described in
Use of proceeds.
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June 30, 2009
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(unaudited) (in
thousands)
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Actual
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As adjusted
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Cash and cash equivalents
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$
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3,081
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$
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3,081
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Long-term debt:
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Credit
facilitya
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$
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660,000
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$
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373,016
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8.625% Senior Notes due
2017b
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|
|
295,734
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
660,000
|
|
|
|
668,750
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; 300,000,000 authorized;
85,529,591 shares issued at June 30, 2009 actual and
as adjusted
|
|
|
86
|
|
|
|
86
|
|
Additional paid-in capital
|
|
|
1,020,060
|
|
|
|
1,020,060
|
|
Retained earnings
|
|
|
269,726
|
|
|
|
269,726
|
|
Treasury stock, at cost; 9,341 shares at June 30, 2009
|
|
|
(317
|
)
|
|
|
(317
|
)
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,289,555
|
|
|
|
1,289,555
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
1,949,555
|
|
|
$
|
1,958,305
|
|
|
|
|
|
|
(a)
|
|
As of June 30, 2009, after
giving effect to the issuance and sale of the notes and the
application of the net proceeds therefrom and the automatic
reduction in the borrowing base under our credit facility
resulting from the issuance of the notes, we would have been
able to incur an additional $582.8 million of indebtedness
under our credit facility. For further discussion, see
Description of other indebtednessSenior secured
credit facility.
|
|
(b)
|
|
The $300 million of notes are
recorded at their discounted amount, with the discount to be
amortized over the life of the notes.
|
S-43
Selected
historical financial data
The following tables show our selected historical financial data
as of and for the periods indicated. The selected historical
consolidated financial data presented below is not intended to
replace our historical consolidated financial statements. You
should read the following data along with
Managements discussion and analysis of financial
condition and results of operations and our consolidated
financial statements and related the notes, each of which is
included or incorporated by reference in this prospectus
supplement.
Selected
historical financial information
The following table shows selected historical financial data
related to us (as the accounting successor to Concho Equity
Holdings Corp., which is now known as Concho Equity Holdings
LLC) and combined financial data of the properties we
acquired from Chase Oil Corporation, Caza Energy LLC and other
related working interest owners (which we refer to collectively
as the Chase Group Properties). We have accounted
for the combination transaction that occurred on
February 27, 2006, as an acquisition by Concho Equity
Holdings Corp. of the Chase Group Properties and a simultaneous
reorganization of Concho such that Concho Equity Holdings Corp.
became our wholly owned subsidiary.
Our historical results of operations for the periods presented
below may not be comparable either from period to period or
going forward, for the following reasons:
|
|
|
prior to December 7, 2004, Concho Equity Holdings Corp. did
not own any material assets and did not conduct substantial
operations other than organizational activities;
|
|
|
on December 7, 2004, Concho Equity Holdings Corp. acquired
oil and gas assets for approximately $117 million and
commenced oil and gas operations;
|
|
|
on February 27, 2006, the initial closing of the Chase Oil
transaction occurred, and we acquired the Chase Group Properties
for approximately 35 million shares of common stock and
approximately $409 million in cash;
|
|
|
on March 27, 2007, we entered into a $200 million
second lien term loan facility from which we received proceeds
of $199 million that we used to repay the
$39.8 million outstanding under our prior term loan
facility and to reduce the outstanding balance under our credit
facility by $154 million, with the remaining
$5.2 million used to pay loan fees, accrued interest and
for general corporate purposes;
|
|
|
in August 2007, we completed our initial public offering of
common stock from which we received proceeds of
$173 million that we used to retire outstanding borrowings
under our second lien term loan facility totaling
$86.5 million and to retire outstanding borrowings under
our credit facility totaling $86.5 million; and
|
|
|
on July 31, 2008, we closed our acquisition of the Henry
Entities and additional non-operated interests in oil and gas
properties from persons affiliated with the Henry Entities. In
August 2008 and September 2008, we acquired additional
non-operated interests in oil and gas properties from persons
affiliated with the Henry Entities. We paid approximately
$583.5 million in net cash for the acquisition of the Henry
Entities and the related acquisition of the along-side
interests, which was funded with borrowings under our credit
facility, which was amended and restated on July 31, 2008,
and net proceeds of approximately $242.4 million from our
private placement of 8,302,894 shares of our common stock.
|
S-44
The historical financial data below for the Chase Group
Properties for the years ended December 31, 2005 and 2004
are derived from the audited financial statements of the Chase
Group Properties. Our historical financial data below for the
years ended December 31, 2008, 2007, 2006 and 2005, and for
the period from inception (April 21, 2004) through
December 31, 2004, are derived from our audited financial
statements. Our historical financial data below for the six
months ended June 30, 2009 and 2008 are derived from our
unaudited consolidated financial statements and the notes
thereto and, in our opinion, have been prepared on a basis
consistent with the audited financial statements and the notes
thereto and include all adjustments, consisting of normal
recurring adjustments, necessary for a fair presentation of this
information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
Chase Group Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004) through
|
|
|
Years ended
|
|
|
|
Six months ended June 30,
|
|
|
Years ended December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008a
|
|
|
2007
|
|
|
2006b
|
|
|
2005
|
|
|
2004c
|
|
|
2005
|
|
|
2004
|
|
(in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
166,485
|
|
|
$
|
171,226
|
|
|
$
|
390,945
|
|
|
$
|
195,596
|
|
|
$
|
131,773
|
|
|
$
|
31,621
|
|
|
$
|
1,851
|
|
|
$
|
73,132
|
|
|
$
|
66,529
|
|
Natural gas sales
|
|
|
46,849
|
|
|
|
72,868
|
|
|
|
142,844
|
|
|
|
98,737
|
|
|
|
66,517
|
|
|
|
23,315
|
|
|
|
1,771
|
|
|
|
46,546
|
|
|
|
41,247
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
213,334
|
|
|
|
244,094
|
|
|
|
533,789
|
|
|
|
294,333
|
|
|
|
198,290
|
|
|
|
54,936
|
|
|
|
3,622
|
|
|
|
119,678
|
|
|
|
107,776
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
50,583
|
|
|
|
38,874
|
|
|
|
91,234
|
|
|
|
54,267
|
|
|
|
37,822
|
|
|
|
14,635
|
|
|
|
746
|
|
|
|
23,277
|
|
|
|
20,964
|
|
Exploration and abandonments
|
|
|
7,419
|
|
|
|
3,464
|
|
|
|
38,468
|
|
|
|
29,098
|
|
|
|
5,612
|
|
|
|
2,666
|
|
|
|
1,850
|
|
|
|
|
|
|
|
179
|
|
Depreciation, depletion and amortization
|
|
|
103,150
|
|
|
|
43,294
|
|
|
|
123,912
|
|
|
|
76,779
|
|
|
|
60,722
|
|
|
|
11,485
|
|
|
|
956
|
|
|
|
18,646
|
|
|
|
20,196
|
|
Accretion of discount on asset retirement obligations
|
|
|
579
|
|
|
|
301
|
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
|
|
89
|
|
|
|
7
|
|
|
|
446
|
|
|
|
263
|
|
Impairments of long-lived assets
|
|
|
8,555
|
|
|
|
69
|
|
|
|
18,417
|
|
|
|
7,267
|
|
|
|
9,891
|
|
|
|
2,295
|
|
|
|
|
|
|
|
194
|
|
|
|
3,233
|
|
General and administrative
|
|
|
21,805
|
|
|
|
13,237
|
|
|
|
35,553
|
|
|
|
21,336
|
|
|
|
12,577
|
|
|
|
8,055
|
|
|
|
3,086
|
|
|
|
1,702
|
|
|
|
1,387
|
|
Stock-based compensation
|
|
|
4,113
|
|
|
|
3,029
|
|
|
|
5,223
|
|
|
|
3,841
|
|
|
|
9,144
|
|
|
|
3,252
|
|
|
|
1,128
|
|
|
|
|
|
|
|
|
|
Bad debt expense
|
|
|
|
|
|
|
1,799
|
|
|
|
2,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling feesstacked rigs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
(920
|
)
|
|
|
(1,336
|
)
|
|
|
821
|
|
|
|
(1,193
|
)
|
|
|
1,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on derivatives not designated as hedges
|
|
|
86,652
|
|
|
|
119,634
|
|
|
|
(249,870
|
)
|
|
|
20,274
|
|
|
|
|
|
|
|
5,001
|
|
|
|
(684
|
)
|
|
|
1,062
|
|
|
|
7,936
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
282,856
|
|
|
|
222,781
|
|
|
|
65,395
|
|
|
|
218,396
|
|
|
|
134,862
|
|
|
|
48,626
|
|
|
|
7,089
|
|
|
|
45,327
|
|
|
|
54,158
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(69,522
|
)
|
|
|
21,313
|
|
|
|
468,394
|
|
|
|
75,937
|
|
|
|
63,428
|
|
|
|
6,310
|
|
|
|
(3,467
|
)
|
|
|
74,351
|
|
|
|
53,618
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(10,570
|
)
|
|
|
(9,500
|
)
|
|
|
(29,039
|
)
|
|
|
(36,042
|
)
|
|
|
(30,567
|
)
|
|
|
(3,096
|
)
|
|
|
(272
|
)
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
(148
|
)
|
|
|
1,331
|
|
|
|
1,432
|
|
|
|
1,484
|
|
|
|
1,186
|
|
|
|
779
|
|
|
|
168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(10,718
|
)
|
|
|
(8,169
|
)
|
|
|
(27,607
|
)
|
|
|
(34,558
|
)
|
|
|
(29,381
|
)
|
|
|
(2,317
|
)
|
|
|
(104
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(80,240
|
)
|
|
|
13,144
|
|
|
|
440,787
|
|
|
|
41,379
|
|
|
|
34,047
|
|
|
|
3,993
|
|
|
|
(3,571
|
)
|
|
|
74,351
|
|
|
|
53,618
|
|
Income tax (expense) benefit
|
|
|
33,797
|
|
|
|
(5,199
|
)
|
|
|
(162,085
|
)
|
|
|
(16,019
|
)
|
|
|
(14,379
|
)
|
|
|
(2,039
|
)
|
|
|
915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(46,443
|
)
|
|
|
7,945
|
|
|
|
278,702
|
|
|
|
25,360
|
|
|
|
19,668
|
|
|
|
1,954
|
|
|
|
(2,656
|
)
|
|
$
|
74,351
|
|
|
$
|
53,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
(1,244
|
)
|
|
|
(4,766
|
)
|
|
|
(804
|
)
|
|
|
|
|
|
|
|
|
Effect of induced conversion of preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) applicable to common shareholders
|
|
$
|
(46,443
|
)
|
|
$
|
7,945
|
|
|
$
|
278,702
|
|
|
$
|
25,315
|
|
|
$
|
30,025
|
|
|
$
|
(2,812
|
)
|
|
$
|
(3,460
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
$
|
(0.55
|
)
|
|
$
|
0.11
|
|
|
$
|
3.52
|
|
|
$
|
0.39
|
|
|
$
|
0.63
|
|
|
$
|
(0.70
|
)
|
|
$
|
(3.48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in basic earnings (loss) per share
|
|
|
84,665
|
|
|
|
75,569
|
|
|
|
79,206
|
|
|
|
64,316
|
|
|
|
47,287
|
|
|
|
4,059
|
|
|
|
994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
$
|
(0.55
|
)
|
|
$
|
0.10
|
|
|
$
|
3.46
|
|
|
$
|
0.38
|
|
|
$
|
0.59
|
|
|
$
|
(0.70
|
)
|
|
$
|
(3.48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in diluted earnings (loss) per share
|
|
|
84,665
|
|
|
|
77,034
|
|
|
|
80,587
|
|
|
|
66,309
|
|
|
|
50,729
|
|
|
|
4,059
|
|
|
|
994
|
|
|
|
|
|
|
|
|
|
|
|
S-45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group
|
|
|
|
Concho Resources Inc.
|
|
|
Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception (April 21,
|
|
|
Years ended
|
|
|
|
Six months ended June 30,
|
|
|
Years ended December 31,
|
|
|
2004) through
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008a
|
|
|
2007
|
|
|
2006b
|
|
|
2005
|
|
|
December 31,
2004c
|
|
|
2005
|
|
|
2004
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operations
|
|
$
|
118,232
|
|
|
$
|
162,948
|
|
|
$
|
391,397
|
|
|
$
|
169,769
|
|
|
$
|
112,181
|
|
|
$
|
25,070
|
|
|
$
|
(2,193
|
)
|
|
$
|
93,162
|
|
|
$
|
84,202
|
|
Net cash used in investing activities
|
|
|
(162,828
|
)
|
|
|
(142,127
|
)
|
|
|
(946,050
|
)
|
|
|
(160,353
|
)
|
|
|
(596,852
|
)
|
|
|
(61,902
|
)
|
|
|
(122,473
|
)
|
|
|
(35,611
|
)
|
|
|
(30,045
|
)
|
Net cash provided by (used in) financing
|
|
|
29,925
|
|
|
|
(19,529
|
)
|
|
|
541,981
|
|
|
|
19,886
|
|
|
|
476,611
|
|
|
|
45,358
|
|
|
|
125,322
|
|
|
|
(57,551
|
)
|
|
|
(54,157
|
)
|
Capital expenditures on oil and natural gas properties
|
|
|
223,283
|
|
|
|
122,757
|
|
|
|
347,702
|
|
|
|
162,378
|
|
|
|
182,389
|
|
|
|
52,768
|
|
|
|
6,450
|
|
|
|
29,709
|
|
|
|
25,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group
|
|
|
|
Concho Resources Inc.
|
|
|
Properties
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008a
|
|
|
2007
|
|
|
2006b
|
|
|
2005
|
|
|
2004c
|
|
|
2005
|
|
|
2004
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,081
|
|
|
$
|
31,716
|
|
|
$
|
17,752
|
|
|
$
|
30,424
|
|
|
$
|
1,122
|
|
|
$
|
9,182
|
|
|
$
|
656
|
|
|
$
|
|
|
|
$
|
|
|
Property and equipment, net
|
|
|
2,487,166
|
|
|
|
1,475,521
|
|
|
|
2,401,404
|
|
|
|
1,394,994
|
|
|
|
1,320,655
|
|
|
|
170,583
|
|
|
|
115,455
|
|
|
|
149,042
|
|
|
|
135,568
|
|
Total assets
|
|
|
2,764,799
|
|
|
|
1,634,233
|
|
|
|
2,815,203
|
|
|
|
1,508,229
|
|
|
|
1,390,072
|
|
|
|
232,385
|
|
|
|
130,717
|
|
|
|
161,792
|
|
|
|
145,100
|
|
Long-term debt, including current maturities
|
|
|
660,000
|
|
|
|
300,953
|
|
|
|
630,000
|
|
|
|
327,404
|
|
|
|
495,500
|
|
|
|
72,000
|
|
|
|
53,000
|
|
|
|
|
|
|
|
|
|
Equity
|
|
|
1,289,555
|
|
|
|
783,959
|
|
|
|
1,325,154
|
|
|
|
775,398
|
|
|
|
575,156
|
|
|
|
109,670
|
|
|
|
71,710
|
|
|
|
150,814
|
|
|
|
134,014
|
|
|
|
|
|
|
(a)
|
|
The acquisition of the Henry
Entities occurred on July 31, 2008.
|
|
(b)
|
|
The acquisition of the Chase Group
Properties was substantially consummated on February 27,
2006.
|
|
(c)
|
|
The acquisition of the Lowe
Properties was completed on December 7, 2004. See
Selected historical financial and operating
information for Lowe Properties below.
|
S-46
Selected
historical financial and operating information for Lowe
Properties
On December 7, 2004, we acquired the Lowe Properties for
$117 million. The selected financial data below for the
Lowe Properties for the period from January 1, 2004 through
November 30, 2004 were derived from the audited statements
of revenue and direct operating expenses of the Lowe Properties
included in our prospectus dated August 2, 2007 and filed
with the SEC pursuant to Rule 424(b) on August 3, 2007
and information provided by the seller.
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
January 1
|
|
|
|
through
|
|
|
|
November 30,
|
|
(in thousands)
|
|
2004
|
|
|
|
|
Revenues
|
|
$
|
34,663
|
|
Direct operating expenses:
|
|
|
|
|
Lease operating expense
|
|
|
6,983
|
|
Production tax expense
|
|
|
2,159
|
|
Other expenses
|
|
|
461
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
9,603
|
|
|
|
|
|
|
Revenues in excess of direct operating expenses
|
|
$
|
25,060
|
|
|
|
S-47
Managements
discussion and analysis of
financial condition and results of operations
The following discussion is intended to assist in
understanding our business and results of operations together
with our present financial condition. This section should be
read in conjunction with our historical consolidated financial
statements and notes included in our Annual Report on
Form 10-K
for the year ended December 31, 2008 and our Quarterly
Reports on
Form 10-Q
for the quarters ended March 31, 2009 and June 30, 2009,
which are incorporated by reference herein.
During the third quarter of 2008, we closed a significant
acquisition as discussed below. As a result of the acquisition,
many comparisons between periods will be difficult or
impossible. See Items impacting comparability of our
financial results.
Statements in this section may include forward-looking
statements. These forward-looking statements involve risks and
uncertainties. We caution that a number of factors could cause
future production, revenue and expenses to differ materially
from our expectations. See Cautionary statement regarding
forward-looking statements.
Overview
We are an independent oil and natural gas company engaged in the
acquisition, development, exploitation and exploration of
producing oil and natural gas properties. Our operations are
primarily focused in the Permian Basin of Southeast New Mexico
and West Texas. We have also acquired significant acreage
positions in and are actively involved in drilling or
participating in drilling in emerging plays located in the
Permian Basin of Southeast New Mexico and the Williston Basin in
North Dakota, where we are applying horizontal drilling and
advanced fracture stimulation. Oil comprised 62.9 percent
of our 137.3 MMBoe of estimated net proved reserves at
December 31, 2008, and 67.1 percent of our
5.2 MMBoe of production during the six months ended
June 30, 2009. We generally seek to operate the wells in
which we own an interest, and we operated wells that accounted
for 93.1 percent of our proved developed producing
PV-10 at
December 31, 2008 and 65.1 percent of our
3,738 gross wells at June 30, 2009. By controlling
operations, we believe that we are able to more effectively
manage the cost and timing of exploration and development of our
properties, including the drilling, completion and stimulation
methods used.
Commodity
prices
Factors that may impact future commodity prices, including the
price of oil and natural gas, include:
|
|
|
developments generally impacting the Middle East, including Iraq
and Iran;
|
|
|
the extent to which members of the Organization of Petroleum
Exporting Countries and other oil exporting nations are able to
continue to manage oil supply through export quotas;
|
|
|
the overall global demand for oil; and
|
S-48
|
|
|
overall North American natural gas supply and demand
fundamentals, including:
|
|
|
|
|
|
the impact of the decline of the United States economy,
|
|
|
weather conditions, and
|
|
|
liquefied natural gas deliveries to the United States.
|
Although we cannot predict the occurrence of events that may
affect future commodity prices or the degree to which these
prices will be affected, the prices for any commodity that we
produce will generally approximate current market prices in the
geographic region of the production. From time to time, we
expect that we may economically hedge a portion of our commodity
price risk to mitigate the impact of price volatility on our
business.
Oil prices in 2008 were high and particularly volatile compared
to historical prices. In addition, natural gas prices have been
subject to significant fluctuations during the past several
years. In general, oil and natural gas prices were substantially
lower during the comparable periods of 2009 measured against
2008. The following table sets forth the average NYMEX oil and
natural gas prices for the six months ended June 30, 2009
and 2008 and for the years ended December 31, 2008, 2007
and 2006, as well as the high and low NYMEX price for the same
periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
|
Years ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
51.61
|
|
|
$
|
111.02
|
|
|
$
|
99.75
|
|
|
$
|
72.45
|
|
|
$
|
66.26
|
|
Natural gas (per MMBtu)
|
|
$
|
4.15
|
|
|
$
|
10.10
|
|
|
$
|
8.89
|
|
|
$
|
7.11
|
|
|
$
|
6.99
|
|
High/low NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
72.68
|
|
|
$
|
140.21
|
|
|
$
|
145.29
|
|
|
$
|
98.18
|
|
|
$
|
77.03
|
|
Low
|
|
$
|
33.98
|
|
|
$
|
86.99
|
|
|
$
|
33.87
|
|
|
$
|
50.48
|
|
|
$
|
55.81
|
|
Natural gas (per MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
6.07
|
|
|
$
|
13.35
|
|
|
$
|
13.58
|
|
|
$
|
8.64
|
|
|
$
|
11.23
|
|
Low
|
|
$
|
3.25
|
|
|
$
|
7.48
|
|
|
$
|
5.29
|
|
|
$
|
5.38
|
|
|
$
|
4.20
|
|
|
|
Further demonstrating continuing volatility, the NYMEX oil price
and NYMEX natural gas price reached highs and lows of $74.37 and
$59.52 per Bbl and $4.04 and $2.51 per MMBtu, respectively,
during the period from July 1, 2009 to September 8, 2009.
At September 8, 2009, the NYMEX oil price and NYMEX natural
gas price were $71.10 per Bbl and $2.81 MMBtu, respectively.
Henry Entities
acquisition
On July 31, 2008, we closed the acquisition of Henry
Petroleum LP and certain entities affiliated with Henry
Petroleum LP (collectively, the Henry Entities) and
additional non-operated interests in oil and natural gas
properties from persons affiliated with the Henry Entities. In
August 2008 and September 2008, we acquired additional
non-operated interests in oil and natural gas properties from
persons affiliated with the Henry Entities. The assets acquired
in the Henry Entities acquisition, including the additional
non-operated interests, are referred to as the
S-49
Henry Properties. We paid $583.5 million in
cash for the Henry Properties acquisition, which was funded with
borrowings under our credit facility, which was amended and
restated on July 31, 2008, and net proceeds of
approximately $242.4 million from our contemporaneous
private placement of 8,302,894 shares of our common stock.
2009 capital
budget
On November 6, 2008, our board of directors approved the
following capital budget for 2009, predicated on funding it
substantially within our cash flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current 2009
|
|
|
|
Original 2009
|
|
|
planned capital
|
|
(in millions)
|
|
budget
|
|
|
expenditures
|
|
|
|
|
Drilling and recompletion opportunities in our core operating
areas
|
|
$
|
398
|
|
|
$
|
316
|
|
Projects operated by third parties
|
|
|
8
|
|
|
|
5
|
|
Emerging plays, acquisition of leasehold acreage and other
property interests, and geological and geophysical
|
|
|
72
|
|
|
|
60
|
|
Maintenance capital in our core operating areas
|
|
|
22
|
|
|
|
19
|
|
|
|
|
|
|
|
Total 2009 capital budget
|
|
$
|
500
|
|
|
$
|
400
|
|
|
|
In January 2009, in light of the significant drop in commodity
prices during the fourth quarter of 2008, we took actions to
reduce our activities to a level that would allow us to fund our
capital expenditures substantially within our cash flow, which
at the time resulted in estimated annual capital expenditures of
approximately $300 million for 2009. As a result of
improved commodity prices, in particular oil prices, we recently
increased our estimated capital expenditures for 2009 to
approximately $400 million, which we believe we can
substantially fund within our cash flow. We will continue to
monitor our capital expenditures, at least on a quarterly basis,
in relation to our cash flow and expect to adjust our activity
and capital spending level based on changes in commodity prices
and the cost of goods and services and other considerations.
During the first half of 2009, we incurred approximately
$207.0 million of capital expenditures (excluding the
effects of asset retirement obligations and adjustments to the
acquisition of the Henry Properties). These costs were modestly
in excess of our cash flows (including effects of derivative
cash receipts/payments) during that period. For the balance of
2009, we expect to use the remaining approximately
$193 million of our planned capital expenditures to pursue
increased opportunities in our core operating areas along with
targeted opportunities in our emerging plays.
Reaffirmed
borrowing base
We amended our credit agreement on April 7, 2009, to
(i) reaffirm our borrowing base at $960 million;
(ii) add certain provisions relating to defaulting lenders
which, among other things, require us, at the request of the
administrative agent, to cash collateralize or prepay a
defaulting lenders pro rata share of letter of credit and
swingline loan exposure; (iii) amend the calculation of
alternate base rate interest, which is used in connection with
non-Eurodollar rate loans from the greater of (a) the
JPMorgan Chase Bank prime rate or (b) the federal funds
rate plus 0.50% to the greatest of the (x) JPMorgan Chase
Bank prime rate, (y) the federal funds rate plus 0.50% and
(z) the rate for one-month U.S. dollar deposits in the
London interbank market plus 1.00% and (iv) revise the
pricing schedule to increase (a) the Eurodollar rate margin
from a
S-50
range of 1.25% to 2.75% to a range of 2.00% to 3.00% (depending
on the then-current borrowing base usage), (b) the
alternate base rate margin from a range of 0.00% to 1.25% to a
range of 1.125% to 2.125% (depending on the then-current
borrowing base usage), and (c) the unused commitment fee
rate from a range of 0.25% to 0.50% to a flat rate of 0.50%.
Short-term
interruptions in production
During 2008, our production was interrupted on several
occasions. The following describes significant interruptions:
|
|
|
None of our properties and facilities were directly impacted by
Hurricane Ike; however, facilities which ultimately received our
production, primarily natural gas liquids, sustained power
interruptions and physical damage. As a result, our production
was either curtailed or shut-in for significant periods of time.
As a result, we estimate that our September 2008 production was
reduced by approximately 117 MBoe and our October 2008
production was reduced by approximately 33 MBoe.
|
|
|
On May 16, 2008, a refinery located in New Mexico shut down
for ten days due to repairs. As a result, we temporarily shut-in
approximately 37 MBoe of production.
|
|
|
On April 7, 2008, a natural gas processing plant through
which we process and sell a portion of the production from our
New Mexico shelf properties was curtailed for its annual routine
maintenance. The plant resumed full operation on April 19,
2008, and we thereafter began restoring production from all of
our properties that had been affected. Approximately
75 MBoe of our production was shut-in as a result of this
plant shut-down.
|
|
|
During the first quarter of 2008, we experienced short-term
interruptions in our production on our New Mexico shelf
properties due to operational problems with a natural gas
processing plant. There were a total of ten days of curtailment
during the first quarter, and approximately 17 MBoe of our
production was curtailed during this period.
|
Derivative
financial instrument exposure
At June 30, 2009, the fair value of our financial
derivatives was a net asset of $24.3 million. All of our
counterparties to these financial derivatives are parties to our
credit facility and have their outstanding debt commitments and
derivative exposures collateralized pursuant to our credit
facility. Pursuant to the terms of our financial derivative
instruments and their collateralization under our credit
facility, we do not have exposure to potential margin
calls on our financial derivative instruments.
We currently have no reason to believe that our counterparties
to these commodity derivative contracts are not financially
viable. Our credit facility does not allow us to offset amounts
we may owe a lender under our credit facility against amounts we
may be owed related to our derivative financial instruments with
such party.
S-51
New commodity derivative contracts. During the six
months ended June 30, 2009, we entered into additional
commodity derivative contracts to economically hedge a portion
of our estimated future production. The following table
summarizes information about these additional commodity
derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate volume
|
|
|
Index price
|
|
|
Contract period
|
|
|
|
|
Oil (volumes in Bbls):
|
Price collar
|
|
|
600,000
|
|
|
$
|
45.00 $49.00
|
a d
|
|
|
3/1/09 5/31/09
|
|
Price swap
|
|
|
270,000
|
|
|
$
|
69.50
|
a
|
|
|
7/1/09 9/30/09
|
|
Price swap
|
|
|
540,000
|
|
|
$
|
51.62
|
a d
|
|
|
7/1/09 12/31/09
|
|
Price swap
|
|
|
150,000
|
|
|
$
|
69.50
|
a
|
|
|
10/1/09 12/31/09
|
|
Price swap
|
|
|
2,508,000
|
|
|
$
|
62.15
|
a d
|
|
|
1/1/10 12/31/10
|
|
Price swap
|
|
|
1,800,000
|
|
|
$
|
72.17
|
a d
|
|
|
1/1/11 12/31/11
|
|
Natural gas (volumes in MMBtus):
|
Price collar
|
|
|
1,500,000
|
|
|
$
|
5.00 $5.81
|
b
|
|
|
10/1/09 12/31/09
|
|
Price collar
|
|
|
1,500,000
|
|
|
$
|
5.00 $5.81
|
b
|
|
|
1/1/10 3/31/10
|
|
Price collar
|
|
|
3,000,000
|
|
|
$
|
5.25 $5.75
|
b
|
|
|
4/1/10 9/30/10
|
|
Price collar
|
|
|
1,500,000
|
|
|
$
|
6.00 $6.80
|
b
|
|
|
10/1/10 12/31/10
|
|
Price collar
|
|
|
1,500,000
|
|
|
$
|
6.00 $6.80
|
b
|
|
|
1/1/11 3/31/11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
3,000,000
|
|
|
$
|
4.31
|
b
|
|
|
4/1/09 9/30/09
|
|
Price swap
|
|
|
600,000
|
|
|
$
|
4.66
|
b
|
|
|
7/1/09 9/30/09
|
|
Price swap
|
|
|
450,000
|
|
|
$
|
4.66
|
b
|
|
|
10/1/09 12/31/09
|
|
Price swap
|
|
|
2,400,000
|
|
|
$
|
6.31
|
b
|
|
|
1/1/10 12/31/10
|
|
Price swap
|
|
|
300,000
|
|
|
$
|
7.29
|
b
|
|
|
1/1/11 3/31/11
|
|
Price swap
|
|
|
5,400,000
|
|
|
$
|
6.96
|
b d
|
|
|
4/1/11 12/31/11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swap
|
|
|
600,000
|
|
|
$
|
0.79
|
c
|
|
|
7/1/09 9/30/09
|
|
Basis swap
|
|
|
450,000
|
|
|
$
|
0.89
|
c
|
|
|
10/1/09 12/31/09
|
|
Basis swap
|
|
|
8,400,000
|
|
|
$
|
0.85
|
c d
|
|
|
1/1/10 12/31/10
|
|
Basis swap
|
|
|
1,800,000
|
|
|
$
|
0.87
|
c d
|
|
|
1/1/11 3/31/11
|
|
Basis swap
|
|
|
5,400,000
|
|
|
$
|
0.76
|
c
|
|
|
4/1/11 12/31/11
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
swaps and collars are based on the NYMEX-West Texas Intermediate
monthly average futures price.
|
|
(b)
|
|
The index price for the natural gas
price swaps and collars are based on the NYMEX-Henry Hub last
trading day futures price.
|
|
(c)
|
|
Represents the basis differential
between the El Paso Permian delivery point and NYMEX Henry
Hub delivery point.
|
|
(d)
|
|
Prices represent weighted-average
prices.
|
After June 30, 2009, we entered into the following oil
price swaps to hedge an additional portion of our estimated oil
production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate volume
|
|
|
Index price
|
|
|
Contract period
|
|
|
|
|
Oil (volumes in Bbls):
|
Price swap
|
|
|
273,000
|
|
|
$
|
67.50
|
a
|
|
|
8/1/09 12/31/09
|
|
Price swap
|
|
|
799,000
|
|
|
$
|
67.50
|
a
|
|
|
1/1/10 12/31/10
|
|
Price swap
|
|
|
801,000
|
|
|
$
|
70.53
|
a b
|
|
|
1/1/11 12/31/11
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price.
|
|
(b)
|
|
Prices represent weighted-average
prices.
|
S-52
Items impacting
comparability of our financial results
Our historical results of operations for the periods presented
may not be comparable, either from period to period or going
forward, for the reasons described below:
|
|
|
On February 24, 2006, we entered into a combination
agreement in which we agreed to purchase the Chase Group
Properties and combine them with substantially all of the
outstanding equity interests of Concho Equity Holdings Corp. to
form Concho. We have accounted for the combination
transaction that occurred on February 27, 2006, as an
acquisition by Concho Equity Holdings Corp. of the Chase Group
Properties and a simultaneous reorganization of Concho such that
Concho Equity Holdings Corp. became our wholly owned subsidiary.
Concho Equity Holdings Corp. is our predecessor for accounting
purposes. As a result, our historical financial statements prior
to February 27, 2006, are the financial statements of
Concho Equity Holdings Corp.
|
|
|
On February 27, 2006, the initial closing of the Chase Oil
transaction occurred, and we acquired the Chase Group Properties
for approximately 35 million shares of common stock and
approximately $409 million in cash.
|
|
|
On March 27, 2007, we entered into a $200 million
second lien term loan facility from which we received proceeds
of $199 million that we used to repay the
$39.8 million outstanding under our prior term loan
facility and to reduce the outstanding balance under our credit
facility by $154 million, with the remaining
$5.2 million used to pay loan fees, accrued interest and
for general corporate purposes.
|
|
|
In August 2007, we completed our initial public offering of
common stock from which we received proceeds of
$173 million that we used to retire outstanding borrowings
under our second lien term loan facility totaling
$86.5 million, and to retire outstanding borrowings under
our credit facility totaling $86.5 million.
|
|
|
On July 31, 2008, we closed our acquisition of the Henry
Entities and additional non-operated interests in oil and gas
properties from persons affiliated with the Henry Entities. In
August 2008 and September 2008, we acquired additional
non-operated interests in oil and gas properties from persons
affiliated with the Henry Entities. We paid approximately
$583.5 million in net cash for the acquisition of the Henry
Entities and the related acquisition of the along-side
interests, which was funded with borrowings under our credit
facility, which was amended and restated on July 31, 2008,
and net proceeds of approximately $242.4 million from our
private placement of 8,302,894 shares of our common stock.
|
S-53
Results of
operations
The following table presents selected financial and operating
information for the years ended December 31, 2008, 2007 and
2006 and for the six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended
|
|
|
|
|
|
|
June 30,
|
|
|
Years ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
3,518
|
|
|
|
1,786
|
|
|
|
4,586
|
|
|
|
3,014
|
|
|
|
2,295
|
|
Natural gas (MMcf)
|
|
|
10,369
|
|
|
|
6,451
|
|
|
|
14,968
|
|
|
|
12,064
|
|
|
|
9,507
|
|
Total (MBoe)
|
|
|
5,246
|
|
|
|
2,861
|
|
|
|
7,081
|
|
|
|
5,025
|
|
|
|
3,880
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
19,436
|
|
|
|
9,813
|
|
|
|
12,530
|
|
|
|
8,258
|
|
|
|
6,288
|
|
Natural gas (Mcf)
|
|
|
57,287
|
|
|
|
35,445
|
|
|
|
40,896
|
|
|
|
33,052
|
|
|
|
26,047
|
|
Total (Boe)
|
|
|
28,984
|
|
|
|
15,721
|
|
|
|
19,347
|
|
|
|
13,767
|
|
|
|
10,630
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without hedges (Bbl)
|
|
$
|
47.32
|
|
|
$
|
107.39
|
|
|
$
|
91.92
|
|
|
$
|
68.58
|
|
|
$
|
60.47
|
|
Oil, with
hedgesa
(Bbl)
|
|
$
|
47.32
|
|
|
$
|
95.87
|
|
|
$
|
85.25
|
|
|
$
|
64.90
|
|
|
$
|
57.42
|
|
Natural gas, without hedges (Mcf)
|
|
$
|
4.52
|
|
|
$
|
11.33
|
|
|
$
|
9.59
|
|
|
$
|
8.08
|
|
|
$
|
6.87
|
|
Natural gas, with
hedgesa
(Mcf)
|
|
$
|
4.52
|
|
|
$
|
11.30
|
|
|
$
|
9.54
|
|
|
$
|
8.18
|
|
|
$
|
7.00
|
|
Total, without hedges (Boe)
|
|
$
|
40.67
|
|
|
$
|
92.59
|
|
|
$
|
79.80
|
|
|
$
|
60.54
|
|
|
$
|
52.62
|
|
Total, with
hedgesa
(Boe)
|
|
$
|
40.67
|
|
|
$
|
85.32
|
|
|
$
|
75.38
|
|
|
$
|
58.56
|
|
|
$
|
51.12
|
|
|
|
|
|
|
(a)
|
|
These prices do not reflect the
cash receipts/payments related to the oil and natural gas
derivatives that were not designated as hedges and are reflected
in gain (loss) on derivatives not designated as hedges in our
statements of operations. If the cash receipts/payments related
to the oil and natural gas derivatives that were not designated
as hedges were included in our oil and natural gas sales, our
oil and natural gas prices would be as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
|
|
|
|
Six months ended June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Oil (Bbl)
|
|
$
|
63.36
|
|
|
$
|
86.93
|
|
|
$
|
83.55
|
|
|
$
|
64.90
|
|
|
$
|
57.42
|
|
Natural gas (Mcf)
|
|
$
|
5.08
|
|
|
$
|
11.23
|
|
|
$
|
9.64
|
|
|
$
|
8.33
|
|
|
$
|
7.00
|
|
Total (Boe)
|
|
$
|
52.53
|
|
|
$
|
79.59
|
|
|
$
|
74.49
|
|
|
$
|
58.93
|
|
|
$
|
51.12
|
|
|
|
The presentation above provides the effect of our oil and
natural gas derivatives program without consideration for the
financial presentation of the cash receipts/payments on the oil
and natural gas derivatives.
Six months ended
June 30, 2009 compared to six months ended June 30,
2008
Oil and natural gas revenues. Revenue from oil and
natural gas operations was $213.3 million for the six
months ended June 30, 2009, a decrease of
$30.8 million (13 percent) from $244.1 million
for the six months ended June 30, 2008. This decrease was
primarily due to substantial decreases in realized oil and
natural gas prices, offset by increased production (i) as a
result of the acquisition of the Henry Properties on
July 31, 2008 and (ii) due to successful drilling
efforts during 2008 and 2009. Specifically the:
|
|
|
average realized oil price (after giving effect to hedging
activities) was $47.32 per Bbl during the six months ended
June 30, 2009, a decrease of 51 percent from $95.87
per Bbl during the six months ended June 30, 2008;
|
|
|
total oil production was 3,518 MBbl for the six months
ended June 30, 2009, an increase of 1,732 MBbl
(97 percent) from 1,786 MBbl for the six months ended
June 30, 2008;
|
S-54
|
|
|
average realized natural gas price (after giving effect to
hedging activities) was $4.52 per Mcf during the six months
ended June 30, 2009, a decrease of 60 percent from
$11.30 per Mcf during the six months ended June 30, 2008;
|
|
|
total natural gas production was 10,369 MMcf for the six
months ended June 30, 2009, an increase of 3,918 MMcf
(61 percent) from 6,451 MMcf for the six months ended
June 30, 2008;
|
|
|
average realized barrel of oil equivalent price (after giving
effect to hedging activities) was $40.67 per Boe during the six
months ended June 30, 2009, a decrease of 52 percent
from $85.32 per Boe during the six months ended June 30,
2008; and
|
|
|
total production was 5,246 MBoe for the six months ended
June 30, 2009, an increase of 2,385 MBoe
(83 percent) from 2,861 MBoe for the six months ended
June 30, 2008.
|
Hedging activities. The oil and natural gas prices
that we report are based on the market price received for the
commodities adjusted to give effect to the results of our cash
flow hedging activities. We utilize commodity derivative
instruments in order to (i) reduce the effect of the
volatility of price changes on the commodities we produce and
sell, (ii) support our capital budget and expenditure plans
and (iii) support the economics associated with
acquisitions.
Currently, we do not designate our derivative instruments to
qualify for hedge accounting. Accordingly, we reflect the
changes in the fair value of our derivative instruments in the
statements of operations as (gain) loss on derivatives not
designated as hedges. All of our remaining hedges that
historically qualified or were dedesignated from hedge
accounting were settled in 2008.
The following is a summary of the effects of commodity hedges
that qualify for hedge accounting treatment for the six months
ended June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil hedges
|
|
|
Natural gas hedges
|
|
|
|
Six months ended
|
|
|
Six months ended
|
|
|
|
June 30, 2008
|
|
|
June 30, 2008
|
|
|
|
|
Hedging revenue increase (decrease) (in thousands)
|
|
$
|
(20,573
|
)
|
|
$
|
(222
|
)
|
Hedged volumes (Bbls and MMBtus, respectively)
|
|
|
473,000
|
|
|
|
2,457,000
|
|
Hedged revenue decrease per hedged volume
|
|
$
|
(43.49
|
)
|
|
$
|
(0.09
|
)
|
|
|
Production expenses. The following tables provide
the components of our total oil and natural gas production costs
for the six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
(in thousands, except per unit
amounts)
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
|
Lease operating expenses
|
|
$
|
32,294
|
|
|
$
|
6.16
|
|
|
$
|
16,238
|
|
|
$
|
5.68
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
2,491
|
|
|
|
0.47
|
|
|
|
1,006
|
|
|
|
0.35
|
|
Production
|
|
|
15,365
|
|
|
|
2.93
|
|
|
|
21,108
|
|
|
|
7.38
|
|
Workover costs
|
|
|
433
|
|
|
|
0.08
|
|
|
|
522
|
|
|
|
0.18
|
|
|
|
|
|
|
|
Total oil and gas production expenses
|
|
$
|
50,583
|
|
|
$
|
9.64
|
|
|
$
|
38,874
|
|
|
$
|
13.59
|
|
|
|
S-55
Among the cost components of production expenses, in general, we
have some control over lease operating expenses and workover
costs on properties we operate, but production and ad valorem
taxes are directly related to commodity price changes.
Lease operating expenses were $32.3 million ($6.16 per Boe)
for the six months ended June 30, 2009, an increase of
$16.1 million (99 percent) from $16.2 million
($5.68 per Boe) for the six months ended June 30, 2008. The
increase in lease operating expenses is due to (i) the
wells acquired in the Henry Properties acquisition, which
increased the absolute and per unit amount because those wells
have a higher per unit cost as compared to our historical per
unit cost and (ii) our wells successfully drilled and
completed in 2008 and 2009.
Ad valorem taxes have increased primarily as a result of the
Henry Properties acquisition, which were highly concentrated in
Texas, a state which has a higher ad valorem rate than New
Mexico, where substantially all of our properties prior to the
acquisition were located.
Production taxes per unit of production were $2.93 per Boe
during the six months ended June 30, 2009, a decrease of
60 percent from $7.38 per Boe during the six months ended
June 30, 2008. The decrease is directly related to the
decrease in commodity prices offset by the increase in oil and
natural gas revenues related to increased volumes. Over the same
period, our Boe prices (before the effects of hedging) decreased
56 percent.
Workover expenses were approximately $0.4 million and
$0.5 million for the six months ended June 30, 2009
and 2008, respectively. The 2009 and 2008 amounts related
primarily to workovers in Andrews County, Texas.
Exploration and abandonments expense. The following
table provides a breakdown of our exploration and abandonments
expense for the six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
(in thousands)
|
|
2009
|
|
|
2008
|
|
|
|
|
Geological and geophysical
|
|
$
|
1,125
|
|
|
$
|
2,317
|
|
Exploratory dry holes
|
|
|
1,866
|
|
|
|
(1
|
)
|
Leasehold abandonments and other
|
|
|
4,428
|
|
|
|
1,148
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$
|
7,419
|
|
|
$
|
3,464
|
|
|
|
Our geological and geophysical expense, which primarily consists
of the costs of acquiring and processing seismic data,
geophysical data and core analysis, during the six months ended
June 30, 2009, was $1.1 million, a decrease of
$1.2 million from $2.3 million for the six months
ended June 30, 2008. This decrease is primarily
attributable to a comprehensive seismic survey on our New Mexico
shelf properties which was initiated in December 2007 and
completed in 2008.
During the six months ended June 30, 2009, we wrote-off an
unsuccessful exploratory well in our Arkansas emerging play and
two unsuccessful exploratory wells in our Texas Permian area.
For the six months ended June 30, 2009, we recorded
approximately $4.4 million of leasehold abandonments, which
relate primarily to the write-off of four non-core prospects in
New Mexico and three non-core prospects in Texas. For the six
months ended June 30, 2008, we recorded $1.1 million
of leasehold abandonments, which were primarily related to
non-core prospects in Chaves and Eddy Counties, New Mexico, and
Andrews and Crane Counties, Texas.
S-56
Depreciation, depletion and amortization
expense. The following table provides components of our
depreciation, depletion and amortization expense for the six
months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
(in thousands, except per unit
amounts)
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
100,995
|
|
|
$
|
19.25
|
|
|
$
|
42,510
|
|
|
$
|
14.86
|
|
Depreciation of property and equipment
|
|
|
1,374
|
|
|
|
0.26
|
|
|
|
784
|
|
|
|
0.27
|
|
Amortization of intangible assetoperating rights
|
|
|
781
|
|
|
|
0.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
$
|
103,150
|
|
|
$
|
19.66
|
|
|
$
|
43,294
|
|
|
$
|
15.13
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end
|
|
$
|
66.25
|
|
|
|
|
|
|
$
|
136.50
|
|
|
|
|
|
Natural gas price used to estimate proved gas reserves at period
end
|
|
$
|
3.72
|
|
|
|
|
|
|
$
|
13.10
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties was
$101.0 million ($19.25 per Boe) for the six months ended
June 30, 2009, an increase of $58.5 million from
$42.5 million ($14.86 per Boe) for the six months ended
June 30, 2008. The increase in depletion expense, on a
total and per Boe basis, was primarily due to (i) the Henry
Properties acquisition, for which the depletion rate was higher
than that of our historical assets, (ii) capitalized costs
associated with new wells that were successfully drilled and
completed in 2008 and 2009 and (iii) the decrease in the
oil and natural gas prices between the years utilized to
determine proved reserves.
The amortization of the intangible asset is a result of the
value assigned to the operating rights that we acquired in the
Henry Properties acquisition. The intangible asset is currently
being amortized over an estimated life of approximately
25 years.
Impairment of long-lived assets. We periodically
review our long-lived assets to be held and used, including
proved oil and natural gas properties accounted for under the
successful efforts method of accounting. Due to downward
adjustments to the economically recoverable resource potential
associated with declines in commodity prices and well
performance, we recognized a non-cash charge against earnings of
$8.6 million, which was primarily attributable to non-core
natural gas related properties in Eddy and Lea Counties, New
Mexico. For the six months ended June 30, 2008, we
recognized a non-cash charge against earnings of
$0.07 million, which was primarily attributable to a
non-core lease located in Eddy and Lea Counties, New Mexico.
S-57
General and administrative expenses. The following
table provides components of our general and administrative
expenses for the six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
(in thousands, except per unit
amounts)
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
|
General and administrative expensesrecurring
|
|
$
|
21,939
|
|
|
$
|
4.18
|
|
|
$
|
13,741
|
|
|
$
|
4.80
|
|
Non-recurring bonus paid to former Henry Entities employees
|
|
|
5,311
|
|
|
|
1.01
|
|
|
|
|
|
|
|
|
|
Non-cash stock-based compensationstock options
|
|
|
1,913
|
|
|
|
0.36
|
|
|
|
2,167
|
|
|
|
0.76
|
|
Non-cash stock-based compensationrestricted stock
|
|
|
2,200
|
|
|
|
0.42
|
|
|
|
862
|
|
|
|
0.30
|
|
Less: third-party fee reimbursements
|
|
|
(5,445
|
)
|
|
|
(1.04
|
)
|
|
|
(504
|
)
|
|
|
(0.17
|
)
|
|
|
|
|
|
|
Total general and administrative expenses
|
|
$
|
25,918
|
|
|
$
|
4.93
|
|
|
$
|
16,266
|
|
|
$
|
5.69
|
|
|
|
General and administrative expenses were $25.9 million
($4.93 per Boe) for the six months ended June 30, 2009, an
increase of $9.6 million (59 percent) from
$16.3 million ($5.69 per Boe) for the six months ended
June 30, 2008. The increase in general and administrative
expenses during the six months ended June 30, 2009 over
2008 was primarily due to (i) the non-recurring bonus paid
to former Henry Entities employees, (ii) an increase
in non-cash stock-based compensation for both stock options and
restricted stock awards and (iii) an increase in the number
of employees and related personnel expenses, partially offset by
an increase in third-party operating fee reimbursements.
In connection with the Henry Entities acquisition, we agreed to
pay certain of our employees, who were formerly Henry
Entities employees, a predetermined bonus amount, in
addition to the compensation we pay these employees over the
next two years. Since these employees will earn this bonus over
the next two years, we are reflecting the cost in our general
and administrative costs as non-recurring, as it is not
controlled by us.
We earn reimbursements as operator of certain oil and natural
gas properties in which we own interests. As such, we earned
reimbursements of $5.4 million and $0.5 million during
the six months ended June 30, 2009 and 2008, respectively.
This reimbursement is reflected as a reduction of general and
administrative expenses in the consolidated statements of
operations. The increase in this reimbursement is directly
related to the Henry Properties acquisition, as we own a lower
working interest in these operated properties compared to our
historical property base, so we receive a larger third-party
reimbursement as compared to our historical property base.
Bad debt expense. On May 20, 2008, we entered
into a short-term purchase agreement with an oil purchaser to
buy a portion of our oil affected as a result of the New Mexico
refinery shut down due to repairs. On July 22, 2008, this
purchaser declared bankruptcy. We fully reserved the receivable
amount due from this purchaser of approximately
$1.8 million as of June 30, 2008, and are pursuing our
claim in the bankruptcy proceedings.
Loss on derivatives not designated as hedges. During
the six months ended June 30, 2007, we determined that all
of our natural gas commodity derivative contracts no longer
qualified as hedges. Because we no longer considered these
hedges to be highly effective, we discontinued hedge accounting
for those existing hedges, prospectively, and during the period
the hedges became ineffective. In addition, for our new
commodity and interest rate derivative contracts
S-58
entered into after August 2007, we chose not to designate any of
these contracts as hedges. As a result, any changes in fair
value and any cash settlements related to these contracts are
recorded in earnings during the related period. All amounts
previously recorded in accumulated other comprehensive income
were reclassified to earnings prior to 2009.
The following table sets forth the cash receipts for settlements
and the non-cash
mark-to-market
adjustment for the derivative contracts not designated as hedges
for the six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
(in thousands)
|
|
2009
|
|
|
2008
|
|
|
|
|
Cash payments (receipts):
|
|
|
|
|
|
|
|
|
Commodity derivativesoil
|
|
$
|
(56,412
|
)
|
|
$
|
15,965
|
|
Commodity derivativesnatural gas
|
|
|
(5,832
|
)
|
|
|
422
|
|
Financial derivativesinterest
|
|
|
779
|
|
|
|
|
|
Mark-to-market
(gain) loss:
|
|
|
|
|
|
|
|
|
Commodity derivativesoil
|
|
|
144,099
|
|
|
|
88,900
|
|
Commodity derivativesnatural gas
|
|
|
5,018
|
|
|
|
14,347
|
|
Financial derivativesinterest
|
|
|
(1,000
|
)
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not designated as hedges
|
|
$
|
86,652
|
|
|
$
|
119,634
|
|
|
|
Interest expense. Interest expense was
$10.6 million for the six months ended June 30, 2009,
an increase of $1.1 million from $9.5 million for the
six months ended June 30, 2008. The weighted average
interest rate for the six months ended June 30, 2009 and
2008 was 2.5% and 5.8%, respectively. The weighted average debt
balance during the six months ended June 30, 2009 and 2008
was approximately $668.0 million and $313.3 million,
respectively.
The increase in weighted average debt balance during the six
months ended June 30, 2009 was due primarily to borrowings
in July 2008 for the acquisition of the Henry Properties. The
increase in interest expense is due to an increase in the
weighted average debt balance offset by a decrease in the
weighted average interest rate. The decrease in the weighted
average interest rate is primarily due to an improvement in
market interest rates.
Income tax provisions. We recorded an income tax
benefit of $33.8 million and income tax expense of
$5.2 million for the six months ended June 30, 2009
and 2008, respectively. The effective income tax rate for the
six months ended June 30, 2009 and 2008 was
42.1 percent and 39.6 percent, respectively. The
higher effective tax rate in 2009 compared to 2008 is primarily
due to the estimated annual 2009 permanent tax differences
compared to the related current estimated pre-tax book income.
Year ended
December 31, 2008 compared to year ended December 31,
2007
Oil and gas revenues. Revenue from oil and gas
operations was $533.8 million for the year ended
December 31, 2008, an increase of $239.5 million
(81 percent) from $294.3 million for the year ended
December 31, 2007. This increase was primarily due to
(i) the acquisition of the
S-59
Henry Entities on July 31, 2008, (ii) increased
production due to successful drilling efforts during 2008 and
(iii) substantial increases in realized oil and gas prices.
In addition:
|
|
|
average realized oil prices (after giving effect to hedging
activities) were $85.25 per Bbl during the year ended
December 31, 2008, an increase of 31 percent from
$64.90 per Bbl during the year ended December 31, 2007;
|
|
|
total oil production was 4,586 MBbl for the year ended
December 31, 2008, an increase of 1,572 MBbl
(52 percent) from 3,014 MBbl for the year ended
December 31, 2007;
|
|
|
average realized natural gas prices (after giving effect to
hedging activities) were $9.54 per Mcf during the year ended
December 31, 2008, an increase of 17 percent from
$8.18 per Mcf during the year ended December 31, 2007;
|
|
|
total natural gas production was 14,968 MMcf for the year
ended December 31, 2008, an increase of 2,904 MMcf
(24 percent) from 12,064 MMcf for the year ended
December 31, 2007;
|
|
|
average realized barrel of oil equivalent prices (after giving
effect to hedging activities) were $75.38 per Boe during the
year ended December 31, 2008, an increase of
29 percent from $58.56 per Boe during the year ended
December 31, 2007; and
|
|
|
total production was 7,081 MBoe for the year ended
December 31, 2008, an increase of 2,056 MBoe
(41 percent) from 5,025 MBoe for the year ended
December 31, 2007.
|
Hedging activities. The oil and gas prices that we
report are based on the market price received for the
commodities adjusted to give effect to the results of our cash
flow hedging activities. We utilize commodity derivative
instruments in order to (i) reduce the effect of the
volatility of price changes on the commodities we produce and
sell, (ii) support our annual capital budget and
expenditure plans and (iii) lock-in commodity prices to
protect economics related to certain capital projects. The
following is a summary of the effects of commodity hedges that
qualify for hedge accounting treatment for the year ended
December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil hedges
|
|
|
Natural gas hedges
|
|
|
|
Years ended December 31,
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Hedging revenue increase (decrease) (in thousands)
|
|
$
|
(30,591
|
)
|
|
$
|
(11,091
|
)
|
|
$
|
(696
|
)
|
|
$
|
1,291
|
|
Hedged volumes (Bbls and MMBtus, respectively)
|
|
|
951,000
|
|
|
|
1,076,750
|
|
|
|
4,941,000
|
|
|
|
6,482,600
|
|
Hedged revenue increase (decrease) per hedged volume
|
|
$
|
(32.17
|
)
|
|
$
|
(10.30
|
)
|
|
$
|
(0.14
|
)
|
|
$
|
0.20
|
|
|
|
During the year ended December 31, 2008, our commodity
price hedges decreased oil revenues by $30.6 million ($6.67
per Bbl). During the year ended December 31, 2007, our
commodity price hedges decreased oil revenues by
$11.1 million ($3.68 per Bbl). The effect of the commodity
price hedges in decreasing oil revenues during the year ended
December 31, 2008 compared to their effect of decreasing
oil revenues during the year ended December 31, 2007 was
the result of (i) a higher average market price of NYMEX
oil of $99.75 per Bbl in 2008 as compared to $72.45 per Bbl in
2007 and (ii) the greater price difference between NYMEX
and the weighted
S-60
average hedge price in 2008 as compared to 2007, partially
offset by a lower amount of hedged volumes of 951,000 Bbls
in 2008 as compared to 1,076,750 Bbls in 2007.
During the year ended December 31, 2008, our commodity
price hedges decreased gas revenues by $0.7 million ($0.05
per Mcf) as a result of the amount reclassified from accumulated
other comprehensive income (AOCI) into natural gas
revenues from cash flow hedges that were dedesignated at
June 30, 2007. Cash settlements for these dedesignated
natural gas contracts were recorded as a gain on derivatives not
designated as hedges. During the year ended December 31,
2007, our commodity price hedges increased gas revenues by
$1.3 million ($0.11 per Mcf) primarily as a result of the
amount reclassified from AOCI to natural gas revenues from cash
flow hedges that were dedesignated at June 30, 2007.
At June 30, 2007, we determined that all of our natural gas
commodity contracts no longer qualified as hedges under the
requirements of Financial Accounting Standards Board
(FASB) Statement of Financial Accounting Standards
(SFAS) No. 133. As a result, amounts in AOCI at
June 30, 2007 related to these dedesignated hedges remained
in AOCI and are reclassified into earnings under natural gas
revenues during the periods which the hedged forecasted
transaction affects earnings. Cash settlements for these natural
gas contracts are recorded to gains (losses) on derivatives not
designated as hedges. Regarding the dedesignated contracts, for
the period January 1, 2007 through June 30, 2007, when
these natural gas contracts qualified to use hedge accounting,
the cash settlement receipts of approximately $0.2 million
were recorded in natural gas revenues. For the period
July 1, 2007 through December 31, 2007, when these
natural gas contracts no longer qualified to use hedge
accounting, a pre-tax amount of $1.1 million was
reclassified from AOCI to natural gas revenues and cash
settlement receipts of $1.8 million was recorded to gains (
losses) on derivatives not designated as hedge.
The above discussion on hedging activities does not represent
the activities from all of our commodity derivative instruments.
We have other commodity derivative instruments that we do not
designate as hedges for accounting purposes.
Oil and gas production costs. The following tables
provide the components of our oil and gas production costs for
the year ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
(in thousands, except per unit
amounts)
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
|
Lease operating expenses
|
|
$
|
43,725
|
|
|
$
|
6.17
|
|
|
$
|
26,480
|
|
|
$
|
5.27
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
2,738
|
|
|
|
0.39
|
|
|
|
2,012
|
|
|
|
0.40
|
|
Production
|
|
|
43,775
|
|
|
|
6.18
|
|
|
|
24,301
|
|
|
|
4.84
|
|
Workover costs
|
|
|
996
|
|
|
|
0.14
|
|
|
|
1,474
|
|
|
|
0.29
|
|
|
|
|
|
|
|
Total oil and gas production expenses
|
|
$
|
91,234
|
|
|
$
|
12.88
|
|
|
$
|
54,267
|
|
|
$
|
10.80
|
|
|
|
Among the cost components of production expenses, in general, we
have control over lease operating expenses and workover costs on
properties we operate, but production and ad valorem taxes are
directly related to commodity price changes.
Lease operating expenses were $43.7 million ($6.17 per Boe)
for the year ended December 31, 2008, an increase of
$17.2 million (65 percent) from $26.5 million
($5.27 per Boe) for the year ended December 31, 2007. The
increase in lease operating expenses is due to (i) the
wells
S-61
acquired in the Henry Properties acquisition, which increased
the absolute and per unit amount because those wells have a
higher per unit cost as compared to our historical per unit
cost, (ii) our wells successfully drilled and completed in
2008 and (iii) general inflation of field service and
supply costs associated with rising commodity prices.
Ad valorem taxes have increased primarily as a result of
(i) the Henry Properties acquisition and (ii) the
increase in commodity prices.
Production taxes per unit of production were $6.18 per Boe
during the year ended December 31, 2008, an increase of
28 percent from $4.84 per Boe during the year ended
December 31, 2007. The increase is directly related to the
increase in oil and gas revenues and the related increase in
commodity prices. Over the same period our Boe prices (before
the effects of hedging) increased 32 percent.
Workover expenses were $1.0 million and $1.5 million
for the year ended December 31, 2008 and 2007,
respectively. The 2008 amount related primarily to workovers in
Andrews County, Texas, while the 2007 amount related to a
workover project on a property located in Gaines County, Texas.
Exploration and abandonments expense. The following
table provides a breakdown of our exploration and abandonments
expense for the year ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
(in thousands)
|
|
2008
|
|
|
2007
|
|
|
|
|
Geological and geophysical
|
|
$
|
3,139
|
|
|
$
|
4,089
|
|
Exploratory dry holes
|
|
|
3,723
|
|
|
|
21,923
|
|
Leasehold abandonments and other
|
|
|
31,606
|
|
|
|
3,086
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$
|
38,468
|
|
|
$
|
29,098
|
|
|
|
Our geological and geophysical expense, which primarily consists
of the costs of acquiring and processing seismic data,
geophysical data and core analysis, during the year ended
December 31, 2008 was $3.1 million, a decrease of
$1.0 million from $4.1 million for the year ended
December 31, 2007. This decrease is primarily attributable
to a comprehensive seismic survey on our New Mexico shelf
properties which was initiated in December 2007.
Our exploratory dry hole expense during the year ended
December 31, 2008 is primarily attributable to an
unsuccessful operated exploratory well located in the Central
Basin Platform. Our exploratory dry hole expense during the year
ended December 31, 2007 is primarily attributable to five
unsuccessful operated exploratory wells.
The costs associated with three of these wells drilled in the
Western Delaware Basin in Culberson County, Texas, approximated
$17.0 million. Another of these wells, which was drilled in
Lea County, New Mexico, had costs of approximately
$2.4 million. An additional $0.8 million was charged
to exploratory dry hole costs relative to a target zone in the
fifth of these wells in Eddy County, New Mexico, which was
determined to be unsuccessful.
For the year ended December 31, 2008, we recorded
$31.6 million of leasehold abandonments, which relates
primarily to the write-off of (i) our Fayetteville acreage
position in Arkansas and (ii) a prospect in the Central
Basin Platform in West Texas. For the year ended
December 31, 2007, we recorded $3.1 million of
leasehold abandonments, of which $0.7 million related to a
prospect in Lea County, New Mexico, $0.8 million related to
one prospect located in Edwards
S-62
County, Texas, and $0.5 million related to leasehold
expiring in Southeast New Mexico. The remaining
$1.1 million was related to several individually minor
leaseholds.
Depreciation, depletion and amortization
expense. The following table provides components of our
depreciation, depletion and amortization expense for the year
ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
(in thousands, except per unit
amounts)
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
121,464
|
|
|
$
|
17.15
|
|
|
$
|
75,744
|
|
|
$
|
15.07
|
|
Depreciation of property and equipment
|
|
|
1,808
|
|
|
|
0.26
|
|
|
|
1,035
|
|
|
|
0.21
|
|
Amortization of intangible assetoperating rights
|
|
|
640
|
|
|
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
$
|
123,912
|
|
|
$
|
17.50
|
|
|
$
|
76,779
|
|
|
$
|
15.28
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end
|
|
$
|
41.00
|
|
|
|
|
|
|
$
|
92.50
|
|
|
|
|
|
Natural gas price used to estimate proved gas reserves at period
end
|
|
$
|
5.71
|
|
|
|
|
|
|
$
|
6.80
|
|
|
|
|
|
|
|
Depletion of proved oil and gas properties was
$121.5 million ($17.15 per Boe) for the year ended
December 31, 2008, an increase of $45.8 million from
$75.7 million ($15.07 per Boe) for the year ended
December 31, 2007. The increase in depletion expense was
primarily due to (i) the Henry Properties acquisition for
which the depletion rate was higher than that of our historical
assets, (ii) capitalized costs associated with new wells
that were successfully drilled and completed in 2007 and 2008
and (iii) the decrease in the oil and natural gas prices
between the years which were utilized to determine the proved
reserves.
The amortization of the intangible asset is a result of the
value assigned to the operating rights that we acquired in the
Henry Properties acquisition. The intangible asset is currently
being amortized over an estimated life of approximately
25 years.
Impairment of long-lived assets. In accordance with
SFAS No. 144, we periodically review our long-lived
assets to be held and used, including proved oil and gas
properties accounted for under the successful efforts method of
accounting. As a result of this review of the recoverability of
the carrying value of our assets during the year ended
December 31, 2008, we recognized a non-cash charge against
earnings of $18.4 million, which was comprised primarily of
fields in Reeves and Upton Counties, Texas and in North Dakota.
For the year ended December 31, 2007, we recognized a
non-cash charge against earnings of $7.3 million,
33 percent of which related to a field in Gaines County,
Texas, 30 percent of which related to a field in Schleicher
County, Texas, and 18 percent of which related to a field
in Crane County, Texas. The remaining 19 percent was
comprised of multiple immaterial wells in various counties.
S-63
General and administrative expenses. The following
table provides components of our general and administrative
expenses for the year ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
(in thousands, except per unit
amounts)
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
|
General and administrative expensesrecurring
|
|
$
|
36,170
|
|
|
$
|
5.11
|
|
|
$
|
22,419
|
|
|
$
|
4.46
|
|
Non-recurring bonus paid to former Henry Entities employees
|
|
|
4,328
|
|
|
|
0.61
|
|
|
|
|
|
|
|
|
|
Non-cash stock-based compensationstock options
|
|
|
3,101
|
|
|
|
0.44
|
|
|
|
2,463
|
|
|
|
0.49
|
|
Non-cash stock-based compensationrestricted stock
|
|
|
2,122
|
|
|
|
0.30
|
|
|
|
1,378
|
|
|
|
0.27
|
|
Less: third-party fee reimbursements
|
|
|
(4,945
|
)
|
|
|
(0.70
|
)
|
|
|
(1,083
|
)
|
|
|
(0.21
|
)
|
|
|
|
|
|
|
Total general and administrative expenses
|
|
$
|
40,776
|
|
|
$
|
5.76
|
|
|
$
|
25,177
|
|
|
$
|
5.01
|
|
|
|
General and administrative expenses were $40.8 million
($5.76 per Boe) for the year ended December 31, 2008, an
increase of $15.6 million (62 percent) from
$25.2 million ($5.01 per Boe) for the year ended
December 31, 2007. The increase in general and
administrative expenses during the year ended December 31,
2008 over 2007 was primarily due to (i) the non-recurring
bonus paid to Henry Entities employees, (ii) an
increase in non-cash stock-based compensation for both stock
options and restricted stock awards and (iii) an increase
in the number of employees and related personnel expenses,
partially offset by an increase in third-party operating fee
reimbursements.
As part of the Henry Entities acquisition, we agreed to pay
certain of the Henry Entities employees who became our
employees a predetermined bonus amount, in addition to the
compensation we pay these employees over the next two years.
Since these employees will earn this bonus over the next two
years we are reflecting the cost in our general and
administrative costs. We are reflecting this bonus amount as
non-recurring as it is not controlled by our management.
We earn reimbursements as operator of certain oil and gas
properties in which we own interests. As such, we earned
reimbursements of $4.9 million and $1.1 million during
the year ended December 31, 2008 and 2007, respectively.
This reimbursement is reflected as a reduction of general and
administrative expenses in the consolidated statements of
operations. The increase in this reimbursement is directly
related to the Henry Properties acquisition, as we own a lower
working interest in these operated properties compared to our
historical property base, thus we have a larger third-party
reimbursement as compared to our historical property base.
Bad debt expense. On May 20, 2008, we entered
into a short-term purchase agreement with an oil purchaser to
sell a portion of our oil production affected by a New Mexico
refinery shut down due to repairs. On July 22, 2008, this
purchaser declared bankruptcy. We fully reserved the receivable
amount of $2.9 million due from this purchaser for June and
July production during the year ended December 31, 2008.
Contract drilling feesstacked rigs. We
determined in January 2007 to reduce our drilling activities for
the first three months of 2007. As a result, we recorded an
expense during the year ended December 31, 2007 of
approximately $4.3 million for contract drilling fees
related to stacked rigs subject to daywork drilling contracts
with two drilling contractors. We resumed the majority of our
planned drilling activities in April 2007 and all planned
drilling activities in June 2007. These costs were minimized
during the first six months of 2007 as one contractor secured
S-64
work for a rig for 71 days during that period and charged
us only the difference between the then-current operating day
rate pursuant to the contract and the lower operating day rate
received from the new customer.
(Gain) loss on derivatives not designated as
hedges. During the three months ended June 30,
2007, we determined that all of our natural gas commodity
derivative contracts no longer qualified as hedges under the
requirements of SFAS No. 133. If the hedge is no
longer highly effective, according to SFAS No. 133, an
entity shall discontinue hedge accounting for an existing hedge,
prospectively, and during the period the hedges became
ineffective. In addition, for our new commodity and interest
rate derivative contracts entered into after August 2007, we
chose not to designate any of these contracts as hedges. As a
result, any changes in fair value and any cash settlements
related to these contracts are recorded in earnings during the
related period.
The following table sets forth the cash payments (receipts) for
settlements and the non-cash
mark-to-market
adjustment for the derivative contracts not designated as hedges
for the years ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
(in thousands)
|
|
2008
|
|
|
2007
|
|
|
|
|
Cash payments (receipts):
|
|
|
|
|
|
|
|
|
Commodity derivativesoil
|
|
$
|
7,780
|
|
|
$
|
|
|
Commodity derivativesnatural gas
|
|
|
(1,426
|
)
|
|
|
(1,815
|
)
|
Financial derivativesinterest
|
|
|
|
|
|
|
|
|
Mark-to-market
(gain) loss:
|
|
|
|
|
|
|
|
|
Commodity derivativesoil
|
|
|
(253,960
|
)
|
|
|
22,988
|
|
Commodity derivativesnatural gas
|
|
|
(3,347
|
)
|
|
|
(899
|
)
|
Financial derivativesinterest
|
|
|
1,083
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on derivatives not designated as hedges
|
|
$
|
(249,870
|
)
|
|
$
|
20,274
|
|
|
|
Interest expense. Interest expense was
$29.0 million for the year ended December 31, 2008, a
decrease of $7.0 million from $36.0 million for the
year ended December 31, 2007. The weighted average interest
rate for the year ended December 31, 2008 and 2007 was
5.1 percent and 7.7 percent, respectively. The
weighted average debt balance during the year ended
December 31, 2008 and 2007 was approximately
$450.7 million and $436.3 million, respectively.
The increase in weighted average debt balance during the year
ended December 31, 2008 was due to the Henry Properties
acquisition in July 2008, offset by (i) the partial
prepayment in August 2007 of $86.6 million on the second
lien credit facility and the repayment in August 2007 of
$86.6 million on our previous revolving credit facility and
(ii) a partial prepayment in March 2008 on our previous
revolving credit facility utilizing cash from operations. Also,
in July 2008, we repaid and terminated our second lien credit
facility which resulted in the write-off of approximately
$1.1 million of deferred loan costs and approximately
$0.4 million of original issue discount, both of which are
included in interest expense. In March 2007, we reduced our
previous revolving credit facilitys borrowing base by
$100.0 million, or 21 percent, resulting in the
write-off of $0.8 million of deferred loan costs, and
repaid a term credit facility, resulting in the write-off of
$0.4 million of deferred loan costs, both of which are
included in interest expense. In August 2007, we made a
$86.6 million partial prepayment on our second lien credit
facility from proceeds of our initial public offering, which
resulted in the write-off of approximately $1.0 million of
deferred loan costs and approximately $0.4 million of
original issue
S-65
discount, both of which are included in interest expense. The
decrease in the weighted average interest rate is due to
(i) improvement in market interest rates and (ii) the
fact that the interest rate margins under our credit facility
(and previous revolving credit facility) were lower than those
under our second lien credit facility.
Income tax provision. We recorded an income tax
expense of $162.1 million and $16.0 million for the
year ended December 31, 2008 and 2007, respectively. The
effective income tax rate for the year ended December 31,
2008 and 2007 was 36.8 percent and 38.7 percent,
respectively. We estimated a higher effective state income rate
in 2007 than in 2008, which is primarily due to our estimate of
income among the various states in which we own assets.
Year ended
December 31, 2007 compared to year ended December 31,
2006
Oil and gas revenues. Revenue from oil and gas
operations was $294.3 million for the year ended
December 31, 2007, an increase of $96.0 million
(48 percent) from $198.3 million for the year ended
December 31, 2006. This increase was primarily because of
increased production as a result of the acquisition of the Chase
Group Properties and secondarily due to successful drilling
efforts during 2006 and 2007, coupled with moderate increases in
realized oil and gas prices. In addition:
|
|
|
average realized oil prices (after giving effect to hedging
activities) were $64.90 per Bbl during the year ended
December 31, 2007, an increase of 13 percent from
$57.42 per Bbl during the year ended December 31, 2006;
|
|
|
total oil production was 3,014 MBbl for the year ended
December 31, 2007, an increase of 719 MBbl
(31 percent) from 2,295 MBbl for the year ended
December 31, 2006;
|
|
|
average realized natural gas prices (after giving effect to
hedging activities) were $8.18 per Mcf during the year ended
December 31, 2007, an increase of 17 percent from
$7.00 per Mcf during the year ended December 31, 2006;
|
|
|
total natural gas production was 12,064 MMcf for the year
ended December 31, 2007, an increase of 2,557 MMcf
(27 percent) from 9,507 MMcf for the year ended
December 31, 2006;
|
|
|
average realized barrel of oil equivalent prices (after giving
effect to hedging activities) were $58.56 per Boe during the
year ended December 31, 2007, an increase of
15 percent from $51.12 per Boe during the year ended
December 31, 2006;
|
|
|
total production was 5,025 MBoe for the year ended
December 31, 2007, an increase of 1,145 MBoe
(30 percent) from 3,880 MBoe for the year ended
December 31, 2006; and
|
|
|
total production during the year ended December 31, 2007
was reduced by approximately 110 MBoe as a result of the
temporary shut-downs of a natural gas processing plant through
which we process and sell a portion of our production.
|
Hedging activities. The oil and gas prices that we
report are based on the market price received for the
commodities adjusted to give effect to the results of our cash
flow hedging activities. We utilize commodity derivative
instruments in order to (i) reduce the effect of the
volatility of price changes on the commodities we produce and
sell, (ii) support our annual capital budgeting and
expenditure plans and (iii) lock-in commodity prices to
protect economics related to
S-66
certain capital projects. Following is a summary of the effects
of commodity hedges that qualify for hedge accounting treatment
for the year ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil hedges
|
|
|
Natural gas hedges
|
|
|
|
Years ended December 31,
|
|
|
Years ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Hedging revenue increase (decrease) (in thousands)
|
|
$
|
(11,091
|
)
|
|
$
|
(7,000
|
)
|
|
$
|
1,291
|
|
|
|
1,232
|
|
Hedged volumes (Bbls and MMBtus, respectively)
|
|
|
1,076,750
|
|
|
|
1,080,500
|
|
|
|
6,482,600
|
|
|
|
5,447,500
|
|
Hedged revenue increase (decrease) per hedged volume
|
|
$
|
(10.30
|
)
|
|
$
|
(6.48
|
)
|
|
$
|
0.20
|
|
|
$
|
0.23
|
|
|
|
During the year ended December 31, 2007, our commodity
price hedges decreased oil revenues by $11.1 million ($3.68
per Bbl). During the year ended December 31, 2006, our
commodity price hedges decreased oil revenues by
$7.0 million ($3.05 per Bbl). The effect of the commodity
price hedges in decreasing oil revenues during the year ended
December 31, 2007 more than their effect of decreasing oil
revenues during the year ended December 31, 2006 was the
result of (i) a higher average market price of NYMEX oil of
$72.45 per Bbl in 2007 as compared to $66.26 per Bbl in 2006,
and (ii) the higher hedged revenue per hedged volume in
2007 as compared to 2006, as shown in the table above, partially
offset by a lower amount of hedged volumes in 2007 as compared
to 2006.
During the year ended December 31, 2007, our commodity
price hedges increased gas revenues by $1.3 million ($0.11
per Mcf). During the year ended December 31, 2006, our
commodity price hedges increased gas revenues by
$1.2 million ($0.13 per Mcf). The effect of commodity price
hedges in increasing gas revenues in 2007 more than their effect
of increasing gas revenues in 2006 was the result of a higher
amount of hedged volumes in 2007 as compared to 2006, partially
offset by (i) the lower hedged revenue per hedged volume in
2007 as compared to 2006 and (ii) a higher reference market
price for natural gas of $6.11 per MMBtu in 2007 as compared to
$6.06 per MMBtu in 2006.
At June 30, 2007, we determined that all of our natural gas
commodity contracts no longer qualified as hedges under the
requirements of SFAS No. 133. As a result, amounts in
AOCI at June 30, 2007 related to these dedesignated hedges
remained in AOCI and are reclassified into earnings under
natural gas revenues during the periods which the hedged
forecasted transaction affects earnings. Cash settlements for
these natural gas contracts are recorded to gains (losses) on
derivatives not designated as hedges. Regarding the dedesignated
contracts, for the period January 1, 2007 through
June 30, 2007, when these natural gas contracts qualified
to use hedge accounting, the cash settlement receipts of
approximately $0.19 million were recorded in natural gas
revenues. For the period July 1, 2007 through
December 31, 2007, when these natural gas contracts no
longer qualified to use hedge accounting, a pre-tax amount of
$1.1 million was reclassified from AOCI to natural gas
revenues and cash settlement receipts of $1.8 million was
recorded to gains (losses) on derivatives not designated as
hedge.
S-67
Oil and gas production costs. The following tables
provide the components of our oil and gas production costs for
the year ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
(in thousands, except per unit
amounts)
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
|
Lease operating expenses
|
|
$
|
26,480
|
|
|
$
|
5.27
|
|
|
$
|
20,424
|
|
|
$
|
5.26
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
2,012
|
|
|
|
0.40
|
|
|
|
1,120
|
|
|
|
0.29
|
|
Production
|
|
|
24,301
|
|
|
|
4.84
|
|
|
|
15,762
|
|
|
|
4.06
|
|
Workover costs
|
|
|
1,474
|
|
|
|
0.29
|
|
|
|
516
|
|
|
|
0.14
|
|
|
|
|
|
|
|
Total oil and gas production expenses
|
|
$
|
54,267
|
|
|
$
|
10.80
|
|
|
$
|
37,822
|
|
|
$
|
9.75
|
|
|
|
Among the cost components of production expenses, in general, we
have control over lease operating expenses and workover costs on
properties we operate, but production and ad valorem taxes are
directly related to commodity price changes.
Lease operating expenses were $26.5 million ($5.27 per Boe)
for the year ended December 31, 2007, an increase of
$6.1 million (30 percent) from $20.4 million
($5.27 per Boe) for the year ended December 31, 2006. The
increase in lease operating expenses is due to (i) lease
operating expenses associated with the Chase Group Properties
acquired in February 2006 of approximately $2.2 million,
(ii) lease operating expenses associated with wells that
were successfully completed in 2006 and 2007 as a result of our
drilling activities and (iii) general inflation of field
service and supply costs associated with rising commodity prices.
Ad valorem taxes have increased primarily as a result of
(i) new wells that were successfully completed in 2006 and
2007 as a result of our drilling activities and (ii) the
increase in commodity prices.
Production taxes per unit of production were $4.84 per Boe
during the year ended December 31, 2007, an increase of
19 percent from $4.06 per Boe during the year ended
December 31, 2006. The increase is directly related to the
increase in oil and gas revenues and the related increase in
commodity prices. Over the same period our Boe prices (before
the effects of hedging) increased 15 percent.
Workover expenses were $1.5 million and $0.5 million
for the year ended December 31, 2007 and 2006,
respectively. The 2007 amount related to a workover project on a
property located in Gaines County, Texas, while the 2006 amount
related primarily to workovers on properties located in Andrews
County, Texas.
Exploration and abandonments expense. The following
table provides a breakdown of our exploration and abandonments
expense for the year ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
(in thousands)
|
|
2007
|
|
|
2006
|
|
|
|
|
Geological and geophysical
|
|
$
|
4,089
|
|
|
$
|
2,185
|
|
Exploratory dry holes
|
|
|
21,923
|
|
|
|
3,192
|
|
Leasehold abandonments and other
|
|
|
3,086
|
|
|
|
235
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$
|
29,098
|
|
|
$
|
5,612
|
|
|
|
S-68
Our geological and geophysical expense, which primarily consists
of general and administrative costs for our geology department
as well as seismic data, geophysical data and core analysis,
during the year ended December 31, 2007 was
$4.1 million, an increase of $1.9 million from
$2.2 million for the year ended December 31, 2006.
This increase is primarily attributable to a comprehensive
seismic survey on our New Mexico shelf properties which was
initiated in December 2007.
Our exploratory dry holes expense during the year ended
December 31, 2007 is primarily attributable to five
operated exploratory wells that were unsuccessful. The costs
associated with three of these wells drilled in the Western
Delaware Basin in Culberson County, Texas approximated
$17.0 million. Another of these wells, which was drilled in
the Southeast New Mexico Basin in Lea County, New Mexico, had
costs of approximately $2.4 million. An additional
$0.8 million was charged to exploratory dry hole costs
related to an unsuccessful targeted zone in the fifth of these
wells in the Southeast New Mexico Basin in Eddy County, New
Mexico. Exploration expense of $1.7 million related to
three unsuccessful outside operated wells located in Eddy
County, New Mexico.
Of our exploratory dry holes expense during the year ended
December 31, 2006, $3.2 million was attributable to
one unsuccessful exploratory well in Gaines County, Texas that
we operated and one unsuccessful exploratory well in Val Verde
County, Texas operated by another company.
For the year ended December 31, 2007, we recorded
$3.1 million of leasehold abandonments, of which
$0.7 million related to a prospect in Lea County, New
Mexico, $0.8 million related to one prospect located in
Edwards County, Texas and $0.5 million related to leasehold
expiring in Southeast New Mexico. The remaining
$1.1 million was related to several individually minor
leaseholds. We had minimal leasehold abandonments during the
year ended December 31, 2006.
Depreciation, depletion and amortization
expense. The following table provides components of our
depreciation, depletion and amortization expense for the year
ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
(in thousands, except per unit
amounts)
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
75,744
|
|
|
$
|
15.07
|
|
|
$
|
59,872
|
|
|
$
|
15.43
|
|
Depreciation of property and equipment
|
|
|
1,035
|
|
|
|
0.21
|
|
|
|
850
|
|
|
|
0.22
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
$
|
76,779
|
|
|
$
|
15.28
|
|
|
$
|
60,722
|
|
|
$
|
15.65
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end
|
|
$
|
92.50
|
|
|
|
|
|
|
$
|
57.75
|
|
|
|
|
|
Natural gas price used to estimate proved gas reserves at period
end
|
|
$
|
6.80
|
|
|
|
|
|
|
$
|
5.64
|
|
|
|
|
|
|
|
Depletion of proved oil and gas properties was
$75.7 million ($15.07 per BOE) for the year ended
December 31, 2007, an increase of $15.8 million from
$59.9 million ($15.43 per BOE) for the year ended
December 31, 2006. The increase in depletion expense was
primarily due to (i) the acquisition of the Chase Group
Properties and (ii) capitalized costs associated with new
wells that were successfully completed in 2006 and 2007 as a
result of our drilling activities. The
S-69
decrease in depletion expense per Boe was primarily due to an
increase in proved oil and natural gas reserves as a result of
our successful development and exploratory drilling program.
Impairment of long-lived assets. In accordance with
SFAS No. 144, we review our long-lived assets to be
held and used, including proved oil and gas properties accounted
for under the successful efforts method of accounting. As a
result of this review of the recoverability of the carrying
value of our assets during the year ended December 31,
2007, we recognized a non-cash charge against earnings of
$7.3 million, 33 percent of which related to wells
drilled in Gaines County, Texas, 30 percent of which
related to a well drilled in Schleicher County, Texas and
18 percent of which related to a well drilled in Crane
County, Texas. The remaining 19 percent was comprised of
multiple immaterial wells in various counties. For the year
ended December 31, 2006, we recognized a non-cash charge
against earnings of $9.9 million, 33 percent of which
related to wells located in Pecos and Midland Counties, Texas,
acquired in our acquisition of the Lowe Properties,
24 percent of which related to wells located in Lea and
Eddy Counties, New Mexico, acquired in our acquisition of the
Lowe Properties, 11 percent of which related to a well
drilled in Eddy County, New Mexico and 9 percent of which
related to a well drilled in Mountrail County, North Dakota. The
remaining 23 percent was comprised of multiple immaterial
wells in various counties.
Contract drilling feesstacked rigs. We
determined in January 2007 to reduce our drilling activities for
the first three months of 2007. As a result, we recorded an
expense during the six months ended June 30, 2007 of
approximately $4.3 million for contract drilling fees
related to stacked rigs subject to daywork drilling contracts
with two drilling contractors. No additional costs were incurred
from July 1, 2007 through December 31, 2007. We
resumed the majority of our planned drilling activities in April
2007 and all planned drilling activities in June 2007. These
costs were minimized during the first six months of 2007 as one
contractor secured work for a rig for 71 days during that
period and charged us only the difference between the
then-current operating day rate pursuant to the contract and the
lower operating day rate received from the new customer.
General and administrative expenses. The following
table provides components of our general and administrative
expenses for the year ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
(in thousands, except per unit
amounts)
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
|
General and administrative expensesrecurring
|
|
$
|
22,419
|
|
|
$
|
4.46
|
|
|
$
|
13,376
|
|
|
$
|
3.45
|
|
Non-cash stock-based compensationCapital Options
|
|
|
|
|
|
|
|
|
|
|
975
|
|
|
|
0.25
|
|
Non-cash stock-based compensationstock options
|
|
|
2,463
|
|
|
|
0.49
|
|
|
|
7,125
|
|
|
|
1.84
|
|
Non-cash stock-based compensationrestricted stock
|
|
|
1,378
|
|
|
|
0.27
|
|
|
|
1,044
|
|
|
|
0.27
|
|
Less: third-party fee reimbursements
|
|
|
(1,083
|
)
|
|
|
(0.21
|
)
|
|
|
(799
|
)
|
|
|
(0.21
|
)
|
|
|
|
|
|
|
Total general and administrative expenses
|
|
$
|
25,177
|
|
|
$
|
5.01
|
|
|
$
|
21,721
|
|
|
$
|
5.60
|
|
|
|
General and administrative expenses were $25.2 million
($5.01 per BOE) for the year ended December 31, 2007, an
increase of $3.5 million (16 percent) from
$21.7 million ($5.60 per BOE) for the year ended
December 31, 2006. The increase in general and
administrative expenses during the year ended December 31,
2007 was primarily due to the increase in the size and
complexity of our operations following the combination
transaction and related increase in professional fees. In
addition, annual bonuses in the aggregate amount of
$2.5 million were
S-70
paid to the officers and employees in April 2007 representing
bonuses for 2006 performance as compared to $0.9 million
aggregate bonuses paid to employees in February 2006.
We earn revenue as operator of certain oil and gas properties in
which we own interests. As such, we earned revenue of
$1.1 million and $0.8 million during the year ended
December 31, 2007 and 2006, respectively. This revenue is
reflected as a reduction of general and administrative expenses
in the consolidated statements of operations.
Loss on derivatives not designated as hedges. During
the three months ended June 30, 2007, we determined that
all of our natural gas commodity derivative contracts no longer
qualified as hedges under the requirements of
SFAS No. 133. If the hedge is no longer highly
effective, according to SFAS No. 133, an entity shall
discontinue hedge accounting for an existing hedge,
prospectively, and during the period the hedges became
ineffective. In addition, for our new commodity derivative
contracts entered into after August 2007, we chose not to
designate any of these contracts as hedges. As a result, any
changes in fair value and any cash settlements related to these
contracts are recorded in earnings during the related period.
The following table sets forth the cash payments (receipts) for
settlements and the non-cash
mark-to-market
adjustment for the derivative contracts not designated as hedges
for the years ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
(in thousands)
|
|
2007
|
|
|
2006
|
|
|
|
|
Cash receipts:
|
|
|
|
|
|
|
|
|
Commodity derivativesoil
|
|
$
|
|
|
|
$
|
|
|
Commodity derivativesnatural gas
|
|
|
(1,815
|
)
|
|
|
|
|
Mark-to-market
(gain) loss:
|
|
|
|
|
|
|
|
|
Commodity derivativesoil
|
|
|
22,988
|
|
|
|
|
|
Commodity derivativesnatural gas
|
|
|
(899
|
)
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not designated as hedges
|
|
$
|
20,274
|
|
|
$
|
|
|
|
|
Interest expense. Interest expense was
$36.0 million for the year ended December 31, 2007, an
increase of $5.4 million from $30.6 million for the
year ended December 31, 2006. The weighted average interest
rate for the year ended December 31, 2007 and 2006 was
7.7 percent and 7.5 percent, respectively. The
weighted average debt balance during the year ended
December 31, 2007 and 2006 was approximately
$436.3 million and $406.8 million, respectively.
The increase in weighted average debt balance during the year
ended December 31, 2007 was our borrowings to fund our
drilling activities, partially offset by the partial prepayment
in August 2007 of $86.6 million on our second lien credit
facility and the repayment in August 2007 of $86.6 million
on our then revolving credit facility. The increase in interest
expense is due to a slight increase in the weighted average
interest rate, the increase in the weighted average debt and the
acceleration of deferred loan cost amortization and original
issue discount amortization. In March 2007, we reduced our then
revolving credit facility borrowing base by $100.0 million,
or 21 percent, resulting in accelerated amortization of
$0.8 million, and the full repayment of the second lien
credit facility resulting in accelerated amortization of
$0.4 million. The prepayment of $86.6 million on our
new second lien credit facility in August 2007 resulted in
accelerated amortization of $1.0 million in deferred loan
costs and $0.4 million in original issue discount.
S-71
Income tax provision. We recorded income tax expense
of $16.0 million and $14.4 million for the year ended
December 31, 2007 and 2006, respectively. The effective
income tax rate for the year ended December 31, 2007 and
2006 was 38.7 percent and 42.2 percent, respectively.
We estimated a lower effective state income rate in 2007 than in
2006, which is primarily due to our estimate of income among the
various states in which we own assets.
Capital
commitments, capital resources and liquidity
Capital
commitments
Our primary needs for cash are development, exploration and
acquisition of oil and natural gas assets, payment of
contractual obligations and working capital obligations. Funding
for these cash needs may be provided by any combination of
internally-generated cash flow, financing under our credit
facility, proceeds from the disposition of assets or alternative
financing sources, as discussed in Capital
resources below.
Oil and natural gas properties. Our capital
expenditures on oil and natural gas properties, excluding
acquisitions and asset retirement obligations, totaled
$202.7 million and $121.3 million for the six months
ended June 30, 2009 and 2008, respectively, and
$339.6 million, $180.2 million and $173.0 million
during the years ended December 31, 2008, 2007 and 2006,
respectively. These expenditures were primarily funded by cash
flow from operations (including effects of derivative cash
receipts/payments).
On November 6, 2008, our board of directors approved a
capital budget for 2009 of up to approximately
$500 million. The capital budget was predicated on funding
it substantially within cash flow. In January 2009, in light of
a decrease in commodity prices, we took actions to reduce our
activities to a level that would allow us to fund our capital
expenditures substantially within our cash flow, which at the
time resulted in estimated annual capital expenditures of
approximately $300 million. Currently, based on current
capital costs and commodity prices we estimate our capital
expenditures to be approximately $400 million for 2009,
which we believe we can substantially fund within our cash flow.
We will continue to monitor our capital expenditures, at least
on a quarterly basis, in relation to our cash flow and expect to
adjust our activity and capital spending level based on changes
in commodity prices and the cost of goods and services and other
considerations.
Other than the purchase of leasehold acreage and other
miscellaneous property interests, our 2009 capital budget is
exclusive of acquisitions. We do not have a specific acquisition
budget since the timing and size of acquisitions are difficult
to forecast. We evaluate opportunities to purchase or sell oil
and natural gas properties in the marketplace and could
participate as a buyer or seller of properties at various times.
We seek to acquire oil and natural gas properties that provide
opportunities for the addition of reserves and production
through a combination of exploitation, development,
high-potential exploration and control of operations and that
will allow us to apply our operating expertise.
Although we cannot provide any assurance, we believe that our
available cash and cash flows will be sufficient to fund our
2009 capital expenditures, as adjusted from time to time;
however, we could also use our credit facility or other
alternative financing sources to fund such expenditures. The
actual amount and timing of our expenditures may differ
materially from our estimates as a result of, among other
things, actual drilling results, the timing of expenditures by
third parties on projects that we do not operate, the
availability of drilling rigs and other services and equipment,
regulatory, technological and competitive developments and
market
S-72
conditions. In addition, under certain circumstances we would
consider increasing or reallocating our 2009 capital budget.
Acquisitions. Our expenditures for acquisitions of
proved and unproved properties totaled $3.6 million and
$1.4 million for the six months ended June 30, 2009
and 2008, respectively, and $838.0 million,
$7.3 million and $1,050.8 million for the years ended
December 31, 2008, 2007 and 2006, respectively. Included in
previous acquisition amounts are adjustments to the purchase
price allocation related to the acquisition of the Henry
Properties of $0.7 million for the six months ended
June 30, 2009. The Henry Properties acquisition in July
2008 was primarily funded by a private placement of our common
stock and borrowings under our credit facility.
Contractual
obligations
Our contractual obligations include long-term debt, operating
lease obligations, drilling commitments (including commitments
to pay day rates for drilling rigs), employment agreements,
contractual bonus payments, derivative obligations and other
liabilities.
We had the following contractual obligations at June 30,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by period
|
|
|
|
|
|
|
Less than
|
|
|
|
|
|
|
|
|
More than
|
|
(in thousands)
|
|
Total
|
|
|
1 year
|
|
|
1-3 years
|
|
|
3-5 years
|
|
|
5 years
|
|
|
|
|
Long-term
debta
|
|
$
|
660,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
660,000
|
|
|
$
|
|
|
Operating lease obligations
|
|
|
8,105
|
|
|
|
1,062
|
|
|
|
3,237
|
|
|
|
3,806
|
|
|
|
|
|
Drilling
commitmentsb
|
|
|
2,928
|
|
|
|
2,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employment agreements with executive
officersc
|
|
|
4,725
|
|
|
|
1,890
|
|
|
|
2,835
|
|
|
|
|
|
|
|
|
|
Henry Entities bonus
obligationd
|
|
|
11,253
|
|
|
|
10,387
|
|
|
|
866
|
|
|
|
|
|
|
|
|
|
Net derivative
assetse
|
|
|
(24,323
|
)
|
|
|
(10,541
|
)
|
|
|
(13,782
|
)
|
|
|
|
|
|
|
|
|
Asset retirement
obligationsf
|
|
|
14,386
|
|
|
|
2,706
|
|
|
|
337
|
|
|
|
415
|
|
|
|
10,928
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
677,074
|
|
|
$
|
8,432
|
|
|
$
|
(6,507
|
)
|
|
$
|
664,221
|
|
|
$
|
10,928
|
|
|
|
|
|
|
(a)
|
|
The amounts included in the table
above represent principal maturities only and have not been
adjusted to give effect to the issuance of notes in this
offering and the repayment of a portion of the outstanding
borrowings under our credit facility with the proceeds thereof.
|
|
(b)
|
|
Consists of daywork drilling
contracts related to drilling rigs contracted through June 30,
2010.
|
|
(c)
|
|
Represents amounts of cash
compensation we are obligated to pay our executive officers
under our employment agreements, assuming such employees
continue to serve the entire term of their employment agreement
and their cash compensation is not adjusted.
|
|
(d)
|
|
Represents bonuses we agreed to pay
certain employees of the Henry Entities at each of the first and
second anniversaries of the closing of the Henry Properties
acquisition. The first such anniversary bonus payment was made
on July 31, 2009.
|
|
(e)
|
|
Derivative obligations represent
net asset for commodity and interest rate derivatives that were
valued at June 30, 2009. The ultimate settlement amounts of
our derivative obligations are unknown because they are subject
to continuing market risk. See Quantitative and
qualitative disclosures about market risk.
|
|
(f)
|
|
Amounts represent costs related to
expected oil and gas property abandonments related to proved
reserves by period, net of any future accretion.
|
Off-balance sheet
arrangements
Currently, we do not have any material off-balance sheet
arrangements.
S-73
Capital
resources
Our primary sources of liquidity have been cash flows generated
from operating activities and financing provided by our credit
facility. We believe that funds from operating cash flows and
our credit facility should be sufficient to meet both our
short-term working capital requirements and our 2009 capital
budget plans.
Cash flow from operating activities. Our net cash
provided by operating activities was $118.2 million and
$162.9 million for the six months ended June 30, 2009
and 2008, respectively. The decrease in operating cash flows
during the six months ended June 30, 2009 over 2008 was
principally due to (i) decreases in average realized oil
and natural gas prices, offset by increased production,
(ii) increases in oil and natural gas production costs and
general and administrative expenses and (iii) uses of funds
associated with working capital.
Our net cash provided by operating activities was
$391.4 million, $169.8 million and $112.2 million
for the years ended December 31, 2008, 2007 and 2006,
respectively. The increase in operating cash flows during the
years ended December 31, 2008 over 2007 was principally due
to (i) increases in our oil and gas production as a result
of our exploration and development program, (ii) five
months of activity from the acquired Henry Properties and
(iii) increases in average realized oil and natural gas
prices. The increase in operating cash flows during the year
ended December 31, 2007 over 2006 was principally due to
increases in our oil and gas production as a result of our
exploration and development program and cash flow from
production attributable to the Chase Group Properties that we
acquired in the combination transaction in February 2006.
Cash flow used in investing activities. During the
six months ended June 30, 2009 and 2008, we invested
$223.3 million and $122.8 million, respectively, for
additions to, and acquisitions of, oil and natural gas
properties, inclusive of dry hole costs. Cash flows used in
investing activities were substantially higher during the six
months ended June 30, 2009 over 2008, due to an increase in
our exploration and development activities, offset by the
receipts/payments associated with derivatives not designated as
hedges.
During the years ended December 31, 2008, 2007 and 2006, we
invested $931.9 million, $162.6 million and
$595.6 million, respectively, for additions to, and
acquisitions of, oil and gas properties, inclusive of dry hole
costs. Cash flows used in investing activities were
substantially higher during the year ended December 31,
2008 over 2007, primarily due to the Henry Properties
acquisition, as well as increased drilling activity in 2008.
Cash flows used in investing activities were substantially
higher during the year ended December 31, 2006, primarily
due to the approximately $409.0 million cash portion of the
consideration we paid to the Chase Group in the combination
transaction and drilling activities in 2006. In order to
preserve liquidity, we reduced our drilling activities and
curtailed capital expenditures during the year ended
December 31, 2007, until we were able to complete our
second lien term loan facility in March 2007.
Cash flow from financing activities. Net cash
provided by (used in) financing activities was
$29.9 million and $(19.5) million for the six months
ended June 30, 2009 and 2008, respectively. During the six
months ended June 30, 2009, we had net borrowings of
$30.0 million under our credit facility. During the six
months ended June 30, 2008, we reduced our outstanding
balance by $26.5 million on our credit facilities.
Net cash provided by financing activities was
$542.0 million, $19.9 million and $476.6 million
for the years ended December 31, 2008, 2007 and 2006,
respectively. During the year ended December 31, 2008, we
borrowed $767.8 million under our credit facilities and
issued
S-74
approximately 8.3 million shares of our common stock to
fund the Henry Properties acquisition. In March 2007, we entered
into a $200 million second lien credit facility. The
proceeds were principally used to repay the outstanding balance
under our prior term loan facility and to reduce the outstanding
balance under our credit facility. Cash provided by financing
activities during the year ended December 31, 2006 was
primarily due to borrowings under our revolving credit facility
to fund the approximately $409.0 million cash portion of
the consideration paid to the Chase Group pursuant to the
combination transaction and proceeds from private issuances of
equity in our company.
Credit facility. On July 31, 2008, we amended
and restated our credit facility in various respects, including
increasing the borrowing base to $960 million, subject to
scheduled semiannual redetermination, and extending the maturity
date from February 24, 2011 to July 31, 2013. We paid
an arrangement fee of $14.4 million at closing of the
credit facility. The amount outstanding under the credit
facility at December 31, 2008 was $630.0 million. In
April 2009, the lenders reaffirmed our $960 million
borrowing base under the credit facility until the next
scheduled borrowing base redetermination in October 2009.
Between scheduled borrowing base redeterminations, we and, if
requested by
662/3 percent
of the lenders, the lenders, may each request one special
redetermination.
At June 30, 2009, we had letters of credit outstanding
under the credit facility of approximately $25,000 and our
availability to borrow additional funds was approximately
$300 million. Pursuant to the terms of our credit facility,
if we issue certain additional indebtedness, our borrowing base
will be reduced. Following the application of the proceeds of
this offering in the manner described in Use of
proceeds and giving effect to the reduction to our
borrowing base as a result of the issuance of the notes offered
hereby, we expect to have approximately $582.8 million of
availability under our credit facility and a revised borrowing
base of $955.9 million. For further discussion, see
Description of other indebtednessSenior secured
credit facility.
Advances on the credit facility bear interest, at our option,
based on (i) the prime rate of JPMorgan Chase Bank
(JPM Prime Rate) (3.25 percent at June 30,
2009) or (ii) a Eurodollar rate (substantially equal
to the London Interbank Offered Rate). At June 30, 2009,
the interest rates of Eurodollar rate advances and JPM Prime
Rate advances vary, with interest margins ranging from 200 to
300 basis points and 112.5 to 212.5 basis points,
respectively, per annum depending on the debt balance
outstanding. At June 30, 2009, we pay commitment fees on
the unused portion of the available borrowing base of
50 basis points per annum.
Other capital resource issues. On July 31,
2008, we repaid all the amounts outstanding under our second
lien credit facility and terminated the facility. On
June 5, 2008, we entered into a common stock purchase
agreement with certain unaffiliated third-party investors to
sell certain shares of our common stock in a private placement
(the Private Placement) contemporaneous with the
closing of the Acquisition. On July 31, 2008, we issued
8,302,894 shares of our common stock at $30.11 per share
pursuant to the Private Placement. We paid the placement agent
of the Private Placement a fee of approximately
$7.6 million, which resulted in net proceeds to us of
$242.4 million.
In conducting our business, we may utilize various financing
sources, including the issuance of (i) fixed and floating
rate debt, (ii) convertible securities,
(iii) preferred stock, (iv) common stock and
(v) other securities. We may also sell assets and issue
securities in exchange for oil and natural gas assets or
interests in oil and natural gas companies. Additional
securities may be of a class senior to common stock with respect
to such matters as dividends and liquidation rights and may also
have other rights and preferences as determined from time to
time by our board
S-75
of directors or a committee thereof. Utilization of some of
these financing sources may require approval from the lenders
under our credit facility.
Financial
markets
The current state of the financial markets is uncertain. There
have been financial institutions that have (i) failed and
been forced into government receivership, (ii) declared
bankruptcy, (iii) been forced to seek additional capital
and liquidity to maintain viability or (iv) merged. The
United States and world economy is experiencing volatility,
which is having an adverse impact on the financial markets.
At June 30, 2009, we had $300 million of available
borrowing capacity under our credit facility. Following the
application of the proceeds of this offering in the manner
described in Use of proceeds and giving effect to
the reduction to our borrowing base as a result of the issuance
of the notes offered hereby, we expect to have approximately
$582.8 million of availability under our credit facility
and a revised borrowing base of $955.9 million. For further
discussion, see Description of other
indebtednessSenior secured credit facility. Even in
light of the current volatility in the financial markets, we
currently believe that the lenders under our credit facility
have the ability to fund additional borrowings we may need for
our business.
We currently pay floating rate interest under our credit
facility and we are unable to predict, especially in light of
the current uncertainty in the financial markets, whether we
will incur increased interest costs due to rising interest
rates. We have utilized the use of interest rate derivatives to
mitigate the cost of rising interest rates, and we may enter
into additional interest rate derivatives in the future.
Additionally, we may issue fixed rate debt in the future to
increase available borrowing capacity under our credit facility
or to reduce our exposure to the volatility of interest rates.
In the current financial markets, we do not believe that we
could refinance our credit facility and obtain comparable terms.
Since our credit facility matures in July 2013, however, we have
no immediate need to seek refinancing.
To the extent we need additional funds, beyond those available
under our credit facility, to operate our business or make
acquisitions we would have to pursue other financing sources.
These sources could include issuance of (i) fixed and
floating rate debt, (ii) convertible securities,
(iii) preferred stock, (iv) common stock or
(v) other securities. We may also sell assets. However, in
light of the current financial market conditions there are no
assurances that we could obtain additional funding, or if
available, at what cost and terms.
Liquidity
Our principal sources of short-term liquidity are cash on hand
and available borrowing capacity under our credit facility. At
June 30, 2009, we had $3.1 million of cash on hand.
At June 30, 2009, the borrowing base under our credit
facility was $960 million, which provided us with
$300 million of available borrowing capacity. Following the
application of the proceeds of this offering in the manner
described in Use of proceeds and giving effect to
the reduction to our borrowing base as a result of the issuance
of the notes offered hereby, we expect to have approximately
$582.8 million of availability under our credit facility
and a revised borrowing base of $955.9 million. For further
discussion, see Description of other
indebtednessSenior secured credit facility. Our
borrowing base is redetermined semi-annually, with the next
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redetermination occurring in October 2009. In addition to such
semi-annual redeterminations, our lenders may request one
additional redetermination during any twelve-month period. In
general, redeterminations are based upon a number of factors,
including commodity prices and reserve levels. Upon a
redetermination, our borrowing base could be substantially
reduced. In light of the current commodity prices and the state
of the financial markets, there is no assurance that our
borrowing base will not be reduced.
Book
capitalization and current ratio
Our book capitalization at June 30, 2009 was
$1,949.6 million, consisting of debt of $660.0 million
and stockholders equity of $1,289.6 million, while
our book capitalization at December 31, 2008 was
$1,955.2 million, consisting of debt of $630.0 million
and stockholders equity of $1,325.2 million. Our debt
to book capitalization was 34 percent, 32 percent and
30 percent at June 30, 2009, December 31, 2008
and December 31, 2007, respectively. Our ratio of current
assets to current liabilities was 0.76 to 1.00 at June 30,
2009 as compared to 1.03 to 1.00 at December 31, 2008 and
0.84 to 1.00 at December 31, 2007.
Inflation and
changes in prices
Our revenues, the value of our assets, and our ability to obtain
bank financing or additional capital on attractive terms have
been and will continue to be affected by changes in commodity
prices and the costs to produce our reserves. Commodity prices
are subject to significant fluctuations that are beyond our
ability to control or predict. During the six months ended
June 30, 2009, we received an average of $47.32 per barrel
of oil and $4.52 per Mcf of natural gas before consideration of
commodity derivative contracts compared to $107.39 per barrel of
oil and $11.33 per Mcf of natural gas in the six months ended
June 30, 2008. During 2008, we received an average of
$91.92 per barrel of oil and $9.59 per Mcf of natural gas before
consideration of commodity derivative contracts compared to
$68.58 per barrel of oil and $8.08 per Mcf of natural gas in
2007. Although certain of our costs are affected by general
inflation, inflation does not normally have a significant effect
on our business. In a trend that began in 2004 and continued
through the first six months of 2008, commodity prices for oil
and natural gas increased significantly. The higher prices have
led to increased activity in the industry and, consequently,
rising costs. These cost trends have put pressure not only on
our operating costs but also on capital costs. We expect these
costs to moderate during the remainder of 2009 as a result of
the recent rapid diminution in prices for oil and natural gas
from 2008 peaks.
Critical
accounting policies, practices and estimates
Our historical consolidated financial statements and related
notes to consolidated financial statements contain information
that is pertinent to our managements discussion and
analysis of financial condition and results of operations.
Preparation of financial statements in conformity with
accounting principles generally accepted in the United States
requires that our management make estimates, judgments and
assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and the disclosure of
contingent assets and liabilities. However, the accounting
principles used by us generally do not change our reported cash
flows or liquidity. Interpretation of the existing rules must be
done and judgments made on how the specifics of a given rule
apply to us.
In managements opinion, the more significant reporting
areas impacted by managements judgments and estimates are
revenue recognition, the choice of accounting method for oil and
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natural gas activities, oil and natural gas reserve estimation,
asset retirement obligations, impairment of long-lived assets
and valuation of stock-based compensation. Managements
judgments and estimates in these areas are based on information
available from both internal and external sources, including
engineers, geologists and historical experience in similar
matters. Actual results could differ from the estimates, as
additional information becomes known.
Successful
efforts method of accounting
We utilize the successful efforts method of accounting for our
oil and natural gas exploration and development activities under
this method. Exploration expenses, including geological and
geophysical costs, lease rentals and exploratory dry holes, are
charged against income as incurred. Costs of successful wells
and related production equipment, undeveloped leases and
developmental dry holes are also capitalized. This accounting
method may yield significantly different results than the full
cost method of accounting. Exploratory drilling costs are
initially capitalized, but are charged to expense if and when
the well is determined not to have found proved reserves.
Generally, a gain or loss is recognized when producing
properties are sold.
The application of the successful efforts method of accounting
requires managements judgment to determine the proper
designation of wells as either developmental or exploratory,
which will ultimately determine the proper accounting treatment
of costs of dry holes. Once a well is drilled, the determination
that proved reserves have been discovered may take considerable
time, and requires both judgment and application of industry
experience. The evaluation of oil and gas leasehold acquisition
costs included in unproved properties requires managements
judgment to estimate the fair value of such properties. Drilling
activities in an area by other companies may also effectively
condemn our leasehold positions.
Non-producing properties consist of undeveloped leasehold costs
and costs associated with the purchase of certain proved
undeveloped reserves. Individually significant non-producing
properties are periodically assessed for impairment of value.
Depletion of capitalized drilling and development costs of oil
and natural gas properties is computed using the
unit-of-production
method on an individual property or unit basis based on total
estimated proved developed oil and natural gas reserves.
Depletion of producing leaseholds is based on the
unit-of-production
method using our total estimated net proved reserves. In
arriving at rates under the
unit-of-production
method, the quantities of recoverable oil and natural gas are
established based on estimates made by our geologists and
engineers and independent engineers. Service properties,
equipment and other assets are depreciated using the
straight-line method over estimated useful lives of one to fifty
years. Upon sale or retirement of depreciable or depletable
property, the cost and related accumulated depreciation and
depletion are eliminated from the accounts and the resulting
gain or loss is recognized.
Oil and natural
gas reserves and standardized measure of discounted future cash
flows
Our independent engineers and technical staff prepare the
estimates of our oil and natural gas reserves and associated
future net cash flows. Current accounting guidance allows only
proved oil and natural gas reserves to be included in our
financial statement disclosures. SEC regulations define proved
reserves as the estimated quantities of oil and natural gas
which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions. Even though our independent engineers and technical
staff are knowledgeable and follow authoritative guidelines for
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estimating reserves, they must make a number of subjective
assumptions based on professional judgments in developing the
reserve estimates. Reserve estimates are updated at least
annually and consider recent production levels and other
technical information about each field. Periodic revisions to
the estimated reserves and future cash flows may be necessary as
a result of a number of factors, including reservoir
performance, new drilling, oil and natural gas prices, cost
changes, technological advances, new geological or geophysical
data, or other economic factors. We cannot predict the amounts
or timing of future reserve revisions. If such revisions are
significant, they could significantly alter future depletion and
result in impairment of long-lived assets that may be material.
Asset retirement
obligations
In June 2001, the Financial Accounting Standards Board
(FASB) issued SFAS No. 143, Accounting for
Asset Retirement Obligations,
(SFAS No. 143) which applies to legal
obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and
the normal operation of a long-lived asset. The primary impact
of this standard on us relates to oil and natural gas wells on
which we have a legal obligation to plug and abandon.
SFAS No. 143 requires us to record the fair value of a
liability for an asset retirement obligation in the period in
which it is incurred and a corresponding increase in the
carrying amount of the related long-lived asset. The
determination of the fair value of the liability requires us to
make numerous judgments and estimates, including judgments and
estimates related to future costs to plug and abandon wells,
future inflation rates and estimated lives of the related assets.
Impairment of
long-lived assets
All of our long-lived assets are monitored for potential
impairment when circumstances indicate that the carrying value
of an asset may be greater than its future net cash flows,
including cash flows from risk adjusted proved reserves. The
evaluations involve a significant amount of judgment since the
results are based on estimated future events, such as future
sales prices for oil and natural gas, future costs to produce
these products, estimates of future oil and natural gas reserves
to be recovered and the timing thereof, the economic and
regulatory climates and other factors. The need to test an asset
for impairment may result from significant declines in sales
prices or downward revisions to estimated quantities of oil and
natural gas reserves. Any assets held for sale are reviewed for
impairment when we approve the plan to sell. Estimates of
anticipated sales prices are highly judgmental and subject to
material revision in future periods. Because of the uncertainty
inherent in these factors, we cannot predict when or if future
impairment charges will be recorded.
Valuation of
stock-based compensation
We adopted the modified prospective approach as
prescribed under SFAS No. 123(R) on January 1,
2006. Under this approach, we are required to expense all
options and other stock-based compensation that vested during
the year of adoption based on the fair value of the award on the
grant date. The calculation of the fair value of stock-based
compensation requires the use of estimates to derive the inputs
necessary for using the various valuation methods utilized by
us. We utilize (i) the Black-Scholes option pricing model
to measure the fair value of stock options and (ii) the
stock price on the date of grant for the fair value of
restricted stock awards.
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Recent accounting
pronouncements and developments
Recent accounting
pronouncements
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations (SFAS No. 141(R)),
which replaces FASB Statement No. 141.
SFAS No. 141(R) establishes principles and
requirements for how an acquirer recognizes and measures in its
financial statements the identifiable assets acquired, the
liabilities assumed, any noncontrolling interest in the acquiree
and the goodwill acquired. SFAS No. 141(R) also
establishes disclosure requirements that will enable users to
evaluate the nature and financial effects of the business
combination. SFAS No. 141(R) is effective for
acquisitions that occur in an entitys fiscal year that
begins after December 15, 2008. We adopted
SFAS No. 141(R) effective January 1, 2009. There
has been no impact on our consolidated financial statements, as
we have not entered into any significant business combinations
during 2009.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statementsan amendment of ARB No. 51
(SFAS No. 160). SFAS No. 160
requires that accounting and reporting for minority interests
will be recharacterized as noncontrolling interests and
classified as a component of equity. SFAS No. 160 also
establishes reporting requirements that provide sufficient
disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the noncontrolling
owners. SFAS No. 160 applies to all entities that
prepare consolidated financial statements, except
not-for-profit
organizations, but will affect only those entities that have an
outstanding noncontrolling interest in one or more subsidiaries
or that deconsolidate a subsidiary. This statement is effective
as of the beginning of an entitys first fiscal year
beginning after December 15, 2008. We adopted
SFAS No. 160 effective January 1, 2009, with no
impact on our consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging Activities
(SFAS No. 161), which amends and expands
the interim and annual disclosure requirements of
SFAS No. 133 to provide an enhanced understanding of
an entitys use of derivative instruments, how they are
accounted for under SFAS No. 133 and their effect on
the entitys financial position, financial performance and
cash flows. The provisions of SFAS No. 161 are
effective as of January 1, 2009. We adopted
SFAS No. 161 effective January 1, 2009, with no
significant impact on our consolidated financial statements,
other than additional disclosures which are set forth in the
notes to our consolidated financial statements which are
incorporated by reference herein.
In April 2008, the FASB issued FASB Staff Position
(FSP)
No. SFAS 142-3,
Determination of the Useful Life of Intangible Assets (FSP
SFAS No. 142-3).
FSP
SFAS No. 142-3
amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under
SFAS No. 142, Goodwill and Other Intangible Assets
(SFAS No. 142). The intent of FSP
SFAS No. 142-3
is to improve the consistency between the useful life of a
recognized intangible asset under SFAS No. 142 and the
period of expected cash flows used to measure the fair value of
the asset under SFAS No. 141R and other applicable
accounting literature. FSP
SFAS No. 142-3
is effective for financial statements issued for fiscal years
beginning after December 15, 2008 and must be applied
prospectively to intangible assets acquired after the effective
date. We adopted FSP
SFAS No. 142-3
effective January 1, 2009, with no significant impact on
our consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162, The
Hierarchy of Generally Accepted Accounting Principles
(SFAS No. 162), which identifies the
sources of accounting principles and the
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framework for selecting the principles used in the preparation
of financial statements of nongovernmental entities that are
presented in conformity with GAAP in the United States of
America. SFAS No. 162 arranges these sources of GAAP
in a hierarchy for users to apply accordingly. This statement
became effective for us on November 15, 2008. The adoption
of SFAS No. 162 did not have a significant impact on
our consolidated financial statements. In June 2009, this
statement was replaced with SFAS No. 168, The FASB
Accounting Standards
Codificationtm
(Codification) and the Hierarchy of Generally
Accepted Accounting Principles
(SFAS No. 168). Once the Codification is
in effect, all of its content will carry the same level of
authority, effectively superseding SFAS No. 162. In
other words, the GAAP hierarchy will be modified to include only
two levels of GAAP: authoritative and nonauthoritative.
SFAS No. 168 is effective for financial statements
issued for interim and annual periods ending after
September 15, 2009. We do not expect the adoption of
SFAS No. 168 to have an impact on our consolidated
financial statements.
In June 2008, the FASB issued FSP
No. EITF 03-6-1,
Determining Whether Instruments Granted in Share-Based Payment
Transactions Are Participating Securities, (FSP
EITF 03-6-1)
which provides that unvested share-based payment awards that
contain non-forfeitable rights to dividends or dividend
equivalents (whether paid or unpaid) are participating
securities and, therefore, need to be included in the earnings
allocation in computing earnings per share under the two class
method. FSP
EITF 03-6-1
was effective for us on January 1, 2009. There was no
impact on our consolidated financial statements.
In April 2009, the FASB issued FSP SFAS No. 141(R)-1,
Accounting for Assets Acquired and Liabilities Assumed in a
Business Combination That Arise from Contingencies. This FSP
amends and clarifies SFAS No. 141(R) to address
application issues raised by preparers, auditors, and members of
the legal profession on initial recognition and measurement,
subsequent measurement and accounting, and disclosure of assets
and liabilities arising from contingencies in a business
combination. This FSP is effective for assets or liabilities
arising from contingencies in business combinations for which
the acquisition date is on or after the beginning of the first
annual reporting period beginning on or after December 15,
2008. We have not made any acquisitions during 2009, and as
such, the adoption of this statement on January 1, 2009 did
not have a significant impact.
In April 2009, the FASB issued FSP
SFAS No. 107-1
and APB Opinion
No. 28-1,
Interim Disclosures about Fair Value of Financial Instrument
(FSP
SFAS No. 107-1).
This FSP amends FASB Statement No. 107, Disclosures about
Fair Value of Financial Instruments, to require disclosures
about fair value of financial instruments for interim reporting
periods of publicly traded companies as well as in annual
financial statements. This FSP also amends APB Opinion
No. 28, Interim Financial Reporting, to require those
disclosures in summarized financial information at interim
reporting periods. This FSP is effective for interim reporting
periods ending after June 15, 2009. This FSP does not
require disclosures for earlier periods presented for
comparative purposes at initial adoption. In periods after
initial adoption, this FSP requires comparative disclosures only
for periods ending after initial adoption. At June 15,
2009, we adopted the provisions of FSP
SFAS No. 107-1
related to the fair value of financial instruments. The adoption
of the provisions of FSP
SFAS No. 107-1
did not have a material effect on our financial condition or
results of operations. See Note H for additional
disclosures required by FSP
SFAS No. 107-1.
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In April 2009, the FASB issued FSP
SFAS No. 157-4,
Determining Fair Value When the Volume and Level of Activity for
the Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly (FSP
SFAS No. 157-4).
This FSP:
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affirms that the objective of fair value when the market for an
asset is not active is the price that would be received to sell
the asset in an orderly transaction;
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clarifies and includes additional factors for determining
whether there has been a significant decrease in market activity
for an asset when the market for that asset is not active;
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eliminates the proposed presumption that all transactions are
distressed (not orderly) unless proven otherwise. The FSP
instead requires an entity to base its conclusion about whether
a transaction was not orderly on the weight of the evidence;
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includes an example that provides additional explanation on
estimating fair value when the market activity for an asset has
declined significantly;
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requires an entity to disclose a change in valuation technique
(and the related inputs) resulting from the application of the
FSP and to quantify its effects, if practicable; and
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applies to all fair value measurements when appropriate.
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FSP
SFAS No. 157-4
must be applied prospectively and retrospective application is
not permitted. FSP
SFAS No. 157-4
is effective for interim and annual periods ending after
June 15, 2009. At June 15, 2009, we adopted the
provisions of FSP
SFAS No. 157-4
related to assets and liabilities that are measured at fair
value on a recurring and nonrecurring basis. The adoption of the
provisions of FSP
SFAS No. 157-4
did not have a material effect on our financial condition or
results of operations.
In May 2009, the FASB issued SFAS No. 165, Subsequent
Events (SFAS No. 165) which establishes
general standards of accounting for and disclosure of events
that occur after the balance sheet date, but before financial
statements are issued or are available to be issued. In
particular, SFAS No. 165 sets forth:
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the period after the balance sheet date during which management
of a reporting entity should evaluate events or transactions
that may occur for potential recognition or disclosure in the
financial statements;
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the circumstances under which a reporting entity should
recognize events or transactions occurring after the balance
sheet date in its financial statements; and
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the disclosures that a reporting entity should make about events
or transactions that occurred after the balance sheet date.
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In accordance with this Statement, a reporting entity should
apply the requirements to interim or annual financial periods
ending after June 15, 2009.
In June 2009, the FASB issued SFAS No. 166, Accounting
for Transfers of Financial Assets
(SFAS No. 166), which amends
SFAS No. 140, Accounting for Transfers and Servicing
of Financial Assets and Extinguishments of Liabilities. This
statement improves the relevance, representational faithfulness,
and comparability of the information that a reporting entity
provides in its financial reports about a transfer of financial
assets; the effects of a transfer on its financial position,
financial performance, and cash flows; and a transferors
continuing involvement in transferred financial assets.
SFAS No. 166 must be applied as of the beginning of
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each reporting entitys first annual reporting period that
begins after November 15, 2009, for interim periods within
that first annual reporting period and for interim and annual
reporting periods thereafter. Earlier application is prohibited.
SFAS No. 166 must be applied to transfers occurring on
or after the effective date. We do not expect the adoption of
SFAS No. 166 to have an impact on our consolidated
financial statements.
Recent
developments in reserves reporting
In December 2008, the SEC released Final Rule, Modernization of
Oil and Gas Reporting (the Reserve Ruling). The
Reserve Ruling revises oil and gas reporting disclosures. The
Reserve Ruling permits the use of new technologies to determine
proved reserves estimates if those technologies have been
demonstrated empirically to lead to reliable conclusions about
reserve volume estimates. The Reserve Ruling will also allow,
but not require, companies to disclose their probable and
possible reserves to investors in documents filed with the SEC.
In addition, the new disclosure requirements require companies
to: (i) report the independence and qualifications of its
reserves preparer or auditor; (ii) file reports when a
third party is relied upon to prepare reserves estimates or
conduct a reserves audit; and (iii) report oil and gas
reserves using an average price based upon the prior
12-month
period rather than a year-end price. The Reserve Ruling becomes
effective for fiscal years ending on or after December 31,
2009. We are currently assessing the impact that adoption of the
provisions of the Reserve Ruling will have on our financial
position, results of operations and disclosures.
Quantitative and
qualitative disclosures about market risk
We are exposed to a variety of market risks including credit
risk, commodity price risk and interest rate risk. We address
these risks through a program of risk management which includes
the use of derivative instruments. The following quantitative
and qualitative information is provided about financial
instruments to which we are a party at June 30, 2009, and
from which we may incur future gains or losses from changes in
market interest rates or commodity prices and losses from
extension of credit. We do not enter into derivative or other
financial instruments for speculative or trading purposes.
Hypothetical changes in interest rates and commodity prices
chosen for the following estimated sensitivity analysis are
considered to be reasonably possible near-term changes generally
based on consideration of past fluctuations for each risk
category. However, since it is not possible to accurately
predict future changes in interest rates and commodity prices,
these hypothetical changes may not necessarily be an indicator
of probable future fluctuations.
Credit
risk
We monitor our risk of loss due to non-performance by
counterparties of their contractual obligations. Our principal
exposure to credit risk is through the sale of our oil and
natural gas production, which we market to energy marketing
companies and refineries. We monitor our exposure to these
counterparties primarily by reviewing credit ratings, financial
statements and payment history. We extend credit terms based on
our evaluation of each counterpartys creditworthiness.
Although we have not generally required our counterparties to
provide collateral to support their obligation to us, we may, if
circumstances dictate, require collateral in the future. In this
manner, we reduce credit risk.
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Commodity price
risk
We are exposed to market risk as the prices of oil and natural
gas are subject to fluctuations resulting from changes in supply
and demand. To reduce our exposure to changes in the prices of
oil and natural gas we have entered into, and may in the future
enter into additional commodity price risk management
arrangements for a portion of our oil and natural gas
production. The agreements that we have entered into generally
have the effect of providing us with a fixed price for a portion
of our expected future oil and natural gas production over a
fixed period of time. Our commodity price risk management
activities could have the effect of reducing net income and the
value of our common stock. At June 30, 2009, the net
unrealized asset on our commodity price risk management
contracts was $24.3 million. An average increase in the
commodity price of $10.00 per barrel of oil and $1.00 per Mcf
for natural gas from the commodity prices at June 30, 2009,
would have resulted in a net unrealized liability on our
commodity price risk management contracts, as reflected on our
consolidated balance sheet at June 30, 2009, of
approximately $81.0 million.
At June 30, 2009, we had (i) an oil price collar and
oil price swaps that settle on a monthly basis covering future
oil production from July 1, 2009 through December 31,
2012 and (ii) a natural gas price swap, natural gas price
collars and natural gas basis swaps covering future natural gas
production from July 1, 2009 to December 31, 2011. At
December 31, 2008, we had (i) a oil price collar and
oil price swaps that settle on a monthly basis covering future
oil production from January 1, 2009 through
December 31, 2012 and (ii) a natural gas price swap
and a natural gas basis swap covering future natural gas
production for 2009.
The average NYMEX oil futures price and average NYMEX natural
gas futures prices for the six months ended June 30, 2009,
was $51.61 per Bbl and $4.15 per MMBtu, respectively. The
average NYMEX oil futures price and average NYMEX natural gas
futures prices for the year ended December 31, 2008, was
$99.75 per Bbl and $7.41 per MMBtu, respectively. At
September 8, 2009, the NYMEX oil futures price and NYMEX
natural gas futures price was $71.10 per Bbl and
$2.81 per MMBtu, respectively.
The decrease in oil and natural gas prices, if it continues
during the remainder of 2009, should increase the fair value
asset of our commodity derivative contracts from their recorded
balance at June 30, 2009. Changes in the recorded fair
value of the undesignated commodity derivative contracts are
marked to market through earnings as unrealized gains or losses.
The potential increase in fair value asset would be recorded in
earnings as unrealized gains. However, an increase in the
average NYMEX oil and natural gas futures price above those at
June 30, 2009 would result in a decrease in fair value
asset and unrealized losses in earnings. We are currently unable
to estimate the effects on the earnings of future periods
resulting from changes in the market value of our commodity
derivative contracts.
Interest rate
risk
Our exposure to changes in interest rates relates primarily to
long-term debt obligations. We manage our interest rate exposure
by limiting our variable-rate debt to a certain percentage of
total capitalization and by monitoring the effects of market
changes in interest rates. To reduce our exposure to changes in
interest rates we have entered into, and may in the future enter
into additional interest rate risk management arrangements for a
portion of our outstanding debt. The agreements that we have
entered into generally have the effect of providing us with a
fixed interest rate for a portion of our variable rate debt. We
may utilize interest rate
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derivatives to alter interest rate exposure in an attempt to
reduce interest rate expense related to existing debt issues.
Interest rate derivatives are used solely to modify interest
rate exposure and not to modify the overall leverage of the debt
portfolio. We are exposed to changes in interest rates as a
result of our credit facility, and the terms of our credit
facility require us to pay higher interest rate margins as we
utilize a larger percentage of our available borrowing base.
At June 30, 2009, we had interest rate swaps on
$300 million of notional principal that fixed the LIBOR
interest rate (does not include the interest rate margins
discussed above) at 1.90 percent for the three years
beginning in May 2009. An average decrease in future interest
rates of 25 basis points from the future rate at
June 30, 2009, would have resulted in a net unrealized
liability on our interest rate risk management contracts, as
reflected on our consolidated balance sheet at June 30,
2009, of approximately $2.1 million.
We had total indebtedness of $660 million outstanding under
our credit facility at June 30, 2009. The impact of a one
percent increase in interest rates on this amount of debt would
result in increased annual interest expense of approximately
$6.6 million.
Fair value of
derivative instruments
The fair value of our derivative instruments is determined based
on our valuation models. We did not change our valuation method
during 2008 or the first half of 2009. During 2008 and 2009, we
were party to commodity derivative instruments. The following
table reconciles the changes that occurred in the fair values of
our derivative instruments during the six months ended
June 30, 2009:
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Derivative instruments net assets
(liabilities)a
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(in thousands)
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Commodities
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Interest rate
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Total
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Fair value of contracts outstanding at December 31, 2008
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$
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173,523
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$
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(1,083
|
)
|
|
$
|
172,440
|
|
Changes in fair
valuesb
|
|
|
(86,873
|
)
|
|
|
221
|
|
|
|
(86,652
|
)
|
Contract maturities
|
|
|
(62,244
|
)
|
|
|
779
|
|
|
|
(61,465
|
)
|
|
|
|
|
|
|
Fair value of contracts outstanding at June 30, 2009
|
|
$
|
24,406
|
|
|
$
|
(83
|
)
|
|
$
|
24,323
|
|
|
|
|
|
|
(a)
|
|
Represents the fair values of open
derivative contracts subject to market risk.
|
|
(b)
|
|
At inception, new derivative
contracts entered into by us have no intrinsic value.
|
S-85
Business
General
Concho Resources Inc., a Delaware corporation, is an independent
oil and natural gas company engaged in the acquisition,
development, exploitation and exploration of oil and natural gas
properties. Our core operations are focused in the Permian Basin
of Southeast New Mexico and West Texas. These core operating
areas are complemented by our activities in our emerging plays.
We intend to grow our reserves and production through
development drilling, exploitation and exploration activities on
our multi-year project inventory and through acquisitions that
meet our strategic and financial objectives.
We were formed in February 2006 as a result of the combination
of Concho Equity Holdings Corp. and a portion of the oil and
natural gas properties and related assets owned by Chase Oil
Corporation (Chase Oil) and certain of its
affiliates. Concho Equity Holdings Corp. was formed in April
2004 and represented the third of three Permian Basin-focused
companies that have been formed since 1997 by certain members of
our current management team (the prior two companies were sold
to large domestic independent oil and gas companies).
Henry Entities
acquisition
On July 31, 2008, we closed our acquisition of Henry
Petroleum LP and certain entities affiliated with Henry
Petroleum LP (which we refer to collectively as the Henry
Entities), together with certain additional non-operated
interests in oil and gas properties from persons affiliated with
the Henry Entities. In August 2008 and September 2008, we
acquired additional non-operated interests in oil and gas
properties from persons affiliated with the Henry Entities. We
paid approximately $583.5 million in net cash for the
acquisition of the Henry Entities and the related acquisition of
the along-side interests, which was funded with
(i) borrowings under our credit facility and (ii) net
proceeds of approximately $242.4 million from our private
placement of 8,302,894 shares of our common stock. The oil
and gas assets acquired in the acquisition of the Henry Entities
and the along-side interests (which we refer to as the
Henry Properties) contained approximately
30.1 MMBoe of net proved reserves at the acquisition date.
Chase Oil
transaction
On February 24, 2006, we entered into a combination
agreement in which we agreed to purchase oil and gas properties
owned by Chase Oil, Caza Energy LLC and other related working
interest owners (which we refer to collectively as the
Chase Group) and combine them with substantially all
of the outstanding equity interests of Concho Equity Holdings
Corp. to form our company. The initial closing of the
transactions contemplated by the combination agreement occurred
on February 27, 2006, and the members of the Chase Group
that sold their working interests to us then received
34,683,315 shares of our common stock and approximately
$400 million in cash. The oil and gas properties
contributed to us by the Chase Group are referred to as the
Chase Group Properties.
Business and
properties
Our core operations are focused in the Permian Basin of
Southeast New Mexico and West Texas. The Permian Basin is one of
the most prolific producing oil and gas regions in the United
States.
S-86
It underlies an area of Southeast New Mexico and West Texas
approximately 250 miles wide and 300 miles long.
Commercial accumulations of hydrocarbons occur in multiple
stratigraphic horizons, at depths ranging from approximately
1,000 feet to over 25,000 feet. This basin is
characterized by long life, shallow decline reserves. At
December 31, 2008, 97.9 percent of our total estimated
net proved reserves were located in our core operating areas and
consisted of approximately 62.9 percent oil and
37.1 percent natural gas. We refer to our core operating
areas as (i) New Mexico Permian and (ii) Texas
Permian. The Permian Basin is characterized by an extensive
production history, mature infrastructure, long reserve life,
multiple producing horizons and enhanced recovery potential.
Producing horizons in our core properties include (i) the
Yeso in the New Mexico Permian, which is located at depths
ranging from 3,800 feet to 7,500 feet and
(ii) the Wolfberry in the Texas Permian, the term applied
to production attributable to the combined Wolfcamp and
Spraberry horizons, which are located at depths ranging from
7,500 feet to 10,500 feet. We have assembled a
multi-year inventory of development drilling and exploitation
projects, including projects to further evaluate the aerial
extent of the Yeso formation and the Wolfberry play, that we
believe will allow us to grow proved reserves and production. We
also have significant acreage positions in active emerging plays
in the Lower Abo horizontal play in Southeast New Mexico and the
Bakken/Three Forks play in North Dakota. We view an
emerging play as an area where we can acquire large undeveloped
acreage positions and apply horizontal drilling, advanced
fracture stimulation
and/or
enhanced recovery technologies to achieve economic and
repeatable production results.
During the first six months of 2009, we commenced drilling or
participation in the drilling of 147 gross (97.4 net)
wells, 76.2 percent of which were completed as producers,
1.4 percent of which were dry holes and 22.4 percent
of which were awaiting completion at June 30, 2009. In
addition, in the first half of 2009, we commenced recompletion
or participation in the recompletion of 82 gross (76.1 net)
wells, 93.9 percent of which were productive, none of which
were unsuccessful and 6.1 percent were still in progress at
June 30, 2009. In 2008, we commenced drilling or
participation in the drilling of 243 gross (157.2 net)
wells, 86.8 percent of which were completed as producers,
0.4 percent of which were dry holes and 12.8 percent
of which were awaiting completion at December 31, 2008. In
addition, in 2008, we commenced recompletion or participation in
the recompletion of 242 gross (198.6 net) wells,
90.9 percent of which were productive, 2.1 percent of
which were unsuccessful and 7 percent were still in
progress at December 31, 2008.
We produced approximately 7.1 MMBoe of oil and natural gas
during 2008 and 5.2 MMBoe of oil and natural gas during the
first six months of 2009. In addition, we increased our average
net daily production from 15.4 MBoe during the first
quarter of 2008 to 25.2 MBoe during the fourth quarter of
2008, including the impact of the acquisition of the Henry
Properties, and further to 30.0 MBoe during the second
quarter of 2009. During 2008, we increased our total estimated
net proved reserves by approximately 53.4 MMBoe, taking
into account the effects of negative price revisions
(10.1 MMBoe) and acquisitions.
S-87
Drilling
activities
The following table sets forth information with respect to wells
drilled and completed during the periods indicated. The
information should not be considered indicative of future
performance, nor should a correlation be assumed between the
number of productive wells drilled, quantities of reserves found
or economic value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended
|
|
|
Years ended December 31,
|
|
|
|
June 30, 2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
81.0
|
|
|
|
52.4
|
|
|
|
118.0
|
|
|
|
76.8
|
|
|
|
60.0
|
|
|
|
38.5
|
|
|
|
93.0
|
|
|
|
57.8
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.0
|
|
|
|
2.4
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
72.0
|
|
|
|
46.4
|
|
|
|
93.0
|
|
|
|
63.2
|
|
|
|
55.0
|
|
|
|
48.0
|
|
|
|
37.0
|
|
|
|
25.4
|
|
Dry
|
|
|
3.0
|
|
|
|
0.6
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
2.0
|
|
|
|
1.2
|
|
|
|
3.0
|
|
|
|
0.8
|
|
Total wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
153.0
|
|
|
|
98.8
|
|
|
|
211.0
|
|
|
|
140.0
|
|
|
|
115.0
|
|
|
|
86.5
|
|
|
|
130.0
|
|
|
|
83.2
|
|
Dry
|
|
|
3.0
|
|
|
|
0.6
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
2.0
|
|
|
|
1.2
|
|
|
|
10.0
|
|
|
|
3.2
|
|
|
|
|
|
|
|
Total
|
|
|
156.0
|
|
|
|
99.4
|
|
|
|
212.0
|
|
|
|
141.0
|
|
|
|
117.0
|
|
|
|
87.7
|
|
|
|
140.0
|
|
|
|
86.4
|
|
|
|
The following table sets forth information about our wells for
which drilling was in progress or are pending completion at
June 30, 2009, which are not included in the above table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
|
|
|
|
|
in-progress
|
|
|
Pending completion
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
Development wells
|
|
|
9.0
|
|
|
|
6.1
|
|
|
|
12.0
|
|
|
|
7.9
|
|
Exploratory wells
|
|
|
3.0
|
|
|
|
1.2
|
|
|
|
9.0
|
|
|
|
6.1
|
|
|
|
|
|
|
|
Total
|
|
|
12.0
|
|
|
|
7.3
|
|
|
|
21.0
|
|
|
|
14.0
|
|
|
|
S-88
Our production,
prices and expenses
The following table sets forth summary information concerning
our production results, average sales prices and operating costs
and expenses for the years ended December 31, 2008, 2007
and 2006. The actual historical data in this table excludes
production from the (i) Chase Group Properties for periods
prior to February 27, 2006 and (ii) Henry Properties
for periods prior to August 1, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
|
Years ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
3,518
|
|
|
|
1,786
|
|
|
|
4,586
|
|
|
|
3,014
|
|
|
|
2,295
|
|
Natural gas (MMcf)
|
|
|
10,369
|
|
|
|
6,451
|
|
|
|
14,968
|
|
|
|
12,064
|
|
|
|
9,507
|
|
Total (MBoe)
|
|
|
5,246
|
|
|
|
2,861
|
|
|
|
7,081
|
|
|
|
5,025
|
|
|
|
3,880
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
19,436
|
|
|
|
9,813
|
|
|
|
12,530
|
|
|
|
8,258
|
|
|
|
6,288
|
|
Natural gas (Mcf)
|
|
|
57,287
|
|
|
|
35,445
|
|
|
|
40,896
|
|
|
|
33,052
|
|
|
|
26,047
|
|
Total (Boe)
|
|
|
28,984
|
|
|
|
15,721
|
|
|
|
19,347
|
|
|
|
13,767
|
|
|
|
10,630
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without hedges (per Bbl)
|
|
$
|
47.32
|
|
|
$
|
107.39
|
|
|
$
|
91.92
|
|
|
$
|
68.58
|
|
|
$
|
60.47
|
|
Oil, with hedges (per
Bbl)a
|
|
$
|
63.36
|
|
|
$
|
86.93
|
|
|
$
|
83.55
|
|
|
$
|
64.90
|
|
|
$
|
57.42
|
|
Natural gas, without hedges (per Mcf)
|
|
$
|
4.52
|
|
|
$
|
11.33
|
|
|
$
|
9.59
|
|
|
$
|
8.08
|
|
|
$
|
6.87
|
|
Natural gas, with hedges (per
Mcf)a
|
|
$
|
5.08
|
|
|
$
|
11.23
|
|
|
$
|
9.64
|
|
|
$
|
8.33
|
|
|
$
|
7.00
|
|
Total, without hedges (per Boe)
|
|
$
|
40.67
|
|
|
$
|
92.59
|
|
|
$
|
79.80
|
|
|
$
|
60.54
|
|
|
$
|
52.62
|
|
Total, with hedges (per
Boe)a
|
|
$
|
52.53
|
|
|
$
|
79.59
|
|
|
$
|
74.49
|
|
|
$
|
58.93
|
|
|
$
|
51.12
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs
|
|
$
|
6.24
|
|
|
$
|
5.86
|
|
|
$
|
6.31
|
|
|
$
|
5.56
|
|
|
$
|
5.40
|
|
Oil and natural gas taxes
|
|
$
|
3.40
|
|
|
$
|
7.73
|
|
|
$
|
6.57
|
|
|
$
|
5.24
|
|
|
$
|
4.35
|
|
General and administrative
|
|
$
|
4.93
|
|
|
$
|
5.69
|
|
|
$
|
5.76
|
|
|
$
|
5.01
|
|
|
$
|
5.60
|
|
Depreciation, depletion and amortization
|
|
$
|
19.66
|
|
|
$
|
15.13
|
|
|
$
|
17.50
|
|
|
$
|
15.28
|
|
|
$
|
15.65
|
|
|
|
S-89
|
|
|
(a)
|
|
Includes the effect of
(i) commodity derivatives designated as hedges and reported
in oil and natural gas sales and (ii) includes the cash
payments/receipts from commodity derivatives not designated as
hedges and reported in operating costs and expenses. The
following table reflects the amounts of cash payments/receipts
from commodity derivatives not designated as hedges that were
included in computing average prices with hedges and reconciles
to the amount in gain (loss) on derivatives not designated as
hedges as reported in the statement of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
|
Years ended December 31,
|
|
(in thousands)
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Oil and natural gas sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments on oil derivatives
|
|
$
|
|
|
|
$
|
(20,573
|
)
|
|
$
|
(30,591
|
)
|
|
$
|
(11,091
|
)
|
|
$
|
(7,000
|
)
|
Cash receipts from natural gas derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
188
|
|
|
|
1,232
|
|
Designated natural gas cash flow hedges reclassified from
accumulated other comprehensive income
|
|
|
|
|
|
|
(222
|
)
|
|
|
(696
|
)
|
|
|
1,103
|
|
|
|
|
|
|
|
|
|
|
|
Total effect on oil and natural gas sales
|
|
$
|
|
|
|
$
|
(20,795
|
)
|
|
$
|
(31,287
|
)
|
|
$
|
(9,800
|
)
|
|
$
|
(5,768
|
)
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash (payments) receipts from oil derivatives
|
|
$
|
56,412
|
|
|
$
|
(15,965
|
)
|
|
$
|
(7,780
|
)
|
|
$
|
|
|
|
$
|
|
|
Cash (payments) receipts from natural gas derivatives
|
|
|
5,832
|
|
|
|
(422
|
)
|
|
|
1,426
|
|
|
|
1,815
|
|
|
|
|
|
Cash payments from interest rate derivatives
|
|
|
(779
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized mark-to-market gain (loss) on commodity and interest
rate derivatives
|
|
|
(148,117
|
)
|
|
|
(103,247
|
)
|
|
|
256,224
|
|
|
|
(22,089
|
)
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges
|
|
$
|
(86,652
|
)
|
|
$
|
(119,634
|
)
|
|
$
|
249,870
|
|
|
$
|
(20,274
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
The presentation of average prices
with hedges is a non-GAAP measure as a result of including the
cash payments/receipts from commodity derivatives that are
presented in gain (loss) on derivatives not designated as hedges
in the statements of operations. This presentation of average
prices with hedges is a means by which to reflect the actual
cash performance of our commodity derivatives for the respective
periods and presents oil and natural gas prices with hedges in a
manner consistent with the presentation generally used by the
investment community.
|
Productive
wells
The following table sets forth the number of productive oil and
gas wells on our properties at June 30, 2009:
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|
|
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|
|
|
|
|
|
|
|
Gross productive wells
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Net productive wells
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Oil
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|
Gas
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Total
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Oil
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Gas
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Total
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Core Operating Areas:
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|
|
|
|
|
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|
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|
|
|
|
|
|
|
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|
|
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New Mexico Permian
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|
1,596
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|
|
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193
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|
|
|
1,789
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|
|
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1,032.2
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|
|
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56.8
|
|
|
|
1,089.0
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Texas Permian
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|
|
1,686
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|
|
|
69
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|
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|
1,755
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|
|
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398.3
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|
|
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10.8
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|
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409.2
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Emerging plays:
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|
|
|
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|
|
|
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|
|
|
|
|
|
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Lower Abo
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14
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14
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7.3
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7.3
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Bakken/Three Forks
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31
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|
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31
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3.9
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|
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|
|
|
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3.9
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Other
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23
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|
|
|
126
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|
|
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149
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1.1
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6.0
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7.1
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|
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Total
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3,350
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|
|
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388
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3,738
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1,442.8
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73.6
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1,516.5
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|
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S-90
Summary of core
operating areas and emerging plays
The following is a summary of information regarding our core
operating areas and emerging plays that are further described
below:
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Quarter
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ended
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December 31, 2008
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June 30, 2009
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June 30, 2009
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Total
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Average net
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proved
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PV-10
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|
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daily
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Identified
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Total
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|
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reserves
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($ in
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|
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% Proved
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|
|
production
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|
drilling
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|
gross
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Total net
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|
Areas
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|
(MBoe)
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|
millions)
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% Oil
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|
|
developed
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(Boe per day)
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|
|
locations
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acreage
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|
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acreage
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|
|
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Core Operating Areas:
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|
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|
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|
|
|
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|
|
|
|
|
|
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New Mexico Permian
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|
|
95,055
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$
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1,242.8
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59.3%
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52.9%
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|
|
|
18,847
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1,654
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151,766
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|
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70,868
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Texas Permian
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39,392
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378.0
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|
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71.9%
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|
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62.9%
|
|
|
|
8,709
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|
|
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1,558
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283,043
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|
|
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77,784
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|
Emerging Plays:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Lower Abo
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|
2,127
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|
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34.4
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|
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67.8%
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|
|
|
39.3%
|
|
|
|
1,939
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|
|
|
152
|
|
|
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31,978
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|
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27,805
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Bakken/Three Forks
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|
|
206
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|
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3.8
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|
|
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83.2%
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|
|
|
100.0%
|
|
|
|
376
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|
|
|
150
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44,221
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11,661
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Other
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|
495
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4.2
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6.2%
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|
|
|
87.1%
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|
|
|
166
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|
|
|
8
|
|
|
|
147,715
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|
|
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68,645
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|
|
|
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|
|
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|
|
|
|
|
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|
|
|
|
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Total
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137,275
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|
$
|
1,663.2
|
|
|
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62.9%
|
|
|
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55.7%
|
|
|
|
30,037
|
|
|
|
3,522
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|
|
|
658,723
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|
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|
256,763
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|
|
|
Core operating
areas
New Mexico Permian. This area represents our most
significant concentration of assets and, at December 31,
2008, estimated proved reserves of 95.1 MMBoe, or
69.2 percent of our total net proved reserves and
74.7 percent of our
PV-10.
During the second quarter of 2009, our average net daily
production from this area was approximately 18.8 MBoe per
day, representing 62.8 percent of our total production for
that time period.
Within this area we target two distinct producing areas, which
we refer to as the shelf properties and the basinal properties.
The shelf properties generally produce from the Yeso,
San Andres and Grayburg formations, with producing depths
ranging from about 900 feet to 7,500 feet. The basinal
properties generally produce from the Strawn, Atoka and Morrow
formations, with producing depths generally ranging from
7,500 feet to 15,000 feet.
During the six months ended June 30, 2009, we commenced
drilling or participation in the drilling of 90 (83.3 net)
wells in this area, of which 70 (65.2 net) were completed as
producers and 20 (18.1 net) were in various stages of drilling
and completion at June 30, 2009. During the first half of
2009, we continued our (i) development of the Blinebry
interval of the Yeso formation, the top of which is located
approximately 400 feet below the top of the Paddock
interval of the Yeso formation, (ii) evaluation of drilling
on 10 acre spacing in the Blinebry interval and
(iii) evaluation of the use of larger fracture stimulation
procedures in the completion of certain wells.
At June 30, 2009, we had 151,766 gross (70,868 net)
acres in this area. At June 30, 2009, on our properties in
this area, we had identified 1,654 drilling locations, with
proved undeveloped reserves attributed to 478 of such locations.
Of these drilling locations, we identified 984 locations
intended to evaluate both the Blinebry and the Paddock
intervals, while 15 locations are intended to evaluate only the
Blinebry interval and 184 locations are intended to evaluate
only the Paddock interval.
S-91
Texas Permian. We acquired the majority of our
properties in this area from Henry Petroleum LP and certain
affiliated entities in 2008. At December 31, 2008, our
estimated proved reserves of 39.4 MMBoe in this area
accounted for 28.7 percent of our total net proved reserves
and 22.7 percent of our
PV-10.
During the month of July 2009, our average net daily production
from this area was approximately 8.7 MBoe per day,
representing 29 percent of our total production for that
time period.
Our primary objective in the Texas Permian area is the Wolfberry
in the Midland Basin. Wolfberry is the term applied
to the combined production from the Spraberry and Wolfcamp
formations, which are typically encountered at depths of 7,500
to 10,500 feet. These formations are comprised of a
sequence of basinal, interbedded shales and carbonates. We also
operate and develop properties on the Central Basin Platform
targeting the Grayburg, San Andres and Clearfork
formations, which are shallower, and are typically encountered
at depths of 4,500 to 7,500 feet. The reservoirs in these
formations are largely carbonates, limestones and dolomites.
At June 30, 2009, we had 283,043 gross (77,784 net)
acres in this area. In addition, at June 30, 2009, we had
identified 1,558 drilling locations, with proved undeveloped
reserves attributed to 489 of such locations.
During the six months ended June 30, 2009, we commenced
drilling or participation in the drilling of 44 (12.1 net) wells
in this area, of which 33 (9.1 net) were completed as producers,
two (0.4 net) were unsuccessful and nine (2.6 net) wells were in
various stages of drilling and completion at June 30, 2009.
In addition, during the first six months of 2009, we commenced
the recompletion of two (1.1 net) wells, which were producing at
June 30, 2009.
Emerging
plays
We are actively involved in drilling or participating in
drilling activities in two emerging plays, in which we had
2.3 MMBoe of proved reserves at December 31, 2008.
Lower Abo horizontal play. The Lower Abo horizontal
play is an oil play along the northwestern rim of the Delaware
Basin in Lea, Eddy and Chaves Counties, New Mexico. This play is
found at vertical depths ranging from 6,500 feet to
10,000 feet and is being exploited utilizing horizontal
drilling techniques.
At June 30, 2009, we held interests in 31,978 gross
(27,805 net) acres in this play. During the six months ended
June 30, 2009, we commenced participation in the drilling
of one well (0.4 net) in this play, which was waiting on
completion at June 30, 2009. At December 31, 2008, we
had 2.1 MMBoe of proved reserves in this play.
Bakken/Three Forks play. Our acreage in the
Bakken/Three Forks play is in the Williston Basin in North
Dakota, primarily in Mountrail and McKenzie Counties. These
Mississippian/Devonian age horizons consist of siltstones
encased within and below a highly organic oil-rich shale
package. These horizons are found at vertical depths ranging
from 9,000 feet to 11,000 feet and are being exploited
utilizing horizontal drilling techniques.
At June 30, 2009, we held interests in 44,221 gross
(11,661 net) acres in this play. During the six months ended
June 30, 2009, we commenced participation in the drilling
of twelve wells in this play with nine wells producing and three
in various stages of drilling and on completion at June 30,
2009. At December 31, 2008, we had 0.2 MMBoe of proved
reserves in this play.
S-92
Other emerging plays. We also own interests in the
following other emerging plays:
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|
Central Basin Platform of West Texas, where we drilled one
unsuccessful Woodford shale exploratory well in 2008;
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|
Western Delaware Basin of West Texas, where we drilled four
exploratory wells prior to 2008, targeting the Bone Springs,
Atoka, Barnett and Woodford shales, of which three were
unsuccessful and one was successful; and
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|
Arkoma Basin in Arkansas, where, in 2008, we participated in the
drilling of three exploratory wells targeting both the Hale and
the Fayetteville shale, of which one was unsuccessful and two
were completed and are currently in production.
|
Because of the current commodity price environment, the minimal
success from drilling in these other emerging plays and other
activity in or around these other emerging plays, we are
currently not actively pursuing further exploration activities
on these other emerging plays. We are evaluating our
alternatives related to these three other emerging plays.
Marketing
arrangements
General
We market our oil and natural gas in accordance with standard
energy practices utilizing certain of our employees and external
consultants, in each case in consultation with our chief
financial officer and our production engineers. The marketing
effort is coordinated with our operations group as it relates to
the planning and preparation of future drilling programs so that
available markets can be assessed and secured. This planning
also involves the coordination of procuring the physical
facilities necessary to connect new producing wells as
efficiently as possible upon their completion. When possible, we
negotiate with our purchasers on multiple well drilling programs
in an attempt to improve our economics on such wells due to the
commitment of potentially increased production volumes. Our
current drilling plans consist substantially of multiple well
programs.
Oil
We do not refine or process the oil we produce. A significant
portion of our oil is connected directly to pipelines via
gathering facilities in the respective field locations
throughout Southeast New Mexico, while a significant portion of
our production in West Texas is transported by truck. The oil is
then delivered either to hub facilities located in Midland,
Texas or Cushing, Oklahoma or to third party refineries located
in Southeast New Mexico and the Panhandle and Gulf Coast area of
Texas, with the majority of our oil going to a refinery in
Southeast New Mexico. This oil is also transported to the hub
facilities and refineries mentioned above. We sell the majority
of the oil we produce under short-term contracts using market
sensitive pricing. The majority of our contracts are based on a
Platts formula which is calculated based on an
intermediate posting deemed 40 degrees (typically as published
by major oil purchasers at the Cushing, Oklahoma delivery point)
for each calendar month plus the average of the Platts
P-Plus WTI price as published monthly in the Platts
Oilgram Price Report. This price is then adjusted for
differentials based upon delivery location and oil quality.
S-93
Natural
Gas
We consider all gas gathering and delivery infrastructure in the
areas of our production and evaluate market options to obtain
the best price reasonably available under the circumstances. We
sell the majority of our gas under individually negotiated gas
purchase contracts using market sensitive pricing. The majority
of our gas is subject to term agreements that extend at least
three years from the date of the subject contract.
The majority of the gas we sell is casinghead gas sold at the
lease under a percentage of proceeds processing contract. The
purchaser gathers our casinghead gas in the field where produced
and transports it via pipeline to a gas processing plant where
the liquid products are extracted. The remaining gas product is
residue gas, or dry gas. Under our percentage of proceeds
contracts, we receive a percentage of the value for the
extracted liquids and the residue gas. Each of the liquid
products has its own individual market and is therefore priced
separately.
The remaining portion of our gas is dry gas, which is gathered
at the wellhead and delivered into the purchasers residue
or mainline transportation system. In many cases, the gas
gathering and transportation is performed by a third party
gathering company which transports the production from the
production location to the purchasers mainline. The
majority of our dry gas and residue gas is subject to term
agreements that extend at least three years from the date of the
subject contract.
Our principal
customers
We sell our oil and natural gas production principally to
marketers and other purchasers that have access to pipeline
facilities. In areas where there is no practical access to
pipelines, oil is transported to storage facilities by trucks
owned or otherwise arranged by the marketers or purchasers. Our
marketing of oil and natural gas can be affected by factors
beyond our control, the effects of which cannot be accurately
predicted.
For the six months ended June 30, 2009, revenues from oil
and natural gas sales to Navajo Refining Company, L.P. and DCP
Midstream, LP accounted for approximately 47 percent and
approximately 11 percent, respectively, of our total
operating revenues. For 2008, revenues from oil and natural gas
sales to Navajo Refining Company, L.P. and DCP Midstream, LP
accounted for approximately 59 percent and approximately
18 percent, respectively, of our total operating revenues.
While the loss of either of these purchasers may result in a
temporary interruption in sales of, or a lower price for, our
production, we believe that the loss of either of these
purchasers would not have a material adverse effect on our
operations, as there are alternative purchasers in our producing
regions.
Competition
The oil and natural gas industry in the regions in which we
operate is highly competitive. We encounter strong competition
from numerous parties, ranging generally from small independent
producers to major integrated oil companies. We primarily
encounter significant competition in acquiring properties,
contracting for drilling and workover equipment and securing
trained personnel. Many of these competitors have financial and
technical resources and staffs substantially larger than ours.
As a result, our competitors may be able to pay more for
desirable
S-94
properties, or to evaluate, bid for and purchase a greater
number of properties or prospects than our financial or
personnel resources will permit.
We are also affected by competition for drilling rigs and the
availability of related equipment. The oil and natural gas
industry periodically experiences shortages of drilling and
workover rigs, equipment, pipe, materials and personnel, which
can delay developmental drilling, workover and exploitation
activities and caused significant price increases. The recent
shortage of personnel has also made it difficult to attract and
retain personnel with experience in the oil and gas industry and
has caused us to increase our general and administrative budget.
We are unable to predict the timing or duration of any such
shortages.
Competition is also strong for attractive oil and natural gas
producing properties, undeveloped leases and drilling rights.
Although we regularly evaluate acquisition opportunities and
submit bids as part of our growth strategy, we do not have any
current agreements, understandings or arrangements with respect
to any material acquisition.
Applicable laws
and regulations
Regulation of the
oil and natural gas industry
Regulation of transportation of oil. Sales of oil,
condensate and natural gas liquids are not currently regulated
and are made at negotiated prices. Nevertheless, Congress could
reenact price controls in the future.
Our sales of oil are affected by the availability, terms and
cost of transportation. The transportation of oil in common
carrier pipelines is also subject to rate regulation. The
Federal Energy Regulatory Commission, or the FERC,
regulates interstate oil pipeline transportation rates under the
Interstate Commerce Act. In general, interstate oil pipeline
rates must be cost-based, although settlement rates agreed to by
all shippers are permitted and market-based rates may be
permitted in certain circumstances. Effective January 1,
1995, the FERC implemented regulations establishing an indexing
system that permits a pipeline, subject to limited challenges,
to annually increase or decrease its transportation rates due to
inflationary changes in costs using a FERC approved index. On
March 21, 2006, FERC issued a decision setting the index
for the period July 1, 2006 through July 2011 at the
Producer Price Index for Finished Goods (PPI-FG) plus
1.3 percent. The basis for intrastate oil pipeline
regulation, and the degree of regulatory oversight and scrutiny
given to intrastate oil pipeline rates, varies from state to
state. Insofar as effective interstate and intrastate rates are
equally applicable to all comparable shippers, we believe that
the regulation of oil transportation rates will not affect our
operations in any way that is of material difference from those
of our competitors.
Further, interstate and intrastate common carrier oil pipelines
must provide service on a non-discriminatory basis at posted
tariff rates. When oil pipelines operate at full capacity,
access is governed by prorationing provisions set forth in the
pipelines published tariffs. Accordingly, we believe that
access to oil pipeline transportation services generally will be
available to us to the same extent as to our competitors.
Regulation of transportation and sale of natural
gas. Historically, the transportation and sale for
resale of natural gas in interstate commerce have been regulated
pursuant to the Natural Gas Act of 1938, the Natural Gas Policy
Act of 1978 and regulations issued under those acts by the FERC.
In the past, the federal government has regulated the prices at
which natural gas could be sold. While sales by producers of
natural gas can currently be made at uncontrolled market
S-95
prices, Congress could reenact price controls in the future, and
market participants are prohibited from engaging in market
manipulation. Deregulation of wellhead natural gas sales began
with the enactment of the Natural Gas Policy Act. In 1989,
Congress enacted the Natural Gas Wellhead Decontrol Act which
removed all Natural Gas Act and Natural Gas Policy Act price and
non-price controls affecting wellhead sales of natural gas
effective January 1, 1993.
The FERC regulates interstate natural gas transportation rates
and service conditions, which affects the marketing of natural
gas that we produce, as well as the revenues we receive for
sales of our natural gas. Since 1985, the FERC has endeavored to
make natural gas transportation more accessible to natural gas
buyers and sellers on an open and non-discriminatory basis. The
FERC has stated that open access policies are necessary to
improve the competitive structure of the interstate natural gas
pipeline industry and to create a regulatory framework that will
put natural gas sellers into more direct contractual relations
with natural gas buyers by, among other things, unbundling the
sale of natural gas from the sale of transportation and storage
services. Beginning in 1992, the FERC issued Order No. 636
and a series of related orders to implement its open access
policies. As a result of the Order No. 636 program, the
marketing and pricing of natural gas have been significantly
altered. The interstate pipelines traditional role as
wholesalers of natural gas has been eliminated and replaced by a
structure under which pipelines provide transportation and
storage service on an open access basis to others who buy and
sell natural gas. Although these orders do not directly regulate
natural gas producers, they are intended to foster increased
competition within all phases of the natural gas industry.
In 2000, the FERC issued Order No. 637 and subsequent
orders, which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things,
Order No. 637 effected changes in FERC regulations relating
to scheduling procedures, capacity segmentation, penalties,
rights of first refusal and information reporting. Most
pipelines tariff filings to implement the requirements of
Order No. 637 have been accepted by the FERC and placed
into effect.
In August, 2005, Congress enacted the Energy Policy Act of 2005
(EPAct 2005). Among other matters, EPAct 2005 amends
the Natural Gas Act to make it unlawful for any
entity, including otherwise non-jurisdictional producers
such as us, to use any deceptive or manipulative device or
contrivance in connection with the purchase or sale of natural
gas or the purchase or sale of transportation services subject
to regulation by the FERC, in contravention of rules prescribed
by the FERC. The FERCs rules implementing this provision
make it unlawful, in connection with the purchase or sale of
natural gas subject to the jurisdiction of the FERC, or the
purchase or sale of transportation services subject to the
jurisdiction of the FERC, for any entity, directly or
indirectly, to use or employ any device, scheme or artifice to
defraud; to make any untrue statement of material fact or omit
to make any such statement necessary to make the statements made
not misleading; or to engage in any act or practice that
operates as a fraud or deceit upon any person. EPAct 2005 also
gives the FERC authority to impose civil penalties for
violations of the Natural Gas Act up to $1 million per day
per violation. The new anti-manipulation rule does not apply to
activities that relate only to intrastate or other
non-jurisdictional sales, gathering or production, but does
apply to activities of otherwise non-jurisdictional entities to
the extent the activities are conducted in connection
with gas sales, purchases or transportation subject to
FERC jurisdiction, which now includes the annual reporting
requirements under Order 704. EPAct 2005 therefore reflects a
significant expansion of the FERCs enforcement authority.
We do not anticipate we will be affected any differently than
other producers of natural gas.
S-96
In December 2007, the FERC issued rules (Order 704)
requiring that any market participant, including a producer such
as Concho, that engages in wholesale sales or purchases of
natural gas that equal or exceed 2.2 million MMBtus during
a calendar year to annually report, starting May 1, 2009,
such sales and purchases to the FERC.
These rules are intended to increase the transparency of the
wholesale natural gas markets and to assist the FERC in
monitoring such markets and in detecting market manipulation. We
do not anticipate that we will be affected by these rules any
differently than other producers of natural gas.
We cannot accurately predict whether the FERCs actions
will achieve the goal of increasing competition in markets in
which our natural gas is sold. Additional proposals and
proceedings that might affect the natural gas industry are
pending before the FERC and the courts. The natural gas industry
historically has been very heavily regulated. Therefore, we
cannot provide any assurance that the less stringent regulatory
approach recently established by the FERC will continue.
However, we do not believe that any action taken will affect us
in a way that materially differs from the way it affects other
natural gas producers.
Gathering service, which occurs upstream of jurisdictional
transmission services, is regulated by the states onshore and in
state waters. Although its policy is still in flux, the FERC has
reclassified certain jurisdictional transmission facilities as
non-jurisdictional gathering facilities, which has the tendency
to increase our costs of getting gas to point of sale locations.
Intrastate natural gas transportation is also subject to
regulation by state regulatory agencies. The basis for
intrastate regulation of natural gas transportation and the
degree of regulatory oversight and scrutiny given to intrastate
natural gas pipeline rates and services varies from state to
state. During the 2007 legislative session, the Texas State
Legislature passed H.B. 3273 (Competition Bill) and
H.B. 1920 (LUG Bill). The Competition Bill gives the
Railroad Commission of Texas (RRC) the ability to
use either a cost-of-service method or a market-based method for
setting rates for natural gas gathering and intrastate
transportation pipelines in formal rate proceedings. It also
gives the RRC specific authority to enforce its statutory duty
to prevent discrimination in natural gas gathering and
transportation, to enforce the requirement that parties
participate in an informal complaint process and to punish
purchasers, transporters, and gatherers for taking
discriminatory actions against shippers and sellers. The
Competition Bill also provides producers with the unilateral
option to determine whether or not confidentiality provisions
are included in a contract to which a producer is a party for
the sale, transportation, or gathering of natural gas. The LUG
Bill modifies the informal complaint process at the RRC with
procedures unique to lost and unaccounted for gas issues. It
extends the types of information that can be requested, provides
producers with an annual audit right, and provides the RRC with
the authority to make determinations and issue orders in
specific situations. Both the Competition Bill and the LUG Bill
became effective September 1, 2007. Insofar as such
regulation within a particular state will generally affect all
intrastate natural gas shippers within the state on a comparable
basis, we believe that the regulation of similarly situated
intrastate natural gas transportation in any states in which we
operate and ship natural gas on an intrastate basis will not
affect our operations in any way that is of material difference
from those of our competitors. Like the regulation of interstate
transportation rates, the regulation of intrastate
transportation rates affects the marketing of natural gas that
we produce, as well as the revenues we receive for sales of our
natural gas.
Regulation of production. The production of oil and
natural gas is subject to regulation under a wide range of
local, state and federal statutes, rules, orders and
regulations. Federal, state and
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local statutes and regulations require permits for drilling
operations, drilling bonds and reports concerning operations.
All of the states in which we own and operate properties have
regulations governing conservation matters, including provisions
for the unitization or pooling of oil and natural gas
properties, the establishment of maximum allowable rates of
production from oil and natural gas wells, the regulation of
well spacing, and the plugging and abandonment of wells. The
effect of these regulations is to limit the amount of oil and
natural gas that we can produce from our wells and to limit the
number of wells or the locations at which we can drill, although
we can apply for exceptions to such regulations or to have
reductions in well spacing. Moreover, each state generally
imposes a production or severance tax with respect to the
production and sale of oil, natural gas and natural gas liquids
within its jurisdiction. The failure to comply with these rules
and regulations can result in substantial penalties. Our
competitors in the oil and natural gas industry are subject to
the same regulatory requirements and restrictions that affect
our operations.
Environmental,
health and safety matters
General. Our operations are subject to stringent and
complex federal, state and local laws and regulations governing
environmental protection as well as the discharge of materials
into the environment. These laws and regulations may, among
other things:
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require the acquisition of various permits before drilling
commences;
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restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with oil and natural gas drilling and production, and
saltwater disposal activities;
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limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas; and
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require remedial measures to mitigate pollution from former and
ongoing operations, such as requirements to close pits and plug
abandoned wells.
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These laws, rules and regulations may also restrict the rate of
oil and natural gas production below the rate that would
otherwise be possible. The regulatory burden on the oil and gas
industry increases the cost of doing business in the industry
and consequently affects profitability. Additionally, Congress
and federal and state agencies frequently revise environmental
laws and regulations, and any changes that result in more
stringent and costly waste handling, disposal and cleanup
requirements for the oil and gas industry could have a
significant impact on our operating costs.
The following is a summary of some of the existing laws, rules
and regulations to which our business is subject.
Waste handling. The Resource Conservation and
Recovery Act, or RCRA, and comparable state
statutes, regulate the generation, transportation, treatment,
storage, disposal and cleanup of hazardous and non-hazardous
wastes. Under the auspices of the federal Environmental
Protection Agency, or EPA, the individual states
administer some or all of the provisions of RCRA, sometimes in
conjunction with their own, more stringent requirements.
Drilling fluids, produced waters, and most of the other wastes
associated with the exploration, development, and production of
oil or natural gas are currently regulated under RCRAs
non-hazardous waste provisions. However, it is possible that
certain oil and natural gas exploration and production wastes
now classified as non-hazardous could be classified as hazardous
wastes in the future.
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Any such change could result in an increase in our costs to
manage and dispose of wastes, which could have a material
adverse effect on our results of operations and financial
position.
Comprehensive Environmental Response, Compensation and
Liability Act. The Comprehensive Environmental
Response, Compensation and Liability Act, or CERCLA,
also known as the Superfund law, imposes joint and several
liability, without regard to fault or legality of conduct, on
classes of persons who are considered to be responsible for the
release of a hazardous substance into the environment. These
persons include the owner or operator of the site where the
release occurred, and anyone who disposed or arranged for the
disposal of a hazardous substance released at the site. Under
CERCLA, such persons may be subject to joint and several
liability for the costs of cleaning up the hazardous substances
that have been released into the environment, for damages to
natural resources and for the costs of certain health studies.
In addition, it is not uncommon for neighboring landowners and
other third-parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances
released into the environment.
We currently own, lease, or operate numerous properties that
have been used for oil and natural gas exploration and
production for many years. Although we believe that we have
utilized operating and waste disposal practices that were
standard in the industry at the time, hazardous substances,
wastes, or hydrocarbons may have been released on or under the
properties owned or leased by us, or on or under other
locations, including off-site locations, where such substances
have been taken for disposal. In addition, some of our
properties have been operated by third parties or by previous
owners or operators whose treatment and disposal of hazardous
substances, wastes, or hydrocarbons was not under our control.
These properties and the substances disposed or released on them
may be subject to CERCLA, RCRA, and analogous state laws. Under
such laws, we could be required to remove previously disposed
substances and wastes, remediate contaminated property, or
perform remedial plugging or pit closure operations to prevent
future contamination.
Water discharges. The Federal Water Pollution
Control Act, or the Clean Water Act, and analogous
state laws, impose restrictions and strict controls with respect
to the discharge of pollutants, including spills and leaks of
oil and other substances, into waters of the United States. The
discharge of pollutants into regulated waters is prohibited,
except in accordance with the terms of a permit issued by the
EPA or an analogous state agency. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties
for non-compliance with discharge permits or other requirements
of the Clean Water Act and analogous state laws and regulations.
Air emissions. The federal Clean Air Act, and
comparable state laws, regulate emissions of various air
pollutants through air emissions permitting programs and the
imposition of other requirements. In addition, the EPA has
developed, and continues to develop, stringent regulations
governing emissions of toxic air pollutants at specified
sources. Federal and state regulatory agencies can impose
administrative, civil and criminal penalties for non-compliance
with air permits or other requirements of the federal Clean Air
Act and associated state laws and regulations.
Recent scientific studies have suggested that emissions of
certain gases, commonly referred to as greenhouse
gases and including carbon dioxide and methane, may be
contributing to warming of the Earths atmosphere. In
response to such studies, the U.S. Congress is considering
legislation to reduce emissions of greenhouse gases. President
Obama has expressed support for legislation to restrict or
regulate emissions of greenhouse gases. In addition, more than
one-
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third of the states, either individually or through multi-state
regional initiatives, already have begun implementing legal
measures to reduce emissions of greenhouse gases, primarily
through the planned development of emission inventories or
regional greenhouse gas cap and trade programs. Depending on the
particular program, we could be required to purchase and
surrender allowances for greenhouse gas emissions resulting from
our operations. This requirement could increase our operational
and compliance costs and result in reduced demand for our
products.
Also, as a result of the United States Supreme Courts
decision on April 2, 2007 in Massachusetts, et al. v.
EPA, the EPA may regulate greenhouse gas emissions from mobile
sources such as cars and trucks even if Congress does not adopt
new legislation specifically addressing emissions of greenhouse
gases. The Courts holding in Massachusetts that greenhouse
gases including carbon dioxide fall under the federal Clean Air
Acts definition of air pollutant may also
result in future regulation of carbon dioxide and other
greenhouse gas emissions from stationary sources. In July 2008,
the EPA released an Advance Notice of Proposed
Rulemaking regarding possible future regulation of
greenhouse gas emissions under the Clean Air Act, in response to
the Supreme Courts decision in Massachusetts. In the
notice, the EPA evaluated the potential regulation of greenhouse
gases under the Clean Air Act and other potential methods of
regulating greenhouse gases. Although the notice did not propose
any specific, new regulatory requirements for greenhouse gases,
it indicates that federal regulation of greenhouse gas emissions
could occur in the future even if Congress does not adopt new
legislation specifically addressing emissions of greenhouse
gases. In April 2009, the EPA issued a notice of its proposed
finding and determination that emissions of greenhouse gases are
presenting an endangerment to human health and the environment,
which, if finalized, would enable the EPA to begin regulating
such emissions under existing provisions of the federal Clear
Air Act. Although it is not possible at this time to predict how
legislation or new regulations that may be adopted to address
greenhouse gas emissions would impact our business, any such new
federal, regional or state restrictions on emissions of carbon
dioxide or other greenhouse gases that may be imposed in areas
in which we conduct business could result in increased
compliance costs or additional operating restrictions, which
could have a material adverse effect on our business and the
demand for our products.
National Environmental Policy Act. Oil and natural
gas exploration and production activities on federal lands are
subject to the National Environmental Policy Act, or
NEPA. NEPA requires federal agencies, including the
Department of Interior, to evaluate major agency actions having
the potential to significantly impact the environment. In the
course of such evaluations, an agency will prepare an
environmental assessment that assesses the potential direct,
indirect and cumulative impacts of a proposed project and, if
necessary, will prepare a more detailed environmental impact
statement that may be made available for public review and
comment. All of our current exploration and production
activities, as well as proposed exploration and development
plans, on federal lands require governmental permits that are
subject to the requirements of NEPA. This process has the
potential to delay the development of oil and natural gas
projects.
OSHA and other laws and regulation. We are subject
to the requirements of the federal Occupational Safety and
Health Act, or OSHA, and comparable state statutes.
The OSHA hazard communication standard, the EPA community
right-to-know regulations under the Title III of CERCLA and
similar state statutes require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations. We believe that we are in substantial
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compliance with these applicable requirements and with other
OSHA and comparable requirements.
We believe that we are in substantial compliance with all
existing environmental laws and regulations applicable to our
current operations and that our continued compliance with
existing requirements will not have a material adverse impact on
our financial condition and results of operations. For instance,
we did not incur any material capital expenditures for
remediation or pollution control activities for the year ended
December 31, 2008. Additionally, as of the date of this
prospectus supplement, we are not aware of any environmental
issues or claims that will require material capital expenditures
during 2009. However, we cannot assure you that the passage or
application of more stringent laws or regulations in the future
will not have an negative impact on our financial position or
results of operation.
Our
Employees
At June 30, 2009, we employed 266 persons, including
137 in operations, 37 in financial and accounting, 36 in land,
18 in geosciences, 20 in reservoir engineering, 14 in
administration and 4 in legal. Of these, 239 worked at our
Midland, Texas headquarters, including Texas field operations,
and 27 in our New Mexico field operations. Our future success
will depend partially on our ability to attract, retain and
motivate qualified personnel. We are not a party to any
collective bargaining agreements and have not experienced any
strikes or work stoppages. We consider our relations with our
employees to be satisfactory. We also utilize the services of
independent contractors to perform various field and other
services.
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Transactions with
related persons
General
In accordance with its charter and our Related Persons
Transaction Policy adopted by the Board of Directors (RPT
Policy) on November 8, 2007, the Audit Committee of
the Board of Directors periodically reviews all related person
transactions that the rules of the SEC require be disclosed in
our proxy statement and make a determination regarding the
authorization or ratification of any such transactions.
Our RPT Policy pre-approves certain related person transactions,
including:
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any employment of an executive officer if his or her
compensation is required to be reported in our proxy statement
under Item 402;
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director compensation which is required to be reported in our
proxy statement under Item 402;
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any transaction with an entity at which the related
persons only relationship is as a director or manager
(other than sole director or manager) or beneficial owner of
less than 10% of the entitys equity, if the aggregate
amount involved does not exceed the greater of $1,000,000 or 2%
of the entitys annual revenues; and
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transactions with Chase Oil Corporation (Chase Oil)
and its affiliates, pursuant to which we acquire equipment,
services or supplies in the ordinary course of its oil and gas
business.
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The Audit Committee Chairman may approve any related person
transaction in which the aggregate amount involved is expected
to be less than $120,000. A summary of such approved
transactions and each new related person transaction deemed
pre-approved under the RPT Policy is provided to the Audit
Committee for its review. The Audit Committee has the authority
to modify the RPT Policy regarding pre-approved transactions or
to impose conditions upon our ability to participate in any
related person transaction.
There were no related person transactions during 2008 or the
first half of 2009 which were required to be reported where the
procedures described above required review, approval or
ratification, but where these procedures were not followed.
We entered into certain of the transactions and contractual
arrangements described below involving our officers, directors
or principal stockholders before the adoption of the RPT Policy.
None of these transactions were reviewed by the Audit Committee.
We believe that the terms of these arrangements and agreements
were at least as favorable as they would have been had we
contracted with unrelated third parties under the same or
similar circumstances.
Transactions
involving directors
We leased certain mineral interests in Andrews County, Texas
from a partnership in which Tucker S. Bridwell, one of
our directors, is the general partner and in which he holds a
3.5% interest. We paid royalties of approximately $332,000
during the year ended December 31, 2008 and approximately
$56,000 during the six months ended June 30, 2009
attributable to such mineral interests. We owed this partnership
royalty payments of approximately $13,000 at June 30, 2009.
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Until he joined Keeneland Capital in 2009, A. Wellford Tabor,
one of our directors, was a member of Wachovia Capital Partners,
a merchant banking arm of Wells Fargo & Company. An
affiliate of Wachovia Capital Partners and Wells
Fargo & Company has been, and may continue to be, one
of our stockholders. In addition, both Wachovia Bank, National
Association and Wells Fargo Bank, National Association are
affiliates of Wells Fargo & Company and are lenders
under our credit facility and counterparties under certain of
our hedging instruments. Wells Fargo Securities, LLC, and Wells
Fargo Bank, National Association, affiliates of Wells Fargo
& Company, will act as an underwriter and trustee under the
indenture, respectively, with respect to the notes offered
hereby.
Consulting
agreement with Steven L. Beal
On June 9, 2009, we entered into a Consulting Agreement
(the Consulting Agreement) with Steven L. Beal,
under which Mr. Beal began serving as a consultant on
July 1, 2009. During the term of the consulting
relationship, Mr. Beal will receive a consulting fee of $20,000
per month and a monthly reimbursement for his medical and dental
coverage costs. During the period Mr. Beal serves as a
non-employee member of the Board of Directors, he will also
receive the standard compensation package for non-employee
members of the Board of Directors. During the term of the
consulting relationship, Mr. Beal cannot, without prior
consent of our Chief Executive Officer, compete with us in the
oil and natural gas industry (other than serving as a board
member
and/or
owning securities of publicly held entities engaged in such
industry).
Transactions
involving executive officers
Overriding
royalty interests
Prior to the formation of Concho Equity Holdings Corp.,
Messrs. Leach, Beal, Copeland and Wright and another of our
former executives acquired working interests in 120 undeveloped
acres located in Lea County, New Mexico. In connection with the
formation of Concho Equity Holdings Corp., these working
interests were sold to that company in November 2004 for
$120,000 in the aggregate, and Messrs. Leach, Beal,
Copeland and Wright and such former executive each retained a
0.25% overriding royalty interest in any production attributable
to this acreage. We have not drilled any wells that are subject
to these overriding royalty interests and, therefore, no
payments have been made in connection with these interests.
In April 2005, we acquired certain working interests in
properties located in Culberson County, Texas for approximately
$2.5 million from an entity partially owned by a person who
was one of our executive officers until March 31, 2008. In
connection with this acquisition, such entity retained a 2%
overriding royalty interest in the acquired properties, which
overriding royalty interest was later conveyed in equal shares
by such entity to such person and one of our non-executive
employees.
Transactions
involving Chase Oil Corporation and its affiliates
Silver Oak
drilling contracts
Silver Oak Drilling, LLC, an affiliate of Chase Oil, owns and
operates drilling rigs, four of which we use for a substantial
portion of our operations in Southeast New Mexico. During the
six months ended June 30, 2009 and the year ended
December 31, 2008, we paid Silver Oak Drilling
approximately $10.3 million and $18.3 million,
respectively, for drilling services in
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Southeast New Mexico. Our contracts with Silver Oak
Drilling were recently extended through June 30, 2010.
Saltwater
disposal services agreement
Among the assets we acquired from Chase Oil in February 2006 is
an undivided interest in a saltwater gathering and disposal
system in Southeast New Mexico, which is owned and maintained
under a written agreement among us and Chase Oil and certain of
its affiliates, and under which we as operator gather and
dispose of produced water. The system is owned jointly by us and
Chase Oil and its affiliates in undivided ownership percentages,
which are annually redetermined as of January 1 on the basis of
each partys percentage contribution of the total volume of
produced water disposed of through the system during the prior
calendar year. At January 1, 2009, we owned 95.4% of the
system and Chase Oil and its affiliates owned 4.6%.
Software license
agreement
At March 1, 2006, we entered into a Software License
Agreement with Enertia Software Systems, which is an affiliate
of Chase Oil, with an initial term of 99 years. We are
using the subject software in the following software functional
areas: accounting and financial reporting, well production and
field data gathering, land and contracts, and payroll
processing. The Software License Agreement provides for up to
fifty-five concurrent users with the ability for us to upgrade
in five concurrent user increments for a one-time license fee of
$50,000 for each concurrent user increment. The license can be
terminated by either party by providing notice to the other
party at least six months prior to the date on which the
termination will be effective. During the year ended
December 31, 2008, we paid Enertia approximately $258,000
for consulting and programming services, $233,000 for additional
licensing fees and $22,000 for annual maintenance fees, a total
of $513,000.
Overriding
royalty interests
Certain persons affiliated with Chase Oil own overriding royalty
interests in some of the properties which we operate. The
aggregate amount of royalty payments made in connection with
these overriding royalty interests was approximately
$0.5 million and $3.1 million during the six months
ended June 30, 2009 and the year ended December 31,
2008, respectively.
Other
transactions
We also conduct business from time to time with other companies
that are affiliated with Chase Oil, with respect to oilfield
services or supplies and other services that we use in the
ordinary course of our operations. We are not required to
purchase products or services from these companies, and we are
able to purchase these products and services from other vendors
who are not affiliated with Chase Oil. During the six months
ended June 30, 2009 and the year ended
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December 31, 2008, we paid the approximate amounts
indicated to the following such affiliates of Chase Oil (in
thousands):
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Six months ended
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Year ended
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June 30, 2009
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December 31, 2008
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Production Specialty Services, Inc.
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$
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$
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2,020
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Catalyst Oilfield Services LLC
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1,999
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1,927
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Deer Horn Aviation Ltd. Co.
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101
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383
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Total
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$
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2,100
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$
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4,330
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Registration
rights agreement
We are a party to a registration rights agreement with certain
of our stockholders, certain of our executive officers and the
former stockholders of Concho Equity Holdings Corp., which was
merged into another of our subsidiaries.
Demand
registration rights
According to the registration rights agreement, holders of 20%
of the aggregate shares held by the former stockholders of
Concho Equity Holdings Corp. may request in writing that we
register their shares by filing a registration statement under
the Securities Act, so long as the anticipated aggregate
offering price, net of underwriting discounts and commissions,
exceeds $50 million.
Piggy-back
registration rights
If we propose to file a registration statement under the
Securities Act relating to an offering of our common stock
(other than on a
Form S-4
or a
Form S-8),
upon the written request of holders of registrable securities,
we will use our commercially reasonable efforts to include in
such registration, and any related underwriting, all of the
registrable securities requested to be included, subject to
customary cutback provisions. There is no limit to the number of
these piggy-back registrations in which these
holders may request their shares be included.
Registration
procedures and expenses
We generally will bear the registration expenses incurred in
connection with any registration, including all registration,
filing and qualification fees, printing and accounting fees, but
excluding underwriting discounts and commissions. We have agreed
to indemnify the subject stockholders against certain
liabilities, including liabilities under the Securities Act, in
connection with any registration effected under the registration
rights agreement. We are not obligated to effect any
registration more than one time in any six-month period and
these registration rights terminate on August 7, 2017.
S-105
Management
The following table sets forth the names and ages of all of our
executive officers and directors.
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Name
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Agea
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Position
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Timothy A. Leach
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49
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Chairman of the Board of Directors, Chief Executive Officer,
President and Class I Director
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David W. Copeland
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52
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Vice President, General Counsel and Secretary
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Jack F. Harper
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38
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Vice PresidentBusiness Development and Capital Markets
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Darin G. Holderness
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45
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Vice President, Chief Financial Officer and Treasurer
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Matthew G. Hyde
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53
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Vice PresidentExploration and Land
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E. Joseph Wright
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49
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Vice PresidentEngineering and Operations
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Steven L. Beal
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50
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Class II Director
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Tucker S. Bridwell
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57
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Class II Director
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William H. Easter III
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59
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Class I Director
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W. Howard Keenan, Jr.
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58
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Class I Director
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Ray M. Poage
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62
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Class III Director
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A. Wellford Tabor
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40
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Class III Director
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(a)
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As of September 1, 2009.
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Timothy A. Leach has been a director and our Chairman of
the Board of Directors and Chief Executive Officer since our
formation in February 2006; he has also been our President since
July 1, 2009. Mr. Leach was the Chairman of the Board
of Directors and Chief Executive Officer of Concho Equity
Holdings Corp. from its formation in April 2004 until it was
merged into another of our subsidiaries at January 1, 2009.
Mr. Leach was Chairman of the Board and Chief Executive
Officer of Concho Oil & Gas Corp. from its formation
in January 2001 until its sale in January 2004. From January
2004 to April 2004, Mr. Leach was involved in private
investments. Mr. Leach was Chairman of the Board and Chief
Executive Officer of Concho Resources Inc. (which was a
different company than we are) from its formation in August 1997
until its sale in June 2001. From September 1989 until May 1997,
Mr. Leach was employed by Parker & Parsley
Petroleum Company (now Pioneer Natural Resources Company) in a
variety of capacities, including serving as Executive Vice
President and as a member of Parker & Parsley
Petroleum Companys Executive Committee. He is a graduate
of Texas A&M University with a Bachelor of Science degree
in Petroleum Engineering.
David W. Copeland has been our Vice President, General
Counsel and corporate Secretary since our formation in February
2006. Mr. Copeland was the Vice President, General Counsel
and corporate Secretary of Concho Equity Holdings Corp. from its
formation in April 2004 until it was merged into another of our
subsidiaries at January 1, 2009. Mr. Copeland was a
director and the Executive Vice President, General Counsel and
corporate Secretary of Concho Oil & Gas Corp. from its
formation in January 2001 until its sale in January 2004. From
January 2004 to April 2004, Mr. Copeland was involved in
private investments. Mr. Copeland was a director and the
Vice President, General Counsel and corporate Secretary of
Concho Resources Inc. (which was a different company than we
are) from its formation in August 1997 until its sale in June
2001. From 1991 until June 1997, Mr. Copeland was employed
in the Legal Department of
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Parker & Parsley Petroleum Company (now Pioneer
Natural Resources Company), and served as its Vice President,
Associate General Counsel from 1994 until June 1997. Prior to
joining Parker & Parsley Petroleum Company,
Mr. Copeland was a partner with the Midland, Texas law firm
of Stubbeman, McRae, Sealy, Laughlin & Browder, where
his practice was concentrated in corporate, banking and other
commercial matters. He is a graduate of Midwestern State
University with a Bachelor of Business Administration degree in
Accounting and a graduate of Texas Tech University School of Law
with a Doctor of Jurisprudence degree.
Jack F. Harper has been our Vice PresidentBusiness
Development and Capital Markets since May 2007. Mr. Harper
was our Director of Investor Relations and Business Development
from July 2006 until May 2007. From October 2005 until July
2006, Mr. Harper was involved in private investments. From
October 2002 until October 2005, Mr. Harper was employed by
Unocal Corporation where he served as Manager of Planning and
Evaluation and Manager of Business Development for Unocal
Corporations wholly owned subsidiary, Pure Resources, Inc.
From May 2000 until October 2002, Mr. Harper was employed
by Pure Resources, Inc. in a variety of capacities, including in
his last position as Vice President, Finance and Investor
Relations. From December 1996 until May 2000, Mr. Harper
was employed by Tom Brown, Inc., where his last position was
Vice President, Investor Relations, Corporate Development and
Treasurer. He is a graduate of Baylor University with a Bachelor
of Business Administration degree in Finance.
Darin G. Holderness has been our Vice President, Chief
Financial Officer and Treasurer since August 2008. From May 2008
until August 2008, Mr. Holderness was employed by Eagle
Rock Energy Partners, L.P. as Senior Vice President and Chief
Financial Officer. From November 2004 until May 2008,
Mr. Holderness served as Vice President and Chief
Accounting Officer of Pioneer Natural Resources Company. From
April 2004 until November 2004, he served as Vice President and
Chief Financial Officer of Basic Energy Services, Inc. From May
2000 until April 2004, he was an officer, including serving as
Vice President and Controller, of Pure Resources, Inc.
Mr. Holderness holds a Bachelor of Business Administration
degree in Accounting from Boise State University and is a
certified public accountant.
Matthew G. Hyde joined us as our Vice
PresidentExploration in May 2008, and was appointed Vice
PresidentExploration and Land in November 2008. From
January 2008 to May 2008, Mr. Hyde was involved in private
investments. From March 2001 to December 2007, Mr. Hyde was
an Asset Manager of Oxy Permian, a business unit of Occidental
Petroleum Corporation. From April 1998 to February 2001,
Mr. Hyde served as President and General Manager of
Occidental Petroleum Corporations international business
unit in Oman. Prior to that role, Mr. Hyde served in a
variety of domestic and international exploration positions for
Occidental Petroleum Corporation, including Regional Exploration
Manager responsible for Latin American exploration activities.
He is a graduate of the University of Vermont and the University
of Massachusetts where he obtained Bachelor of Arts and Master
of Science degrees, respectively, in Geology. Mr. Hyde also
holds a Master of Business Administration degree from the
University of California Los Angeles.
E. Joseph Wright has been our Vice
PresidentEngineering and Operations since our formation in
February 2006. Mr. Wright was the Vice
PresidentOperations & Engineering of Concho
Equity Holdings Corp. from its formation in April 2004 until it
was merged into another of our subsidiaries at January 1,
2009. Mr. Wright was Vice
PresidentOperations/Engineering of Concho Oil &
Gas Corp. from its formation in January 2001 until its sale in
January 2004. From January 2004 to April 2004, Mr. Wright
was involved in private investments. Mr. Wright served in
various engineering and operations positions for Concho
Resources Inc. (which was a different
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company than we are), including serving as its Vice
PresidentOperations, from 1998 until its sale in June
2001. From 1982 until February 1998, Mr. Wright was
employed by Mewbourne Oil Company in several operations,
engineering and capital markets positions. He is a graduate of
Texas A&M University with a Bachelor of Science degree in
Petroleum Engineering.
Steven L. Beal has been a director since our formation in
February 2006 and a consultant to us since July 1, 2009.
Mr. Beal was our President and Chief Operating Officer from
our formation in February 2006 until his retirement effective
June 30, 2009. Mr. Beal was a director and the
President and Chief Operating Officer of Concho Equity Holdings
Corp. from its formation in April 2004 until it was merged into
another of our subsidiaries at January 1, 2009.
Mr. Beal was a director and the Executive Vice President
and Chief Financial Officer of Concho Oil & Gas Corp.
from its formation in January 2001 until he became its President
and Chief Operating Officer in August 2002, a position he held
until its sale in January 2004. From January 2004 to April 2004,
Mr. Beal was involved in private investments. Mr. Beal
was a director and the Vice President and Chief Financial
Officer of Concho Resources Inc. (which was a different company
than we are) from its formation in August 1997 until its sale in
June 2001. From October 1988 until May 1997, Mr. Beal was
employed by Parker & Parsley Petroleum Company (now
Pioneer Natural Resources Company) in a variety of capacities,
including serving as its Senior Vice President and Chief
Financial Officer and as a member of Parker & Parsley
Petroleum Companys Executive Committee. From 1981 until
February 1988, Mr. Beal was employed by the accounting firm
of Price Waterhouse (now PricewaterhouseCoopers). He is a
graduate of the University of Texas with a Bachelor of Business
Administration degree in Accounting.
Tucker S. Bridwell has been a director of ours since
February 2006 and currently serves as the Chairman of the
Nominating & Governance Committee and a member of the Audit
Committee. Mr. Bridwell was a director of Concho Equity
Holdings Corp. from its inception in April 2004 until February
2006. Mr. Bridwell has been the President of each of the
Mansefeldt Investment Corporation and the Dian Graves Owen
Foundation since September 1997 and manages investments for both
entities; both are stockholders of ours. He has been in the
energy business in various capacities for over twenty-five
years. Mr. Bridwell served as Chairman of the Board of
Directors of First Permian, LLC from 2000 until its sale to
Energen Corporation in April 2002. Mr. Bridwell is also a
director of Petrohawk Energy Corporation and First Financial
Bankshares, Inc., and serves on their respective audit
committees. He is a graduate of Southern Methodist University
with a Bachelor of Business Administration degree in accounting
and a Master of Business Administration degree, and is a
certified public accountant.
William H. Easter III has been a director of ours
since February 2008 and serves as a member of the Audit
Committee and the Compensation Committee. Mr. Easters
career spans over thirty years in the areas of natural gas
supply, processing, marketing and transportation, as well as
crude oil/petroleum refining, marketing and transportation.
Mr. Easter is the past Chairman of the Board of Directors,
President and Chief Executive Officer of DCP Midstream, LLC
(formerly Duke Energy Field Services, LLC), having retired from
such company in January 2008. He joined DCP Midstream, LLC in
January 2004 as Chairman, President and Chief Executive Officer.
He also served as director of TEPPCO GP, LLC, the general
partner of TEPPCO Partners, L.P., from January 2004 until
February 2005, and as a director of DCP Midstream GP, LLC, the
general partner of DCP Midstream Partners, LP, from November
2005 to January 2008. From August 2002 through January 2004,
Mr. Easter served as Vice President of State Government
Affairs for ConocoPhillips. From 1998 to 2002, Mr. Easter
served as General Manager of the Gulf Coast Refining, Marketing
and Transportation Business Unit of Conoco Inc. Since his
retirement from DCP Midstream, LLC in January 2008,
Mr. Easter has been involved in private investments. He
also served as a
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member of the Board of Directors for Junior Achievement Rocky
Mountain Inc. and the University of Colorado at Denver Business
School Advisory Board. Mr. Easter earned his Bachelor of
Business Administration degree from the University of Houston
and his Master of Science in Management from The Graduate School
of Business at Stanford University.
W. Howard Keenan, Jr. has been a director of ours
since February 2006 and serves as a member of the Compensation
Committee and the Nominating & Governance Committee.
Mr. Keenan previously was a director of Concho Equity
Holdings Corp., Concho Oil & Gas Corp. and Concho
Resources Inc. (which was a different company than we are).
Mr. Keenan has over thirty years of experience in the
financial and energy businesses. Since 1997, he has been a
Member of Yorktown Partners LLC, a private equity investment
manager focused on the energy industry. Two limited partnerships
managed by Yorktown Partners LLC are stockholders of ours.
Mr. Keenan currently serves on the Board of Directors of
GeoMet, Inc. From 1975 to 1997, he was in the Corporate Finance
Department of Dillon, Read & Co. Inc. and active in
the private equity and energy areas, including the founding of
the first Yorktown Partners fund in 1991. He is serving or has
served as a director of multiple Yorktown Partners portfolio
companies. Mr. Keenan holds a Bachelor of Arts degree in
English from Harvard College and a Master of Business
Administration from Harvard University.
Ray M. Poage has been a director of ours since August
2007 and serves as the Chairman of the Audit Committee.
Mr. Poage was a partner in KPMG LLP from 1980 to June 2002
when he retired. Mr. Poages responsibilities included
supervising and managing both audit and tax professionals and
providing accounting services, primarily in the area of
taxation, to private and publicly held companies engaged in the
oil and natural gas industry. Since June 2002, Mr. Poage
has been involved in private investments. Mr. Poage
currently serves as the Chairman of the audit committee and as a
director of Parallel Petroleum Corporation. Mr. Poage
received a Bachelor of Business Administration degree in
Accounting from Texas Tech University in 1972 and is a certified
public accountant.
A. Wellford Tabor has been a director of ours since
February 2006 and currently serves as the Chairman of the
Compensation Committee and a member of the Audit Committee and
Nominating & Governance Committee. Mr. Tabor was a
director of Concho Equity Holdings Corp. from its inception in
April 2004 until February 2006. Mr. Tabor also served as a
director of Concho Oil & Gas Corp. from March 2003
until its sale to a large domestic independent oil and gas
company in January 2004. Mr. Tabor is currently the
managing partner of Keeneland Capital. Prior to joining
Keeneland Capital in 2009, Mr. Tabor was a partner with
Wachovia Capital Partners, a merchant banking arm of Wells Fargo
& Company. An affiliate of Wachovia Capital Partners and
Wells Fargo & Company has been, and may continue to be a
stockholder of ours. Mr. Tabor was a director at The Beacon
Group from 1995 to 2000. From 1991 to 1993, he worked in the
Investment Banking Division at Morgan Stanley & Co.
Mr. Tabor currently serves on the board of directors of
several privately held companies and not-for-profit
organizations. Mr. Tabor earned his undergraduate degree in
history from The University of Virginia and his Master of
Business Administration degree from The Graduate School of
Business at Stanford University.
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Description of
other indebtedness
Senior secured
credit facility
Following the termination of our second lien credit facility on
July 31, 2008, our only outstanding long-term indebtedness
exists under our credit facility. Our credit facility is subject
to scheduled semiannual borrowing base redeterminations, and has
a maturity date of July 31, 2013. In April 2009, the
lenders reaffirmed our $960 million borrowing base under
the credit facility until the next scheduled borrowing base
redetermination in October 2009. Between scheduled borrowing
base redeterminations, we and, if requested by
662/3 percent
of the lenders, the lenders, may each request one special
redetermination. At June 30, 2009, we had letters of credit
outstanding under our credit facility totaling approximately
$25,000, and our availability to borrow additional funds was
approximately $300 million. Pursuant to the terms of our
credit facility, our borrowing base will be reduced by $0.30 for
every dollar of new indebtedness evidenced by unsecured senior
notes or unsecured senior subordinated notes that we issue. As a
result of this provision, the borrowing base under our credit
facility would have been reduced by $90 million due to our
issuance and sale of the notes. However, as of the date hereof
we have received waivers of this provision from lenders
representing approximately 95.4% of our borrowing base,
resulting in an actual reduction of approximately
$4.1 million. As a result, following the application of the
proceeds of this offering in the manner described in Use
of proceeds and giving effect to the reduction to our
borrowing base as a result of the issuance of the notes offered
hereby, we expect to have approximately $582.8 million of
availability under our credit facility and a revised borrowing
base of $955.9 million. To the extent we receive any
additional waivers of this provision from the lenders after the
date hereof but before the closing of this offering, our
borrowing base availability would increase accordingly.
Advances on the credit facility bear interest, at our option,
based on (i) the prime rate of JPMorgan Chase Bank
(JPM Prime Rate) (3.25 percent at June 30,
2009) or (ii) a Eurodollar rate (substantially equal
to the London Interbank Offered Rate). At June 30, 2009,
the interest rates of Eurodollar rate advances and JPM Prime
Rate advances vary, with interest margins ranging from 200 to
300 basis points and 112.5 to 212.5 basis points,
respectively, per annum depending on the debt balance
outstanding. At June 30, 2009, we paid commitment fees on
the unused portion of the available borrowing base of
50 basis points per annum.
Our credit facility also includes a
same-day
advance facility under which we may borrow funds on a daily
basis from the administrative agent.
Same-day
advances cannot exceed $25 million, and the maturity dates
cannot exceed fourteen days. The interest rate on this facility
is the JPM Prime Rate plus the applicable interest margin.
Our obligations under the credit facility are secured by a first
lien on substantially all of our oil and natural gas properties.
In addition, all of our subsidiaries are guarantors and all
membership interests in our subsidiaries owned by us have been
pledged to secure borrowings under the credit facility.
The credit agreement contains various restrictive covenants and
compliance requirements which include:
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maintenance of certain financial ratios including
(i) maintenance of a quarterly ratio of total debt to
consolidated earnings before interest expense, income taxes,
depletion, depreciation, and amortization, exploration expense
and other noncash income and expenses to be no greater than 4.0
to 1.0, and (ii) maintenance of a ratio of current assets
to current liabilities, excluding noncash assets and liabilities
related to financial derivatives and asset retirement
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obligations and including the unfunded amounts under the credit
facility, to be no less than 1.0 to 1.0;
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limits on the incurrence of certain additional indebtedness and
certain types of liens;
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restrictions on sale and leaseback transactions;
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limitations on making investments;
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limitations on entering into transactions with affiliates;
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restrictions on making material changes to the type of business
we conduct or our business structure;
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restrictions on making guarantees;
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restrictions as to mergers and sales or transfer of
assets; and
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a restriction on the payment of cash dividends.
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At June 30, 2009, we were in compliance with all of the
covenants and compliance requirements under our credit facility.
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Description of
notes
We will issue the Notes under an indenture, as supplemented by a
supplemental indenture (collectively the Indenture),
among us, the Subsidiary Guarantors and Wells Fargo Bank,
National Association, as trustee (the Trustee). The
terms of the Notes include those expressly set forth in the
Indenture and those made part of the Indenture by reference to
the Trust Indenture Act of 1939, as amended (the
Trust Indenture Act). The Indenture is
unlimited in aggregate principal amount, although the issuance
of Notes in this offering will be limited to $300 million.
We may issue an unlimited principal amount of additional notes
having identical terms and conditions as the Notes (the
Additional Notes), as well as debt securities of
other series. We will only be permitted to issue such Additional
Notes in compliance with the covenant described under the
subheading Certain covenantsLimitation on
Indebtedness and Preferred Stock. Any Additional Notes
will be part of the same series as the Notes that we are
currently offering and will vote on all matters with the holders
of the Notes. Unless the context otherwise requires, for all
purposes of the Indenture and this Description of
notes, references to the Notes include any Additional
Notes actually issued.
This description of notes, together with the Description
of debt securities included in the accompanying base
prospectus, is intended to be a useful overview of the material
provisions of the Notes and the Indenture. Since this
description of notes and such Description of debt
securities is only a summary, you should refer to the
Indenture for a complete description of the obligations of the
Company and your rights. This description of notes supersedes
the Description of debt securities in the
accompanying base prospectus to the extent it is inconsistent
with such Description of debt securities.
You will find the definitions of capitalized terms used in this
description of notes under the heading Certain
definitions. For purposes of this description, references
to the Company, we, our and
us refer only to Concho Resources Inc. and not to
any of its subsidiaries. The registered holder of a Note will be
treated as the owner of it for all purposes. Only registered
holders of Notes will have rights under the Indenture, and all
references to holders in this description of notes
are to registered holders of Notes.
General
The Notes. The Notes:
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are general unsecured, senior obligations of the Company;
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mature on October 1, 2017;
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will be issued in denominations of $2,000 and integral multiples
of $1,000 in excess of $2,000;
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will be represented by one or more registered Notes in global
form, but in certain circumstances may be represented by Notes
in definitive form, see Book-entry, delivery and
form;
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rank senior in right of payment to all existing and future
Subordinated Obligations of the Company;
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rank equally in right of payment to any future senior
Indebtedness of the Company, without giving effect to collateral
arrangements;
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will be initially unconditionally guaranteed on a senior basis
by each current Subsidiary of the Company, see
Subsidiary guarantees;
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effectively rank junior to any existing or future secured
Indebtedness of the Company, including amounts that may be
borrowed under our Senior Secured Credit Agreement, to the
extent of the value of the collateral securing such
Indebtedness; and
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rank structurally junior to the indebtedness and other
obligations of our future non-guarantor subsidiaries, if any.
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Interest. Interest on the Notes will:
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accrue at the rate of 8.625% per annum;
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accrue from the Issue Date or, if interest has already been
paid, from the most recent interest payment date;
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be payable in cash semi-annually in arrears on April 1 and
October 1, commencing on April 1, 2010;
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be payable to the holders of record on the March 15 and
September 15 immediately preceding the related interest
payment dates; and
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be computed on the basis of a
360-day year
comprised of twelve
30-day
months.
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If an interest payment date falls on a day that is not a
Business Day, the interest payment to be made on such interest
payment date will be made on the next succeeding Business Day
with the same force and effect as if made on such interest
payment date, and no additional interest will accrue as a result
of such delayed payment. The Company will pay interest on
overdue principal of the Notes at the above rate, and overdue
installments of interest at such rate, to the extent lawful.
Payments on the
Notes; paying agent and registrar
We will pay principal of, premium, if any, and interest on the
Notes at the office or agency designated by the Company in the
City and State of New York, except that we may, at our option,
pay interest on the Notes by check mailed to holders of the
Notes at their registered address as it appears in the
registrars books. We have initially designated the
corporate trust office of the Trustee in New York, New York to
act as our paying agent and its corporate trust office in Fort
Worth, Texas to act as our registrar. We may, however, change
the paying agent or registrar without prior notice to the
holders of the Notes, and the Company or any of its Restricted
Subsidiaries may act as paying agent or registrar.
We will pay principal of, premium, if any, and interest on,
Notes in global form registered in the name of or held by The
Depository Trust Company or its nominee in immediately
available funds to The Depository Trust Company or its
nominee, as the case may be, as the registered holder of such
global Note.
Transfer and
exchange
A holder may transfer or exchange Notes in accordance with the
Indenture. The registrar and the Trustee may require a holder,
among other things, to furnish appropriate endorsements and
transfer documents in connection with a transfer of Notes. No
service charge will be imposed by
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the Company, the Trustee or the registrar for any registration
of transfer or exchange of Notes, but the Company may require a
holder to pay a sum sufficient to cover any transfer tax or
other governmental taxes and fees required by law or permitted
by the Indenture. The Company is not required to transfer or
exchange any Note selected for redemption. Also, the Company is
not required to transfer or exchange any Note for a period of
15 days before a selection of Notes to be redeemed.
The registered holder of a Note will be treated its owner for
all purposes.
Optional
redemption
On and after October 1, 2013, we may redeem all or, from
time to time, a part of the Notes upon not less than 30 nor more
than 60 days notice, at the following redemption
prices (expressed as a percentage of principal amount of the
Notes), plus accrued and unpaid interest on the Notes, if any,
to the applicable redemption date (subject to the right of
holders of record on the relevant record date to receive
interest due on the relevant interest payment date), if redeemed
during the twelve-month period beginning on October 1 of
the years indicated below:
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Year
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Percentage
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2013
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104.313%
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2014
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102.156%
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2015 and thereafter
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100.000%
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Prior to October 1, 2012, we may, at our option, on any one
or more occasions redeem up to 35% of the aggregate principal
amount of the Notes (including Additional Notes) issued under
the Indenture with the Net Cash Proceeds of one or more Equity
Offerings at a redemption price of 108.625% of the principal
amount thereof, plus accrued and unpaid interest, if any, to the
redemption date (subject to the right of holders of record on
the relevant record date to receive interest due on the relevant
interest payment date); provided that
(1) at least 65% of the original principal amount of the
Notes issued on the Issue Date remains outstanding after each
such redemption; and
(2) the redemption occurs within 180 days after the
closing of the related Equity Offering.
In addition, the Notes may be redeemed, in whole or in part, at
any time prior to October 1, 2013 at the option of the
Company upon not less than 30 nor more than 60 days
prior notice mailed by first-class mail to each holder of Notes
at its registered address, at a redemption price equal to 100%
of the principal amount of the Notes redeemed plus the
Applicable Premium as of, and accrued and unpaid interest to,
the applicable redemption date (subject to the right of holders
of record on the relevant record date to receive interest due on
the relevant interest payment date).
Applicable Premium means, with respect to any
Note on any applicable redemption date, the greater of:
(1) 1.0% of the principal amount of such Note; or
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(2) the excess, if any, of:
(a) the present value at such redemption date of
(i) the redemption price of such Note at October 1,
2013 (such redemption price being set forth in the table
appearing above under the caption Optional
redemption) plus (ii) all required interest payments
(excluding accrued and unpaid interest to such redemption date)
due on such Note through October 1, 2013 computed using a
discount rate equal to the Treasury Rate as of such redemption
date plus 50 basis points; over
(b) the principal amount of such Note.
Treasury Rate means, as of any redemption
date, the yield to maturity at the time of computation of United
States Treasury securities with a constant maturity (as compiled
and published in the most recent Federal Reserve Statistical
Release H.15 (519) which has become publicly available at
least two Business Days prior to the redemption date (or, if
such Statistical Release is no longer published, any publicly
available source of similar market data)) most nearly equal to
the period from the redemption date to October 1, 2013;
provided, however, that if the period from the
redemption date to October 1, 2013 is not equal to the
constant maturity of a United States Treasury security for
which a weekly average yield is given, the Treasury Rate shall
be obtained by linear interpolation (calculated to the nearest
one-twelfth of a year) from the weekly average yields of United
States Treasury securities for which such yields are given,
except that if the period from the redemption date to
October 1, 2013 is less than one year, the weekly average
yield on actually traded United States Treasury securities
adjusted to a constant maturity of one year shall be used. The
Company will (a) calculate the Treasury Rate as of the
second Business Day preceding the applicable redemption date and
(b) prior to such redemption date file with the Trustee an
Officers Certificate setting forth the Applicable Premium
and the Treasury Rate and showing the calculation of each in
reasonable detail.
Selection and
notice
If the Company is redeeming less than all of the outstanding
Notes, the Trustee will select the Notes for redemption in
compliance with the requirements of the principal national
securities exchange, if any, on which the Notes are listed or,
if the Notes are not listed, then on a pro rata basis, by lot or
by such other method as the Trustee in its sole discretion will
deem to be fair and appropriate, although no Note of $2,000 in
original principal amount or less will be redeemed in part. If
any Note is to be redeemed in part only, the notice of
redemption relating to such Note will state the portion of the
principal amount thereof to be redeemed. A new Note in principal
amount equal to the unredeemed portion thereof will be issued in
the name of the holder thereof upon cancellation of the
partially redeemed Note. On and after the redemption date,
interest will cease to accrue on Notes or the portion of them
called for redemption unless we default in the payment thereof.
Mandatory
redemption; Offers to purchase; Open market purchases
We are not required to make mandatory redemption payments or
sinking fund payments with respect to the Notes. However, under
certain circumstances, we may be required to offer to purchase
Notes as described under the captions Change of
control and Certain covenantsLimitation
on sales of assets and Subsidiary stock.
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We may acquire Notes by means other than a redemption or
required repurchase, whether by tender offer, open market
purchases, negotiated transactions or otherwise, in accordance
with applicable securities laws, so long as such acquisition
does not otherwise violate the terms of the Indenture. However,
other existing or future agreements of the Company may limit the
ability of the Company or its Subsidiaries to purchase Notes
prior to maturity.
Ranking
The Notes will be general unsecured obligations of the Company
that rank senior in right of payment to all existing and future
Indebtedness that is expressly subordinated in right of payment
to the Notes. The Notes will rank equally in right of payment
with all existing and future liabilities of the Company that are
not so subordinated and will be effectively subordinated to all
of our secured Indebtedness, including Indebtedness Incurred
under our Senior Secured Credit Facility, to the extent of the
value of the collateral securing such Indebtedness, and
liabilities of any of our future Subsidiaries that do not
guarantee the Notes. In the event of bankruptcy, liquidation,
reorganization or other winding up of the Company or its
Subsidiary Guarantors or upon a default in payment with respect
to, or the acceleration of, any Indebtedness under the Senior
Secured Credit Agreement or other secured Indebtedness, the
assets of the Company and its Subsidiary Guarantors that secure
secured Indebtedness will be available to pay obligations on the
Notes and the Subsidiary Guarantees only after all Indebtedness
under the Senior Secured Credit Agreement and other secured
Indebtedness has been repaid in full from such assets. In
addition, in the event of bankruptcy, liquidation,
reorganization or other winding up of a non-guarantor
Subsidiary, the assets of such Subsidiary will be available to
pay obligations on the Notes only after all obligations of such
Subsidiary have been repaid in full from such assets. We advise
you that there may not be sufficient assets remaining to pay
amounts due on any or all the Notes and the Subsidiary
Guarantees then outstanding.
As of June 30, 2009, on an as adjusted basis after giving
effect to this offering and the application of net proceeds from
this offering as more fully described in Use of
proceeds:
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we and our Subsidiary Guarantors would have had
$668.7 million (net of discount) of total Indebtedness
(excluding Hedging Obligations and intercompany
Indebtedness); and
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of the $668.7 million (net of discount) of such total
Indebtedness, $373.0 million would have constituted secured
Indebtedness under our Senior Secured Credit Agreement, and we
would have additional availability of $582.8 million (after
giving effect to the reduction in the borrowing base due to
issuance of the Notes) under our Senior Secured Credit Agreement
as to which the Notes would have been effectively subordinated
to the extent of the value of the collateral thereunder. For
further discussion, see Description of other
indebtednessSenior secured credit facility.
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Subsidiary
guarantees
The Subsidiary Guarantors will, jointly and severally, fully and
unconditionally guarantee on a senior unsecured basis our
obligations under the Notes and all obligations under the
Indenture. The obligations of Subsidiary Guarantors under the
Subsidiary Guarantees will rank equally in right of payment with
other Indebtedness of such Subsidiary Guarantor, except to the
extent such other Indebtedness is expressly subordinate to the
obligations arising under the Subsidiary Guarantee.
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As of June 30, 2009, on an as adjusted basis and after
giving effect to this offering and the application of net
proceeds from this offering, as more fully described under
Use of proceeds, the Subsidiary Guarantors would
have had $668.7 million (net of discount) of Indebtedness
(excluding intercompany Indebtedness), consisting of secured
guarantees of $373.0 million under the Senior Secured
Credit Agreement and unsecured guarantees of $295.7 million
(net of discount) under the Notes.
Although the Indenture will limit the amount of Indebtedness
that Restricted Subsidiaries may Incur, such Indebtedness may be
substantial and such limitation is subject to a number of
significant qualifications. Moreover, the Indenture does not
impose any limitation on the Incurrence by such Subsidiaries of
liabilities that are not considered Indebtedness under the
Indenture. See Certain covenantsLimitation on
Indebtedness and Preferred Stock.
The obligations of each Subsidiary Guarantor under its
Subsidiary Guarantee will be limited as necessary to prevent
that Subsidiary Guarantee from constituting a fraudulent
conveyance or fraudulent transfer under applicable law, although
no assurance can be given that a court would give the holder the
benefit of such provision. See Risk factorsRisks
related to the notesFederal bankruptcy and state
fraudulent conveyance laws and other limitations may preclude
the recovery of payments under the guarantees. If a
Subsidiary Guarantee were rendered voidable, it could be
subordinated by a court to all other indebtedness (including
guarantees and other contingent liabilities) of the applicable
Subsidiary Guarantor, and, depending on the amount of such
indebtedness, a Subsidiary Guarantors liability on its
Subsidiary Guarantee could be reduced to zero. If the
obligations of a Subsidiary Guarantor under its Subsidiary
Guarantee were avoided, holders of Notes would have to look to
the assets of any remaining Subsidiary Guarantors for payment.
There can be no assurance in that event that such assets would
suffice to pay the outstanding principal and interest on the
Notes.
In the event a Subsidiary Guarantor is sold or disposed of
(whether by merger, consolidation, the sale of its Capital Stock
or the sale of all or substantially all of its assets (other
than by lease)) and whether or not the Subsidiary Guarantor is
the surviving entity in such transaction to a Person which is
not the Company or a Restricted Subsidiary of the Company, such
Subsidiary Guarantor will be released from its obligations under
its Subsidiary Guarantee if the sale or other disposition does
not violate the covenants described under Certain
covenantsLimitation on sales of assets and Subsidiary
stock.
In addition, a Subsidiary Guarantor will be released from its
obligations under the Indenture and, its Subsidiary Guarantee,
upon the release or discharge of the Guarantee that resulted in
the creation of such Subsidiary Guarantee pursuant to
clause (b) of the covenant described under
Certain covenantsFuture subsidiary
guarantors, except a release or discharge by or as a
result of payment under such Guarantee; if the Company
designates such Subsidiary as an Unrestricted Subsidiary and
such designation complies with the other applicable provisions
of the Indenture or in connection with any covenant defeasance,
legal defeasance or satisfaction and discharge of the Notes as
provided below under the captions Defeasance
and Satisfaction and discharge.
As of the date hereof, all of the Companys Subsidiaries
will be Restricted Subsidiaries. Under certain circumstances,
the Company may designate Subsidiaries as Unrestricted
Subsidiaries. None of the Unrestricted Subsidiaries will be
subject to the restrictive covenants in the Indenture and none
will guarantee the Notes.
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Change of
control
If a Change of Control occurs, unless the Company has previously
or concurrently exercised its right to redeem all of the Notes
as described under Optional redemption, each holder
will have the right to require the Company to repurchase all or
any part (equal to $2,000 or an integral multiple of $1,000 in
excess of $2,000) of such holders Notes at a purchase
price in cash equal to 101% of the principal amount of the Notes
plus accrued and unpaid interest, if any, to the date of
purchase (subject to the right of holders of record on the
relevant record date to receive interest due on the relevant
interest payment date).
Within 30 days following any Change of Control, unless we
have previously or concurrently exercised our right to redeem
all of the Notes as described under Optional
redemption, we will mail a notice (the Change of
Control Offer) to each holder, with a copy to the Trustee,
stating:
(1) that a Change of Control has occurred and that such
holder has the right to require us to purchase such
holders Notes at a purchase price in cash equal to 101% of
the principal amount of such Notes plus accrued and unpaid
interest, if any, to the date of purchase (subject to the right
of holders of record on a record date to receive interest on the
relevant interest payment date) (the Change of Control
Payment);
(2) the repurchase date (which shall be no earlier than
30 days nor later than 60 days from the date such
notice is mailed) (the Change of Control Payment
Date);
(3) that any Note not properly tendered will remain
outstanding and continue to accrue interest;
(4) that unless we default in the payment of the Change of
Control Payment, all Notes accepted for payment pursuant to the
Change of Control Offer will cease to accrue interest on the
Change of Control Payment Date;
(5) that holders electing to have any Notes in certificated
form purchased pursuant to a Change of Control Offer will be
required to surrender such Notes, with the form entitled
Option of Holder to Elect Purchase on the reverse of
such Notes completed, to the paying agent specified in the
notice at the address specified in the notice prior to the close
of business on the third Business Day preceding the Change of
Control Payment Date;
(6) that holders will be entitled to withdraw their
tendered Notes and their election to require us to purchase such
Notes, provided that the paying agent receives, not later than
the close of business on the third Business Day preceding the
Change of Control Payment Date, a telegram, telex, facsimile
transmission or letter setting forth the name of the holder of
the Notes, the principal amount of Notes tendered for purchase,
and a statement that such holder is withdrawing its tendered
Notes and its election to have such Notes purchased;
(7) that if we are repurchasing a portion of the Note of
any holder, the Holder will be issued a new Note equal in
principal amount to the unpurchased portion of the Note
surrendered, provided that the unpurchased portion of the
Note must be equal to a minimum principal amount of $2,000 and
an integral multiple of $1,000 in excess of $2,000; and
(8) the procedures determined by us, consistent with the
Indenture, that a holder must follow in order to have its Notes
repurchased.
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On the Change of Control Payment Date, the Company will, to the
extent lawful:
(1) accept for payment all Notes or portions of Notes (in a
minimum principal amount of $2,000 and integral multiples of
$1,000 in excess of $2,000) properly tendered pursuant to the
Change of Control Offer and not properly withdrawn;
(2) deposit with the paying agent an amount equal to the
Change of Control Payment in respect of all Notes or portions of
Notes accepted for payment; and
(3) deliver or cause to be delivered to the Trustee the
Notes so accepted together with an Officers Certificate
stating the aggregate principal amount of Notes or portions of
Notes being purchased by the Company.
The paying agent will promptly mail or deliver to each holder of
Notes accepted for payment the Change of Control Payment for
such Notes, and the Trustee will promptly authenticate and mail
(or cause to be transferred by book entry) to each holder a new
Note equal in principal amount to any unpurchased portion of the
Notes surrendered, if any; provided that each such new
Note will be in a minimum principal amount of $2,000 or an
integral multiple of $1,000 in excess of $2,000.
If the Change of Control Payment Date is on or after an interest
record date and on or before the related interest payment date,
any accrued and unpaid interest, will be paid to the Person in
whose name a Note is registered at the close of business on such
record date, and no further interest will be payable to holders
who tender pursuant to the Change of Control Offer.
The Change of Control provisions described above will be
applicable whether or not any other provisions of the Indenture
are applicable. Except as described above with respect to a
Change of Control, the Indenture does not contain provisions
that permit the holders to require that the Company repurchase
or redeem the Notes in the event of a takeover, recapitalization
or similar transaction.
We will not be required to make a Change of Control Offer upon a
Change of Control if a third party makes the Change of Control
Offer in the manner, at the times and otherwise in compliance
with the requirements set forth in the Indenture applicable to a
Change of Control Offer made by us and purchases all Notes
validly tendered and not withdrawn under such Change of Control
Offer.
A Change of Control Offer may be made in advance of a Change of
Control, and conditioned upon the occurrence of a Change of
Control, if a definitive agreement is in place for the Change of
Control at the time of making the Change of Control Offer.
We will comply, to the extent applicable, with the requirements
of
Rule 14e-1
of the Exchange Act and any other securities laws or regulations
in connection with the repurchase of Notes as a result of a
Change of Control. To the extent that the provisions of any
securities laws or regulations conflict with provisions of this
covenant, we will comply with the applicable securities laws and
regulations and will not be deemed to have breached our
obligations under in the Indenture by virtue of our compliance
with such securities laws or regulations.
Our ability to repurchase Notes pursuant to a Change of Control
Offer may be limited by a number of factors. The occurrence of
certain of the events that constitute a Change of Control would
constitute a default under the Senior Secured Credit Agreement.
In addition, certain events that may constitute a change of
control under the Senior Secured Credit Agreement and cause a
default under that agreement will not constitute a Change of
Control under the
S-119
Indenture. Future Indebtedness of the Company and its
Subsidiaries may also contain prohibitions of certain events
that would constitute a Change of Control or require such
Indebtedness to be repurchased upon a Change of Control.
Moreover, the exercise by the holders of their right to require
the Company to repurchase the Notes could cause a default under
such Indebtedness, even if the Change of Control itself does
not, due to the financial effect of such repurchase on the
Company. Finally, the Companys ability to pay cash to the
holders upon a repurchase may be limited by the Companys
then existing financial resources. There can be no assurance
that sufficient funds will be available when necessary to make
any required repurchases.
Even if sufficient funds were otherwise available, our future
Indebtedness may prohibit the Companys prepayment or
repurchase of Notes before their scheduled maturity.
Consequently, if the Company is not able to prepay the
Indebtedness under the Senior Secured Credit Agreement and any
such other Indebtedness containing similar restrictions or
obtain requisite consents, the Company will be unable to fulfill
its repurchase obligations if holders of Notes exercise their
repurchase rights following a Change of Control, resulting in a
default under the Indenture. A default under the Indenture may
result in a cross-default under the Senior Secured Credit
Agreement.
If holders of not less than 90% in aggregate principal amount of
the outstanding Notes validly tender and do not withdraw such
Notes in a Change of Control Offer and the Company, or any third
party making a Change of Control Offer in lieu of the Company as
described above, purchases all of the Notes validly tendered and
not withdrawn by such holders, the Company will have the right,
upon not less than 30 nor more than 60 days prior
notice, given not more than 30 days following such purchase
pursuant to the Change of Control Offer described above, to
redeem all Notes that remain outstanding following such purchase
at a redemption price in cash equal to the applicable Change of
Control Payment plus, to the extent not included in the Change
of Control Payment, accrued and unpaid interest, if any, to the
date of redemption.
The Change of Control provisions described above may deter
certain mergers, tender offers and other takeover attempts
involving the Company. The Change of Control purchase feature is
a result of negotiations between the underwriters and us. As of
the Issue Date, we have no present intention to engage in a
transaction involving a Change of Control, although it is
possible that we could decide to do so in the future. Subject to
the limitations discussed below, we could, in the future, enter
into certain transactions, including acquisitions, refinancings
or other recapitalizations, that would not constitute a Change
of Control under the Indenture, but that could increase the
amount of indebtedness outstanding at such time or otherwise
affect our capital structure or credit ratings. Restrictions on
our ability to incur additional Indebtedness are contained in
the covenants described under Certain
covenantsLimitation on Indebtedness and Preferred
Stock and Certain covenantsLimitation on
Liens. Such restrictions in the Indenture can be waived
only with the consent of the holders of a majority in principal
amount of the Notes then outstanding. Except for the limitations
contained in such covenants, however, the Indenture will not
contain any covenants or provisions that may afford holders of
the Notes protection in the event of a highly leveraged
transaction.
The definition of Change of Control includes a
disposition of all or substantially all of the property and
assets of the Company and its Restricted Subsidiaries taken as a
whole to any Person. Although there is a limited body of case
law interpreting the phrase substantially all, there
is no precise established definition of the phrase under
applicable law. Accordingly, in certain circumstances there may
be a degree of uncertainty as to whether a particular
S-120
transaction would involve a disposition of all or
substantially all of the property or assets of a Person.
As a result, it may be unclear as to whether a Change of Control
has occurred and whether a holder of Notes may require the
Company to make an offer to repurchase the Notes as described
above. In a recent decision, the Chancery Court of Delaware
raised the possibility that a Change of Control occurring as a
result of a failure to have Continuing Directors comprising a
majority of the Board of Directors may be unenforceable on
public policy grounds.
The provisions under the Indenture relative to our obligation to
make an offer to repurchase the Notes as a result of a Change of
Control may be waived or modified or terminated with the written
consent of the holders of a majority in principal amount of the
Notes then outstanding (including consents obtained in
connection with a tender offer or exchange offer for the Notes)
prior to the occurrence of such Change of Control.
Certain
covenants
Limitation on
Indebtedness and Preferred Stock
The Company will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, Incur any Indebtedness
(including Acquired Indebtedness) and the Company will not
permit any of its Restricted Subsidiaries to issue Preferred
Stock; provided, however, that the Company may
Incur Indebtedness and any of the Subsidiary Guarantors may
Incur Indebtedness and issue Preferred Stock if on the date
thereof:
(1) the Consolidated Coverage Ratio for the Company and its
Restricted Subsidiaries is at least 2.25 to 1.00, determined on
a pro forma basis (including a pro forma application of
proceeds); and
(2) no Default would occur as a consequence of, and no
Event of Default would be continuing following, Incurring the
Indebtedness or its application.
The first paragraph of this covenant will not prohibit the
Incurrence of the following Indebtedness:
(1) Indebtedness under one or more Credit Facilities of
(a) the Company or any Subsidiary Guarantor Incurred
pursuant to this clause (1) in an aggregate amount not to
exceed the greater of (i) $1,000.0 million or
(ii) the sum of $500.0 million and 25.0% of the
Companys Adjusted Consolidated Net Tangible Assets
determined as of the date of the Incurrence of such Indebtedness
after giving effect to the application of the proceeds therefrom
and (b) any Foreign Subsidiary Incurred pursuant to this clause
(1) in an aggregate amount not to exceed
$50.0 million, in each case outstanding at any one time;
(2) Guarantees of Indebtedness Incurred in accordance with
the provisions of the Indenture; provided that in the
event such Indebtedness that is being Guaranteed is a
Subordinated Obligation or a Guarantor Subordinated Obligation,
then the related Guarantee shall be subordinated in right of
payment to the Notes or the Subsidiary Guarantee to at least the
same extent as the Indebtedness being Guaranteed, as the case
may be;
(3) Indebtedness of the Company owing to and held by any
Restricted Subsidiary or Indebtedness of a Restricted Subsidiary
owing to and held by the Company or any Restricted Subsidiary;
provided, however, that (a)(i) if the Company is
the obligor on such Indebtedness and the obligee is not a
Subsidiary Guarantor, such Indebtedness must be expressly
subordinated to the prior payment in full in cash of all
obligations with respect to the Notes and
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(ii) if a Subsidiary Guarantor is the obligor of such
Indebtedness and the obligee is neither the Company nor a
Subsidiary Guarantor, such Indebtedness must be expressly
subordinated to the prior payment in full in cash of all
obligations of such Subsidiary Guarantor with respect to its
Subsidiary Guarantee and (b)(i) any subsequent issuance or
transfer of Capital Stock or any other event which results in
any such Indebtedness being held by a Person other than the
Company or a Restricted Subsidiary of the Company and
(ii) any sale or other transfer of any such Indebtedness to
a Person other than the Company or a Restricted Subsidiary of
the Company shall be deemed, in each case, to constitute an
Incurrence of such Indebtedness by the Company or such
Subsidiary, as the case may be, that was not permitted by this
clause;
(4) Indebtedness represented by (a) the Notes issued
on the Issue Date and all Subsidiary Guarantees, (b) any
Indebtedness (other than the Indebtedness described in clauses
(1), (2) and 4(a)) outstanding on the Issue Date and
(c) any Refinancing Indebtedness Incurred in respect of any
Indebtedness described in this clause (4) or
clause (5) or Incurred pursuant to the first paragraph of
this covenant;
(5) Permitted Acquisition Indebtedness;
(6) Indebtedness Incurred in respect of
(a) self-insurance obligations, bid, appeal, reimbursement,
performance, surety and similar bonds and completion guarantees
provided by the Company or a Restricted Subsidiary in the
ordinary course of business and any Guarantees or letters of
credit functioning as or supporting any of the foregoing bonds
or obligations and (b) obligations represented by letters
of credit for the account of the Company or a Restricted
Subsidiary in order to provide security for workers
compensation claims (in the case of clauses (a) and
(b) other than for an obligation for money borrowed);
(7) Preferred Stock (other than Disqualified Stock) of any
Restricted Subsidiary; and
(8) in addition to the items referred to in
clauses (1) through (7) above, Indebtedness of the
Company and its Restricted Subsidiaries in an aggregate
outstanding principal amount which, when taken together with the
principal amount of all other Indebtedness Incurred pursuant to
this clause (8) and then outstanding, will not exceed the
greater of $70.0 million or 2.5% of the Companys
Adjusted Consolidated Net Tangible Assets, determined as of the
date of Incurrence of such Indebtedness after giving effect to
such Incurrence and the application of the proceeds therefrom.
For purposes of determining compliance with, and the outstanding
principal amount of any particular Indebtedness Incurred
pursuant to and in compliance with, this covenant:
(1) in the event an item of that Indebtedness meets the
criteria of more than one of the types of Indebtedness described
in the first and second paragraphs of this covenant, the
Company, in its sole discretion, will classify such item of
Indebtedness on the date of Incurrence and, subject to
clause (2) below may later classify, reclassify or redivide
all or a portion of such item of Indebtedness, in any manner
that complies with this covenant;
(2) all Indebtedness outstanding on the date of the
Indenture under the Senior Secured Credit Agreement shall be
deemed Incurred on the Issue Date under clause (1) of the
second paragraph of this covenant;
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(3) Guarantees of, or obligations in respect of letters of
credit supporting, Indebtedness which is otherwise included in
the determination of a particular amount of Indebtedness shall
not be included;
(4) if obligations in respect of letters of credit are
Incurred pursuant to a Credit Facility and are being treated as
Incurred pursuant to clause (1) of the second paragraph
above and the letters of credit relate to other Indebtedness,
then such other Indebtedness shall not be included;
(5) the principal amount of any Disqualified Stock of the
Company or a Restricted Subsidiary, or Preferred Stock of a
Restricted Subsidiary that is not a Subsidiary Guarantor, will
be equal to the greater of the maximum mandatory redemption or
repurchase price (not including, in either case, any redemption
or repurchase premium) or the liquidation preference thereof;
(6) Indebtedness permitted by this covenant need not be
permitted solely by reference to one provision permitting such
Indebtedness but may be permitted in part by one such provision
and in part by one or more other provisions of this covenant
permitting such Indebtedness; and
(7) the amount of Indebtedness issued at a price that is
less than the principal amount thereof will be equal to the
amount of the liability in respect thereof determined in
accordance with GAAP.
Accrual of interest, accrual of dividends, the amortization of
debt discount or the accretion of accreted value, the payment of
interest in the form of additional Indebtedness, the payment of
dividends in the form of additional shares of Preferred Stock or
Disqualified Stock and unrealized losses or charges in respect
of Hedging Obligations (including those resulting from the
application of Statement of Financial Accounting Standard
No. 133) will not be deemed to be an Incurrence of
Indebtedness for purposes of this covenant.
The Company will not permit any of its Unrestricted Subsidiaries
to Incur any Indebtedness, or issue any shares of Disqualified
Stock, other than Non-Recourse Debt. If at any time an
Unrestricted Subsidiary becomes a Restricted Subsidiary, any
Indebtedness of such Subsidiary shall be deemed to be Incurred
by a Restricted Subsidiary as of such date (and, if such
Indebtedness is not permitted to be Incurred as of such date
under this Limitation on Indebtedness and Preferred
Stock covenant, the Company shall be in Default of this
covenant).
For purposes of determining compliance with any
U.S. dollar-denominated restriction on the Incurrence of
Indebtedness, the U.S. dollar-equivalent principal amount
of Indebtedness denominated in a foreign currency shall be
calculated based on the relevant currency exchange rate in
effect on the date such Indebtedness was Incurred, in the case
of term Indebtedness, or first committed, in the case of
revolving credit Indebtedness; provided that if such
Indebtedness is Incurred to refinance other Indebtedness
denominated in a foreign currency, and such refinancing would
cause the applicable U.S. dollar-denominated restriction to
be exceeded if calculated at the relevant currency exchange rate
in effect on the date of such refinancing, such
U.S. dollar-denominated restriction shall be deemed not to
have been exceeded so long as the principal amount of such
refinancing Indebtedness does not exceed the principal amount of
such Indebtedness being refinanced. Notwithstanding any other
provision of this covenant, the maximum amount of Indebtedness
that the Company may Incur pursuant to this covenant shall not
be deemed to be exceeded solely as a result of fluctuations in
the exchange rates of
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currencies. The principal amount of any Indebtedness Incurred to
refinance other Indebtedness, if Incurred in a different
currency from the Indebtedness being refinanced, shall be
calculated based on the currency exchange rate applicable to the
currencies in which such Refinancing Indebtedness is denominated
that is in effect on the date of such refinancing.
The Indenture will not treat (1) unsecured Indebtedness as
subordinated or junior to secured Indebtedness merely because it
is unsecured or (2) senior Indebtedness as subordinated or
junior to any other senior Indebtedness merely because it has a
junior priority with respect to the same collateral.
Limitation on
Restricted Payments
The Company will not, and will not permit any of its Restricted
Subsidiaries, directly or indirectly, to:
(1) declare or pay any dividend or make any payment or
distribution on or in respect of the Companys Capital
Stock (including any payment or distribution in connection with
any merger or consolidation involving the Company or any of its
Restricted Subsidiaries) except:
(a) dividends or distributions by the Company payable
solely in Capital Stock of the Company (other than Disqualified
Stock but including options, warrants or other rights to
purchase such Capital Stock of the Company); and
(b) dividends or distributions payable to the Company or a
Restricted Subsidiary and if such Restricted Subsidiary is not a
Wholly-Owned Subsidiary, to minority stockholders (or owners of
an equivalent interest in the case of a Subsidiary that is an
entity other than a corporation) so long as the Company or a
Restricted Subsidiary receives at least its pro rata share of
such dividend or distribution;
(2) purchase, repurchase, redeem, defease or otherwise
acquire or retire for value any Capital Stock of the Company or
any direct or indirect parent of the Company held by Persons
other than the Company or a Restricted Subsidiary (other than in
exchange for Capital Stock of the Company (other than
Disqualified Stock));
(3) purchase, repurchase, redeem, defease or otherwise
acquire or retire for value, prior to scheduled maturity,
scheduled repayment or scheduled sinking fund payment, any
Subordinated Obligations or Guarantor Subordinated Obligations
(other than (x) Indebtedness permitted under
clause (3) of the second paragraph of the covenant
Limitation on Indebtedness and Preferred Stock
or (y) the purchase, repurchase, redemption, defeasance or
other acquisition or retirement of Subordinated Obligations or
Guarantor Subordinated Obligations purchased in anticipation of
satisfying a sinking fund obligation, principal installment or
final maturity, in each case due within one year of the date of
purchase, repurchase, redemption, defeasance or other
acquisition or retirement); or
(4) make any Restricted Investment in any Person;
(any such dividend, distribution, purchase, redemption,
repurchase, defeasance, other acquisition, retirement or
Restricted Investment referred to in clauses (1) through
(4) shall be referred to herein as a Restricted
Payment), if at the time the Company or such Restricted
Subsidiary makes such Restricted Payment:
(a) a Default shall have occurred and be continuing (or
would result therefrom);
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(b) the Company is not able to Incur an additional $1.00 of
Indebtedness pursuant to the covenant described under the first
paragraph under Limitation on Indebtedness and
Preferred Stock after giving effect, on a pro forma basis,
to such Restricted Payment; or
(c) the aggregate amount of such Restricted Payment and all
other Restricted Payments declared or made subsequent to the
Issue Date would exceed the sum of:
(i) 50% of Consolidated Net Income for the period (treated
as one accounting period) from July 1, 2009 to the end of
the most recent fiscal quarter ending prior to the date of such
Restricted Payment for which internal financial statements are
in existence (or, in case such Consolidated Net Income is a
deficit, minus 100% of such deficit);
(ii) 100% of the aggregate Net Cash Proceeds and the Fair
Market Value of property or securities other than cash
(including Capital Stock of Persons engaged primarily in the Oil
and Gas Business or assets used in the Oil and Gas Business), in
each case received by the Company from the issue or sale of its
Capital Stock (other than Disqualified Stock) or other capital
contributions subsequent to the Issue Date (other than Net Cash
Proceeds received from an issuance or sale of such Capital Stock
to (x) management, employees, directors or any direct or
indirect parent of the Company, to the extent such Net Cash
Proceeds have been used to make a Restricted Payment pursuant to
clause (5)(a) of the next succeeding paragraph, (y) a
Subsidiary of the Company or (z) an employee stock
ownership plan, option plan or similar trust (to the extent such
sale to an employee stock ownership plan, option plan or similar
trust is financed by loans from or Guaranteed by the Company or
any Restricted Subsidiary unless such loans have been repaid
with cash on or prior to the date of determination));
(iii) the amount by which Indebtedness of the Company or
its Restricted Subsidiaries is reduced on the Companys
balance sheet upon the conversion or exchange (other than by a
Subsidiary of the Company) subsequent to the Issue Date of any
Indebtedness of the Company or its Restricted Subsidiaries
convertible or exchangeable for Capital Stock (other than
Disqualified Stock) of the Company (less the amount of any cash,
or the Fair Market Value of any other property (other than such
Capital Stock), distributed by the Company upon such conversion
or exchange), together with the net proceeds, if any, received
by the Company or any of its Restricted Subsidiaries upon such
conversion or exchange; and
(iv) the amount equal to the aggregate net reduction in
Restricted Investments made by the Company or any of its
Restricted Subsidiaries in any Person after the Issue Date
resulting from:
(A) repurchases, repayments or redemptions of such
Restricted Investments by such Person, proceeds realized upon
the sale of such Restricted Investment (other than to a
Subsidiary of the Company), repayments of loans or advances or
other transfers of assets (including by way of dividend or
distribution) by such Person to the Company or any Restricted
Subsidiary;
(B) the redesignation of Unrestricted Subsidiaries as
Restricted Subsidiaries (valued in each case as provided in the
definition of Investment) not to exceed, in the case
of any Unrestricted Subsidiary, the amount of Investments
previously made by the Company or any Restricted Subsidiary in
such Unrestricted Subsidiary, which amount in each case under
this clause (iv) was included in the calculation of the
amount of
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Restricted Payments; provided, however, that no
amount will be included under this clause (iv) to the
extent it is already included in Consolidated Net
Income; and
(C) the sale by the Company or any Restricted Subsidiary
(other than to the Company or a Restricted Subsidiary) of all or
a portion of the Capital Stock of an Unrestricted Subsidiary or
a distribution from an Unrestricted Subsidiary or a dividend
from an Unrestricted Subsidiary (whether any such distribution
or dividend is made with proceeds from the issuance by such
Unrestricted Subsidiary of its Capital Stock or otherwise).
The provisions of the preceding paragraph will not prohibit:
(1) any Restricted Payment made by exchange for, or out of
the proceeds of the substantially concurrent sale of, Capital
Stock of the Company (other than Disqualified Stock and other
than Capital Stock issued or sold to a Subsidiary of the Company
or an employee stock ownership plan or similar trust to the
extent such sale to an employee stock ownership plan or similar
trust is financed by loans from or Guaranteed by the Company or
any Restricted Subsidiary unless such loans have been repaid
with cash on or prior to the date of determination) or a
substantially concurrent cash capital contribution received by
the Company from its shareholders; provided,
however, that (a) such Restricted Payment will be
excluded from subsequent calculations of the amount of
Restricted Payments and (b) the Net Cash Proceeds from such
sale of Capital Stock or capital contribution will be excluded
from clause (c)(ii) of the preceding paragraph;
(2) any purchase, repurchase, redemption, defeasance or
other acquisition or retirement of Subordinated Obligations of
the Company or Guarantor Subordinated Obligations of any
Subsidiary Guarantor made by exchange for, or out of the
proceeds of the substantially concurrent sale of, Subordinated
Obligations of the Company or any purchase, repurchase,
redemption, defeasance or other acquisition or retirement of
Guarantor Subordinated Obligations made by exchange for or out
of the proceeds of the substantially concurrent sale of
Guarantor Subordinated Obligations that, in each case, is
permitted to be Incurred pursuant to the covenant described
under Limitation on Indebtedness and Preferred
Stock; provided, however, that such
purchase, repurchase, redemption, defeasance, acquisition or
retirement will be excluded from subsequent calculations of the
amount of Restricted Payments;
(3) any purchase, repurchase, redemption, defeasance or
other acquisition or retirement of Disqualified Stock of the
Company or a Restricted Subsidiary made by exchange for, or out
of the proceeds of the substantially concurrent sale of,
Disqualified Stock of the Company or such Restricted Subsidiary,
as the case may be, that, in each case, is permitted to be
Incurred pursuant to the covenant described under
Limitation on Indebtedness and Preferred
Stock; provided, however, that such
purchase, repurchase, redemption, defeasance, acquisition or
retirement will be excluded from subsequent calculations of the
amount of Restricted Payments;
(4) dividends paid or distributions made within
60 days after the date of declaration if at such date of
declaration such dividend or distribution would have complied
with this covenant; provided, however, that such
dividends and distributions will be included in subsequent
calculations of the amount of Restricted Payments; and
provided further, however, that for purposes of
clarification, this clause (4) shall not include cash
payments in lieu of the issuance of fractional shares included
in clause (9) below;
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(5) so long as no Default has occurred and is continuing,
(a) the repurchase or other acquisition of Capital Stock
(including options, warrants, equity appreciation rights or
other rights to purchase or acquire Capital Stock) of the
Company held by any existing or former employees, management or
directors of the Company or any Restricted Subsidiary of the
Company or their assigns, estates or heirs, in each case
pursuant to the repurchase or other acquisition provisions under
employee stock option or stock purchase plans or agreements or
other agreements to compensate management, employees or
directors, in each case approved by the Companys Board of
Directors; provided that such repurchases or other
acquisitions pursuant to this subclause (a) during any
calendar year will not exceed $2.0 million in the aggregate
(with unused amounts in any calendar year being carried over to
succeeding calendar years); provided further, that such
amount in any calendar year may be increased by an amount not to
exceed (A) the cash proceeds received by the Company from
the sale of Capital Stock of the Company to members of
management or directors of the Company and its Restricted
Subsidiaries that occurs after the Issue Date (to the extent the
cash proceeds from the sale of such Capital Stock have not
otherwise been applied to the payment of Restricted Payments by
virtue of the clause (c) of the preceding paragraph), plus
(B) the cash proceeds of key man life insurance policies
received by the Company and its Restricted Subsidiaries after
the Issue Date, less (C) the amount of any Restricted
Payments made pursuant to clauses (A) and (B) of this
clause (5)(a); provided further, however, that the amount
of any such repurchase or other acquisition under this
subclause (a) will be excluded in subsequent calculations
of the amount of Restricted Payments and the proceeds received
from any such transaction will be excluded from clause (c)(ii)
of the preceding paragraph; and (b) loans or advances to
employees or directors of the Company or any Subsidiary of the
Company, in each case as permitted by Section 402 of the
Sarbanes-Oxley Act of 2002, the proceeds of which are used to
purchase Capital Stock of the Company, or to refinance loans or
advances made pursuant to this clause (5)(b), in an aggregate
principal amount not in excess of $2.0 million at any one
time outstanding; provided, however, that the
amount of such loans and advances will be included in subsequent
calculations of the amount of Restricted Payments;
(6) purchases, repurchases, redemptions or other
acquisitions or retirements for value of Capital Stock deemed to
occur upon the exercise of stock options, warrants, rights to
acquire Capital Stock or other convertible securities if such
Capital Stock represents a portion of the exercise or exchange
price thereof, and any purchases, repurchases, redemptions or
other acquisitions or retirements for value of Capital Stock
made in lieu of withholding taxes in connection with any
exercise or exchange of warrants, options or rights to acquire
Capital Stock; provided, however, that such
acquisitions or retirements will be excluded from subsequent
calculations of the amount of Restricted Payments;
(7) the purchase, repurchase, redemption, defeasance or
other acquisition or retirement for value of any Subordinated
Obligation (i) at a purchase price not greater than 101% of
the principal amount of such Subordinated Obligation in the
event of a Change of Control in accordance with provisions
similar to the covenant described under Change of
control or (ii) at a purchase price not greater than
100% of the principal amount thereof in accordance with
provisions similar to the covenant described under
Limitation on sales of assets and Subsidiary
stock; provided that, prior to or simultaneously
with such purchase, repurchase, redemption, defeasance or other
acquisition or retirement, the Company has made the Change of
Control Offer or Asset Disposition Offer, as applicable, as
provided in such covenant with respect to the Notes and has
completed the repurchase or redemption of all Notes validly
tendered for payment in connection with such Change of Control
Offer
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or Asset Disposition Offer; provided, however,
that such acquisitions or retirements will be included in
subsequent calculations of the amount of Restricted Payments;
(8) payments or distributions to dissenting stockholders
pursuant to applicable law or in connection with the settlement
or other satisfaction of legal claims made pursuant to or in
connection with a consolidation, merger or transfer of assets;
provided, however, that any payment pursuant to
this clause (8) shall be included in the calculation of the
amount of Restricted Payments;
(9) cash payments in lieu of the issuance of fractional
shares; provided, however, that any payment
pursuant to this clause (9) shall be excluded in the
calculation of the amount of Restricted Payments;
(10) the declaration and payment of scheduled or accrued
dividends to holders of any class of or series of Disqualified
Stock of the Company issued on or after the Issue Date in
accordance with the covenant captioned Limitation on
Indebtedness and Preferred Stock, to the extent such
dividends are included in Consolidated Interest Expense;
provided, however, that any payment pursuant to
this clause (10) shall be excluded in the calculation of
the amount of Restricted Payments; and
(11) Restricted Payments in an amount not to exceed
$30.0 million in the aggregate since the Issue Date;
provided, however, that the amount of such
Restricted Payments will be included in subsequent calculations
of the amount of Restricted Payments.
The amount of all Restricted Payments (other than cash) shall be
the Fair Market Value on the date of such Restricted Payment of
the asset(s) or securities proposed to be paid, transferred or
issued by the Company or such Restricted Subsidiary, as the case
may be, pursuant to such Restricted Payment. The Fair Market
Value of any cash Restricted Payment shall be its face amount
and the Fair Market Value of any non-cash Restricted Payment
shall be determined in accordance with the definition of that
term. Not later than the date of making any Restricted Payment
in excess of $15.0 million that will be included in
subsequent calculations of the amount of Restricted Payments,
the Company shall deliver to the Trustee an Officers
Certificate stating that such Restricted Payment is permitted
and setting forth the basis upon which the calculations required
by the this covenant were computed.
In the event that a Restricted Payment meets the criteria of
more than one of the exceptions described in (1) through
(11) above or is entitled to be made pursuant to the first
paragraph above, the Company shall, in its sole discretion,
classify such Restricted Payment.
As of the Issue Date, all of the Companys Subsidiaries
will be Restricted Subsidiaries. We will not permit any
Unrestricted Subsidiary to become a Restricted Subsidiary except
pursuant to the last sentence of the definition of
Unrestricted Subsidiary. For purpose of designating
any Restricted Subsidiary as an Unrestricted Subsidiary, all
outstanding Investments by the Company and its Restricted
Subsidiaries (except to the extent repaid) in the Subsidiary so
designated will be deemed to be Restricted Payments in an amount
determined as set forth in the last sentence of the definition
of Investment. Such designation will be permitted
only if a Restricted Payment in such amount would be permitted
at such time, whether pursuant to the first paragraph of this
covenant or under clause (11) of the second paragraph of
this covenant, or pursuant to the definition of Permitted
Investments, and if such Subsidiary otherwise meets the
definition of an Unrestricted Subsidiary. Unrestricted
Subsidiaries will not be subject to any of the restrictive
covenants set forth in the Indenture.
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Limitation on
Liens
The Company will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create, Incur or suffer
to exist any Lien (the Initial Lien) other than
Permitted Liens upon any of its property or assets (including
Capital Stock of Restricted Subsidiaries), including any income
or profits therefrom, whether owned on the date of the Indenture
or acquired after that date, which Lien is securing any
Indebtedness, unless contemporaneously with the Incurrence of
such Liens effective provision is made to secure the
Indebtedness due under the Notes or, in respect of Liens on any
Restricted Subsidiarys property or assets, any Subsidiary
Guarantee of such Restricted Subsidiary, equally and ratably
with (or senior in priority to in the case of Liens with respect
to Subordinated Obligations or Guarantor Subordinated
Obligations, as the case may be) the Indebtedness secured by
such Lien for so long as such Indebtedness is so secured.
Any Lien created for the benefit of the holders of the Notes
pursuant to the preceding paragraph shall provide by its terms
that such Lien shall be automatically and unconditionally
released and discharged upon the release and discharge of the
Initial Lien.
Limitation on
restrictions on distributions from Restricted
Subsidiaries
The Company will not, and will not permit any Restricted
Subsidiary to, create or otherwise cause or permit to exist or
become effective any consensual encumbrance or consensual
restriction on the ability of any Restricted Subsidiary to:
(1) pay dividends or make any other distributions on its
Capital Stock or pay any Indebtedness or other obligations owed
to the Company or any Restricted Subsidiary (it being understood
that the priority of any Preferred Stock in receiving dividends
or liquidating distributions prior to dividends or liquidating
distributions being paid on Common Stock shall not be deemed a
restriction on the ability to make distributions on Capital
Stock);
(2) make any loans or advances to the Company or any
Restricted Subsidiary (it being understood that the
subordination of loans or advances made to the Company or any
Restricted Subsidiary to other Indebtedness Incurred by the
Company or any Restricted Subsidiary shall not be deemed a
restriction on the ability to make loans or advances); or
(3) sell, lease or transfer any of its property or assets
to the Company or any Restricted Subsidiary.
The preceding provisions will not prohibit:
(i) any encumbrance or restriction pursuant to or by reason
of an agreement in effect at or entered into on the Issue Date,
including, without limitation, the Indenture as in effect on
such date;
(ii) any encumbrance or restriction with respect to a
Person pursuant to or by reason of an agreement relating to any
Capital Stock or Indebtedness Incurred by a Person on or before
the date on which such Person was acquired by the Company or
another Restricted Subsidiary (other than Capital Stock or
Indebtedness Incurred as consideration in, or to provide all or
any portion of the funds utilized to consummate, the transaction
or series of related transactions pursuant to which such Person
was acquired by the Company or a Restricted Subsidiary or in
contemplation of the transaction) and outstanding on such date;
provided that any such encumbrance or restriction shall
not extend to any assets or property
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of the Company or any other Restricted Subsidiary other than the
assets and property so acquired;
(iii) encumbrances and restrictions contained in contracts
entered into in the ordinary course of business, not relating to
any Indebtedness, and that do not, individually or in the
aggregate, detract from the value of, or from the ability of the
Company and the Restricted Subsidiaries to realize the value of,
property or assets of the Company or any Restricted Subsidiary
in any manner material to the Company or any Restricted
Subsidiary;
(iv) any encumbrance or restriction with respect to a
Unrestricted Subsidiary pursuant to or by reason of an agreement
that the Unrestricted Subsidiary is a party to entered into
before the date on which such Unrestricted Subsidiary became a
Restricted Subsidiary; provided that such agreement was not
entered into in anticipation of the Unrestricted Subsidiary
becoming a Restricted Subsidiary and any such encumbrance or
restriction shall not extend to any assets or property of the
Company or any other Restricted Subsidiary other than the assets
and property so acquired;
(v) with respect to any Foreign Subsidiary, any encumbrance
or restriction contained in the terms of any Indebtedness or any
agreement pursuant to which such Indebtedness was Incurred if
either (1) the encumbrance or restriction applies only in
the event of a payment default or a default with respect to a
financial covenant in such Indebtedness or agreement or
(2) the Company determines that any such encumbrance or
restriction will not materially affect the Companys
ability to make principal or interest payments on the Notes, as
determined in good faith by the Board of Directors of the
Company, whose determination shall be conclusive;
(vi) any encumbrance or restriction with respect to a
Restricted Subsidiary pursuant to an agreement effecting a
refunding, replacement or refinancing of Indebtedness Incurred
pursuant to an agreement referred to in clauses (i) through
(v) or clause (xii) of this paragraph or this
clause (vi) or contained in any amendment, restatement,
modification, renewal, supplemental, refunding, replacement or
refinancing of an agreement referred to in clauses (i)
through (v) or clause (xii) of this paragraph or this
clause (vi); provided that the encumbrances and
restrictions with respect to such Restricted Subsidiary
contained in any such agreement taken as a whole are no less
favorable in any material respect to the holders of the Notes
than the encumbrances and restrictions contained in the
agreements governing the Indebtedness being refunded, replaced
or refinanced;
(vii) in the case of clause (3) of the first paragraph
of this covenant, any encumbrance or restriction:
(a) that restricts in a customary manner the subletting,
assignment or transfer of any property or asset that is subject
to a lease (including leases governing leasehold interests or
farm-in agreements or farm-out agreements relating to leasehold
interests in Oil and Gas Properties), license or similar
contract, or the assignment or transfer of any such lease
(including leases governing leasehold interests or farm-in
agreements or farm-out agreements relating to leasehold
interests in Oil and Gas Properties), license (including,
without limitation, licenses of intellectual property) or other
contract;
(b) contained in mortgages, pledges or other security
agreements permitted under the Indenture securing Indebtedness
of the Company or a Restricted Subsidiary to the extent
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such encumbrances or restrictions restrict the transfer of the
property subject to such mortgages, pledges or other security
agreements;
(c) contained in any agreement creating Hedging Obligations
permitted from time to time under the Indenture;
(d) pursuant to customary provisions restricting
dispositions of real property interests set forth in any
reciprocal easement agreements of the Company or any Restricted
Subsidiary;
(e) restrictions on cash or other deposits imposed by
customers under contracts entered into in the ordinary course of
business; or
(f) provisions with respect to the disposition or
distribution of assets or property in operating agreements,
joint venture agreements, development agreements, area of mutual
interest agreements and other agreements that are customary in
the Oil and Gas Business and entered into in the ordinary course
of business;
(viii) any encumbrance or restriction contained in
(a) purchase money obligations for property acquired in the
ordinary course of business and (b) Capitalized Lease
Obligations permitted under the Indenture, in each case, that
impose encumbrances or restrictions of the nature described in
clause (3) of the first paragraph of this covenant on the
property so acquired;
(ix) any encumbrance or restriction with respect to a
Restricted Subsidiary (or any of its property or assets) imposed
pursuant to an agreement entered into for the direct or indirect
sale or disposition of all or a portion of the Capital Stock or
assets of such Restricted Subsidiary (or the property or assets
that are subject to such restriction) pending the closing of
such sale or disposition;
(x) any customary encumbrances or restrictions imposed
pursuant to any agreement of the type described in the
definition of Permitted Business Investment;
(xi) encumbrances or restrictions arising or existing by
reason of applicable law or any applicable rule, regulation or
order;
(xii) encumbrances or restrictions contained in agreements
governing Indebtedness of the Company or any of its Restricted
Subsidiaries permitted to be Incurred pursuant to an agreement
entered into subsequent to the Issue Date in accordance with the
covenant described under the caption Limitation on
Indebtedness and Preferred Stock; provided that the
provisions relating to such encumbrance or restriction contained
in such Indebtedness are not materially less favorable to the
Company taken as a whole, as determined by the Board of
Directors of the Company in good faith, than the provisions
contained in the Senior Secured Credit Agreement and in the
Indenture as in effect on the Issue Date;
(xiii) the issuance of Preferred Stock by a Restricted
Subsidiary or the payment of dividends thereon in accordance
with the terms thereof; provided that issuance of such
Preferred Stock is permitted pursuant to the covenant described
under the caption Limitation on Indebtedness and
Preferred Stock and the terms of such Preferred Stock do
not expressly restrict the ability of a Restricted Subsidiary to
pay dividends or make any other distributions on its Capital
Stock (other than requirements to pay dividends or liquidation
preferences on such Preferred Stock prior to paying any
dividends or making any other distributions on such other
Capital Stock);
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(xiv) supermajority voting requirements existing under
corporate charters, bylaws, stockholders agreements and similar
documents and agreements;
(xv) restrictions on cash or other deposits or net worth
imposed by customers under contracts entered into in the
ordinary course of business; and
(xvi) any encumbrance or restriction contained in the
Senior Secured Credit Agreement as in effect as of the Issue
Date, and in any amendments, modifications, restatements,
renewals, increases, supplements, refundings, replacements or
refinancings thereof; provided that such amendments,
modifications, restatements, renewals, increases, supplements,
refundings, replacements or refinancings are no more restrictive
with respect to such dividend and other payment restrictions
than those contained in the Senior Secured Credit Agreement as
in effect on the Issue Date.
Limitation on
sales of assets and Subsidiary stock
The Company will not, and will not permit any of its Restricted
Subsidiaries to, make any Asset Disposition unless:
(1) the Company or such Restricted Subsidiary, as the case
may be, receives consideration at the time of such Asset
Disposition at least equal to the Fair Market Value (such Fair
Market Value to be determined on the date of contractually
agreeing to such Asset Disposition) of the shares or other
assets subject to such Asset Disposition;
(2) at least 75% of the aggregate consideration received by
the Company or such Restricted Subsidiary, as the case may be,
from such Asset Disposition and all other Asset Dispositions
since the Issue Date, on a cumulative basis, is in the form of
cash or Cash Equivalents or Additional Assets, or any
combination thereof; and
(3) except as provided in the next paragraph, an amount
equal to 100% of the Net Available Cash from such Asset
Disposition is applied, within 365 days from the later of
the date of such Asset Disposition or the receipt of such Net
Available Cash, by the Company or such Restricted Subsidiary, as
the case may be:
(a) to prepay, repay, redeem or purchase Pari Passu
Indebtedness of the Company (including the Notes) or a
Subsidiary Guarantor or any Indebtedness (other than
Disqualified Stock) of a Restricted Subsidiary that is not a
Subsidiary Guarantor (in each case, excluding Indebtedness owed
to the Company or an Affiliate of the Company); provided,
however, that, in connection with any prepayment,
repayment, redemption or purchase of Indebtedness pursuant to
this clause (a), the Company or such Restricted Subsidiary will
retire such Indebtedness and will cause the related commitment
(if any) to be permanently reduced in an amount equal to the
principal amount so prepaid, repaid, redeemed or
purchased; or
(b) to invest in Additional Assets;
provided that pending the final application of any such
Net Available Cash in accordance with clause (a) or
clause (b) above, the Company and its Restricted
Subsidiaries may temporarily reduce Indebtedness or otherwise
invest such Net Available Cash in any manner not prohibited by
the Indenture.
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Any Net Available Cash from Asset Dispositions that is not
applied or invested as provided in the preceding paragraph will
be deemed to constitute Excess Proceeds. Not later
than the 366th day from the later of the date of such Asset
Disposition or the receipt of such Net Available Cash, if the
aggregate amount of Excess Proceeds exceeds $20.0 million,
the Company will be required to make an offer (Asset
Disposition Offer) to all holders of Notes and, to the
extent required by the terms of other Pari Passu Indebtedness,
to all holders of other Pari Passu Indebtedness outstanding with
similar provisions requiring the Company to make an offer to
purchase such Pari Passu Indebtedness with the proceeds from any
Asset Disposition (Pari Passu Notes) to
purchase the maximum principal amount of Notes and any such Pari
Passu Notes to which the Asset Disposition Offer applies that
may be purchased out of the Excess Proceeds, at an offer price
in cash in an amount equal to 100% of the principal amount (or,
in the event such Pari Passu Indebtedness of the Company was
issued with significant original issue discount, 100% of the
accreted value thereof) of the Notes and Pari Passu Notes plus
accrued and unpaid interest, if any (or in respect of such Pari
Passu Indebtedness, such lesser price, if any, as may be
provided for by the terms of such Indebtedness), to the date of
purchase (subject to the right of holders of record on the
relevant record date to receive interest due on the relevant
interest payment date), in accordance with the procedures set
forth in the Indenture or the agreements governing the Pari
Passu Notes, as applicable, in each case in minimum principal
amount of $2,000 and integral multiples of $1,000 in excess of
$2,000. If the aggregate principal amount of Notes surrendered
by holders thereof and other Pari Passu Notes surrendered by
holders or lenders, collectively, exceeds the amount of Excess
Proceeds, the Trustee shall select the Notes to be purchased on
a pro rata basis on the basis of the aggregate principal amount
of tendered Notes and Pari Passu Notes. To the extent that the
aggregate amount of Notes and Pari Passu Notes so validly
tendered and not properly withdrawn pursuant to an Asset
Disposition Offer is less than the Excess Proceeds, the Company
may use any remaining Excess Proceeds for general corporate
purposes, subject to the other covenants contained in the
Indenture. Upon completion of such Asset Disposition Offer, the
amount of Excess Proceeds shall be reset at zero.
The Asset Disposition Offer will remain open for a period of 20
Business Days following its commencement, except to the extent
that a longer period is required by applicable law (the
Asset Disposition Offer Period). No later
than five Business Days after the termination of the Asset
Disposition Offer Period (the Asset Disposition
Purchase Date), the Company will purchase the
principal amount of Notes and Pari Passu Notes required to be
purchased pursuant to this covenant (the Asset
Disposition Offer Amount) or, if less than the Asset
Disposition Offer Amount has been so validly tendered and not
properly withdrawn, all Notes and Pari Passu Notes validly
tendered and not properly withdrawn in response to the Asset
Disposition Offer.
If the Asset Disposition Purchase Date is on or after an
interest record date and on or before the related interest
payment date, any accrued and unpaid interest, if any, will be
paid to the Person in whose name a Note is registered at the
close of business on such record date, and no further interest
will be payable to holders who tender Notes pursuant to the
Asset Disposition Offer.
On or before the Asset Disposition Purchase Date, the Company
will, to the extent lawful, accept for payment, on a pro rata
basis to the extent necessary, the Asset Disposition Offer
Amount of Notes and Pari Passu Notes or portions of Notes and
Pari Passu Notes so validly tendered and not properly withdrawn
pursuant to the Asset Disposition Offer, or if less than the
Asset Disposition Offer Amount has been validly tendered and not
properly withdrawn, all Notes and Pari Passu Notes so validly
tendered and not properly withdrawn, in each case in
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minimum principal amount of $2,000 and integral multiples of
$1,000 in excess of $2,000. The Company will deliver to the
Trustee an Officers Certificate stating that such Notes or
portions thereof were accepted for payment by the Company in
accordance with the terms of this covenant and, in addition, the
Company will deliver all certificates and notes required, if
any, by the agreements governing the Pari Passu Notes. The
Company or the paying agent, as the case may be, will promptly
(but in any case not later than five Business Days after the
termination of the Asset Disposition Offer Period) mail or
deliver to each tendering holder of Notes or holder or lender of
Pari Passu Notes, as the case may be, an amount equal to the
purchase price of the Notes or Pari Passu Notes so validly
tendered and not properly withdrawn by such holder or lender, as
the case may be, and accepted by the Company for purchase, and
the Company will promptly issue a new Note, and the Trustee,
upon delivery of an Officers Certificate from the Company,
will authenticate and mail or deliver such new Note to such
holder, in a principal amount equal to any unpurchased portion
of the Note surrendered; provided that each such new Note
will be in a minimum principal amount of $2,000 or an integral
multiple of $1,000 in excess of $2,000. In addition, the Company
will take any and all other actions required by the agreements
governing the Pari Passu Notes. Any Note not so accepted will be
promptly mailed or delivered by the Company to the holder
thereof. The Company will publicly announce the results of the
Asset Disposition Offer on the Asset Disposition Purchase Date.
The Company will comply, to the extent applicable, with the
requirements of
Rule 14e-1
of the Exchange Act and any other securities laws or regulations
in connection with the repurchase of Notes pursuant to an Asset
Disposition Offer. To the extent that the provisions of any
securities laws or regulations conflict with provisions of this
covenant, the Company will comply with the applicable securities
laws and regulations and will not be deemed to have breached its
obligations under the Indenture by virtue of its compliance with
such securities laws or regulations.
For the purposes of clause (2) of the first paragraph of
this covenant, the following will be deemed to be cash:
(1) the assumption by the transferee of Indebtedness (other
than Subordinated Obligations or Disqualified Stock) of the
Company or Indebtedness of a Restricted Subsidiary (other than
Guarantor Subordinated Obligations or Disqualified Stock of any
Restricted Subsidiary that is a Subsidiary Guarantor) and the
release of the Company or such Restricted Subsidiary from all
liability on such Indebtedness in connection with such Asset
Disposition (in which case the Company will, without further
action, be deemed to have applied such deemed cash to
Indebtedness in accordance with clause (3)(a) of the first
paragraph of this covenant; and
(2) securities, notes or other obligations received by the
Company or any Restricted Subsidiary from the transferee that
are converted by the Company or such Restricted Subsidiary into
cash within 180 days after receipt thereof.
Notwithstanding the foregoing, the 75% limitation referred to in
clause (2) of the first paragraph of this covenant shall be
deemed satisfied with respect to any Asset Disposition in which
the cash or Cash Equivalents portion of the consideration
received therefrom, determined in accordance with the foregoing
provision on an after-tax basis, is equal to or greater than
what the after-tax proceeds would have been had such Asset
Disposition complied with the aforementioned 75% limitation.
The requirement of clause (3)(b) of the first paragraph of this
covenant above shall be deemed to be satisfied if an agreement
(including a lease, whether a capital lease or an operating
lease)
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committing to make the acquisitions or expenditures referred to
therein is entered into by the Company or its Restricted
Subsidiary within the specified time period and such Net
Available Cash is subsequently applied in accordance with such
agreement within six months following such agreement. The
Company will not, and will not permit any Restricted Subsidiary
to, engage in any Asset Swaps, unless:
(1) at the time of entering into such Asset Swap and
immediately after giving effect to such Asset Swap, no Default
or Event of Default shall have occurred and be continuing or
would occur as a consequence thereof; and
(2) in the event such Asset Swap involves the transfer by
the Company or any Restricted Subsidiary of assets having an
aggregate Fair Market Value in excess of $20.0 million, the
terms of such Asset Swap have been approved by a majority of the
members of the Board of Directors of the Company.
Limitation on
Affiliate Transactions
The Company will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, enter into, make, amend
or conduct any transaction (including making a payment to, the
purchase, sale, lease or exchange of any property or the
rendering of any service), contract, agreement or understanding
with or for the benefit of any Affiliate of the Company (an
Affiliate Transaction) unless:
(1) the terms of such Affiliate Transaction are not
materially less favorable to the Company or such Restricted
Subsidiary, as the case may be, than those that could reasonably
be expected to be obtained in a comparable transaction at the
time of such transaction in arms-length dealings with a
Person who is not such an Affiliate;
(2) if such Affiliate Transaction involves an aggregate
consideration in excess of $20.0 million, the terms of such
transaction have been approved by a majority of the members of
the Board of Directors of the Company having no personal stake
in such transaction, if any (and such majority determines that
such Affiliate Transaction satisfies the criteria in
clause (1) above); and
(3) if such Affiliate Transaction involves an aggregate
consideration in excess of $50.0 million, the Board of
Directors of the Company has received a written opinion from an
independent investment banking, accounting, engineering or
appraisal firm of nationally recognized standing that such
Affiliate Transaction is fair, from a financial standpoint, to
the Company or such Restricted Subsidiary or is not materially
less favorable than those that could reasonably be expected to
be obtained in a comparable transaction at such time on an
arms-length basis from a Person that is not an Affiliate.
The preceding paragraph will not apply to:
(1) any Restricted Payment permitted to be made pursuant to
the covenant described under Limitation on
Restricted Payments or any Permitted Investment;
(2) any issuance of Capital Stock (other than Disqualified
Stock), or other payments, awards or grants in cash, Capital
Stock (other than Disqualified Stock) or otherwise pursuant to,
or the funding of, employment or severance agreements and other
compensation arrangements, options to purchase Capital Stock
(other than Disqualified Stock) of the Company, restricted stock
plans, long-term incentive plans, stock appreciation rights
plans,
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participation plans or similar employee benefits plans
and/or
insurance and indemnification arrangements provided to or for
the benefit of directors and employees approved by the Board of
Directors of the Company;
(3) loans or advances to employees, officers or directors
in the ordinary course of business of the Company or any of its
Restricted Subsidiaries;
(4) advances to or reimbursements of employees for moving,
entertainment and travel expenses, drawing accounts and similar
expenditures in the ordinary course of business of the Company
or any of its Restricted Subsidiaries;
(5) any transaction between the Company and a Restricted
Subsidiary or between Restricted Subsidiaries, and Guarantees
issued by the Company or a Restricted Subsidiary for the benefit
of the Company or a Restricted Subsidiary, as the case may be,
in accordance with Limitation on Indebtedness and
Preferred Stock;
(6) any transaction with a joint venture or similar entity
which would constitute an Affiliate Transaction solely because
the Company or a Restricted Subsidiary owns, directly or
indirectly, an Equity Interest in or otherwise controls such
joint venture or similar entity;
(7) the issuance or sale of any Capital Stock (other than
Disqualified Stock) of the Company to, or the receipt by the
Company of any capital contribution from its shareholders;
(8) indemnities of officers, directors and employees of the
Company or any of its Restricted Subsidiaries permitted by bylaw
or statutory provisions and any employment agreement or other
employee compensation plan or arrangement entered into in the
ordinary course of business by the Company or any of its
Restricted Subsidiaries;
(9) the payment of reasonable compensation and fees paid
to, and indemnity provided on behalf of, officers or directors
of the Company or any Restricted Subsidiary;
(10) the performance of obligations of the Company or any
of its Restricted Subsidiaries under the terms of any agreement
to which the Company or any of its Restricted Subsidiaries is a
party as of or on the Issue Date, as these agreements may be
amended, modified, supplemented, extended or renewed from time
to time; provided, however, that any future
amendment, modification, supplement, extension or renewal
entered into after the Issue Date will be permitted only to the
extent that its terms are not materially more disadvantageous,
taken as a whole, to the holders of the Notes than the terms of
the agreements in effect on the Issue Date;
(11) transactions with customers, clients, suppliers, or
purchasers or sellers of goods or services, in each case in the
ordinary course of business and otherwise in compliance with the
terms of the Indenture, provided that in the reasonable
determination of the Board of Directors of the Company or the
senior management of the Company, such transactions are on terms
not materially less favorable to the Company or the relevant
Restricted Subsidiary than those that could reasonably be
expected to be obtained in a comparable transaction at such time
on an arms-length basis from a Person that is not an
Affiliate of the Company;
(12) transactions with a Person (other than an Unrestricted
Subsidiary) that is an Affiliate of the Company solely because
the Company owns, directly or through a Restricted Subsidiary,
an Equity Interest in such Person; and
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(13) transactions between the Company or any Restricted
Subsidiary and any Person, a director of which is also a
director of the Company or any direct or indirect parent company
of the Company, and such director is the sole cause for such
Person to be deemed an Affiliate of the Company or any
Restricted Subsidiary; provided, however, that
such director shall abstain from voting as a director of the
Company or such direct or indirect parent company, as the case
may be, on any matter involving such other Person.
Provision of
financial information
The Indenture will provide that, whether or not the Company is
subject to the reporting requirements of Section 13 or
Section 15(d) of the Exchange Act, to the extent not
prohibited by the Exchange Act, the Company will file with the
SEC, and make available to the Trustee and the holders of the
Notes without cost to any holder, the annual reports and the
information, documents and other reports (or copies of such
portions of any of the foregoing as the SEC may by rules and
regulations prescribe) that are specified in Sections 13
and 15(d) of the Exchange Act and applicable to a
U.S. corporation within the time periods specified therein
with respect to an accelerated filer. In the event that the
Company is not permitted to file such reports, documents and
information with the SEC pursuant to the Exchange Act, the
Company will nevertheless make available such Exchange Act
information to the Trustee and the holders of the Notes without
cost to any holder as if the Company were subject to the
reporting requirements of Section 13 or 15(d) of the
Exchange Act within the time periods specified therein with
respect to a non-accelerated filer.
If the Company has designated any of its Subsidiaries as
Unrestricted Subsidiaries, then the financial information
required will include a reasonably detailed presentation, either
on the face of the financial statements or in the footnotes
thereto, and in Managements Discussion and Analysis of
Financial Condition and Results of Operations, of the financial
condition and results of operations of the Company and its
Restricted Subsidiaries separate from the financial condition
and results of operations of the Unrestricted Subsidiaries of
the Company.
The availability of the foregoing materials on the SECs
website or on the Companys website shall be deemed to
satisfy the foregoing delivery obligations.
Merger and
consolidation
The Company will not consolidate with or merge with or into or
wind up into (whether or not the Company is the surviving
corporation), or convey, transfer or lease all or substantially
all its assets in one or more related transactions to, any
Person, unless:
(1) the resulting, surviving or transferee Person (the
Successor Company) will be a corporation,
partnership, trust or limited liability company organized and
existing under the laws of the United States of America, any
State of the United States or the District of Columbia and the
Successor Company (if not the Company) will expressly assume, by
supplemental indenture, executed and delivered to the Trustee,
in form reasonably satisfactory to the Trustee, all the
obligations of the Company under the Notes and the Indenture;
(2) immediately after giving effect to such transaction
(and treating any Indebtedness that becomes an obligation of the
Successor Company or any Subsidiary of the Successor Company as
a result of such transaction as having been Incurred by the
Successor Company or such Subsidiary at the time of such
transaction), no Default or Event of Default shall have occurred
and be continuing;
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(3) either (A) immediately after giving effect to such
transaction, the Successor Company would be able to Incur at
least an additional $1.00 of Indebtedness pursuant to the first
paragraph of the covenant described under Limitation
on Indebtedness and Preferred Stock or
(B) immediately after giving effect to such transaction on
a pro forma basis and any related financing transactions as if
the same had occurred at the beginning of the applicable four
quarter period, the Consolidated Coverage Ratio of the Company
is equal to or greater than the Consolidated Coverage Ratio of
the Company immediately before such transaction;
(4) if the Company is not the Successor Company, each
Subsidiary Guarantor (unless it is the other party to the
transactions above, in which case clause (1) shall apply)
shall have by supplemental indenture confirmed that its
Subsidiary Guarantee shall apply to such Persons
obligations in respect of the Indenture and the Notes shall
continue to be in effect; and
(5) the Company shall have delivered to the Trustee an
Officers Certificate and an Opinion of Counsel, each
stating that such consolidation, merger, conveyance, transfer or
lease and such supplemental indenture (if any) comply with the
Indenture.
For purposes of this covenant, the sale, lease, conveyance,
assignment, transfer or other disposition of all or
substantially all of the properties and assets of one or more
Subsidiaries of the Company, which properties and assets, if
held by the Company instead of such Subsidiaries, would
constitute all or substantially all of the properties and assets
of the Company on a consolidated basis, shall be deemed to be
the transfer of all or substantially all of the assets of the
Company.
The Successor Company will succeed to, and be substituted for,
and may exercise every right and power of, the Company under the
Indenture; and its predecessor Company, except in the case of a
lease of all or substantially all its assets, will be released
from the obligation to pay the principal of and interest on the
Notes.
Although there is a limited body of case law interpreting the
phrase substantially all, there is no precise
established definition of the phrase under applicable law.
Accordingly, in certain circumstances there may be a degree of
uncertainty as to whether a particular transaction would involve
all or substantially all of the assets of a Person.
Notwithstanding the preceding clause (3), (x) any
Restricted Subsidiary may consolidate with, merge into or
transfer all or part of its properties and assets to the Company
and the Company may consolidate with, merge into or transfer all
or part of its properties and assets to a Subsidiary Guarantor
and (y) the Company may merge with an Affiliate
incorporated solely for the purpose of reincorporating the
Company in another jurisdiction; and provided further
that, in the case of a Restricted Subsidiary that consolidates
with, merges into or transfers all or part of its properties and
assets to the Company, the Company will not be required to
comply with the preceding clause (5).
In addition, the Company will not permit any Subsidiary
Guarantor to consolidate with or merge with or into, and will
not permit the conveyance, transfer or lease of all or
substantially all of the assets of any Subsidiary Guarantor to,
any Person (other than the Company or another Subsidiary
Guarantor) unless:
(1) (a) the resulting, surviving or transferee Person
will be a corporation, partnership, trust or limited liability
company organized and existing under the laws of the United
States of America, any State of the United States or the
District of Columbia and such Person (if not
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such Subsidiary Guarantor) will expressly assume, by
supplemental indenture, executed and delivered to the Trustee,
all the obligations of such Subsidiary Guarantor under its
Subsidiary Guarantee; (b) immediately after giving effect
to such transaction (and treating any Indebtedness that becomes
an obligation of the resulting, surviving or transferee Person
or any Restricted Subsidiary as a result of such transaction as
having been Incurred by such Person or such Restricted
Subsidiary at the time of such transaction), no Default shall
have occurred and be continuing; and (c) the Company will
have delivered to the Trustee an Officers Certificate and
an Opinion of Counsel, each stating that such consolidation,
merger or transfer and such supplemental indenture (if any)
comply with the Indenture; and
(2) the transaction is made in compliance with the
covenants described under Subsidiary
guarantees, Certain covenantsLimitation
on sales of assets and Subsidiary stock and this
Merger and consolidation covenant.
Future subsidiary
guarantors
The Company will cause (a) each Wholly-Owned Subsidiary of
the Company (other than a Foreign Subsidiary) formed or acquired
after the Issue Date and (b) any other Domestic Subsidiary
that is not already a Subsidiary Guarantor that Guarantees any
Indebtedness of the Company or a Subsidiary Guarantor, in each
case to execute and deliver to the Trustee within 30 days a
supplemental indenture (in the form specified in the Indenture)
pursuant to which such Subsidiary will unconditionally
Guarantee, on a joint and several basis, the full and prompt
payment of the principal of, premium, if any, and interest on
the Notes on a senior basis; provided that any Restricted
Subsidiary that constitutes an Immaterial Subsidiary need not
become a Subsidiary Guarantor until such time as it ceases to be
an Immaterial Subsidiary.
Payments for
consent
Neither the Company nor any of its Restricted Subsidiaries will,
directly or indirectly, pay or cause to be paid any
consideration, whether by way of interest, fees or otherwise, to
any holder of any Notes for or as an inducement to any consent,
waiver or amendment of any of the terms or provisions of the
Indenture or the Notes unless such consideration is offered to
be paid or is paid to all holders of the Notes that consent,
waive or agree to amend in the time frame set forth in the
solicitation documents relating to such consent, waiver or
amendment.
Covenant
termination
From and after the occurrence of an Investment Grade Rating
Event, the Company and its Restricted Subsidiaries will no
longer be subject to the provisions of the Indenture described
above under the following headings:
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Limitation on Indebtedness and Preferred Stock,
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Limitation on Restricted Payments,
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Limitation on restrictions on distributions from
Restricted Subsidiaries,
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Limitation on sales of assets and Subsidiary
stock,
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Limitation on Affiliate Transactions and
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Clause (3) of Merger and consolidation
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(collectively, the Eliminated Covenants). As a
result, after the date on which the Company and its Restricted
Subsidiaries are no longer subject to the Eliminated Covenants,
the Notes will be entitled to substantially reduced covenant
protection.
After the foregoing covenants have been terminated, the Company
may not designate any of its Subsidiaries as Unrestricted
Subsidiaries pursuant to the second sentence of the definition
of Unrestricted Subsidiary.
Events of
default
Each of the following is an Event of Default with respect to the
Notes:
(1) default in any payment of interest on any Note when
due, continued for 30 days;
(2) default in the payment of principal of or premium, if
any, on any Note when due at its Stated Maturity, upon optional
redemption, upon required repurchase, upon declaration of
acceleration or otherwise;
(3) failure by the Company or any Subsidiary Guarantor to
comply with its obligations under Certain
covenantsMerger and consolidation;
(4) failure by the Company to comply for 30 days (or
180 days in the case of a Reporting Failure) after notice
as provided below with any of its obligations under the covenant
described under Change of control above or
under the covenants described under Certain
covenants above (in each case, other than a failure to
purchase Notes which will constitute an Event of Default under
clause (2) above and other than a failure to comply with
Certain covenantsMerger and
consolidation which is covered by clause (3));
(5) failure by the Company to comply for 60 days after
notice as provided below with its other agreements contained in
the Indenture;
(6) default under any mortgage, indenture or instrument
under which there may be issued or by which there may be secured
or evidenced any Indebtedness for money borrowed by the Company
or any of its Restricted Subsidiaries (or the payment of which
is Guaranteed by the Company or any of its Restricted
Subsidiaries), other than Indebtedness owed to the Company or a
Restricted Subsidiary, whether such Indebtedness or Guarantee
now exists, or is created after the date of the Indenture, which
default:
(a) is caused by a failure to pay principal of, or interest
or premium, if any, on such Indebtedness prior to the expiration
of the grace period provided in such Indebtedness (and any
extensions of any grace period) (payment
default); or
(b) results in the acceleration of such Indebtedness prior
to its Stated Maturity (the cross acceleration
provision);
and, in each case, the principal amount of any such
Indebtedness, together with the principal amount of any other
such Indebtedness under which there has been a payment default
or the maturity of which has been so accelerated, aggregates
$30.0 million or more;
(7) certain events of bankruptcy, insolvency or
reorganization of the Company or a Significant Subsidiary or
group of Restricted Subsidiaries that, taken together (as of the
latest audited consolidated financial statements for the Company
and its Restricted Subsidiaries), would constitute a Significant
Subsidiary (the bankruptcy provisions);
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(8) failure by the Company or any Significant Subsidiary or
group of Restricted Subsidiaries that, taken together (as of the
latest audited consolidated financial statements for the Company
and its Restricted Subsidiaries), would constitute a Significant
Subsidiary to pay final judgments aggregating in excess of
$30.0 million (to the extent not covered by insurance by a
reputable and creditworthy insurer as to which the insurer has
not disclaimed coverage), which judgments are not paid or
discharged, and there shall be any period of 60 consecutive days
following entry of such final judgment or decree during which a
stay of enforcement of such final judgment or decree, by reason
of pending appeal or otherwise, shall not be in effect (the
judgment default provision); or
(9) any Subsidiary Guarantee of a Significant Subsidiary or
group of Restricted Subsidiaries that, taken together (as of the
latest audited consolidated financial statements for the Company
and its Restricted Subsidiaries) would constitute a Significant
Subsidiary, ceases to be in full force and effect (except as
contemplated by the terms of the Indenture) or is declared null
and void in a judicial proceeding or any Subsidiary Guarantor
that is a Significant Subsidiary or group of Subsidiary
Guarantors that, taken together (as of the latest audited
consolidated financial statements of the Company and its
Restricted Subsidiaries) would constitute a Significant
Subsidiary, denies or disaffirms its obligations under the
Indenture or its Subsidiary Guarantee.
However, a default under clauses (4) and (5) of this
paragraph will not constitute an Event of Default until the
Trustee or the holders of at least 25% in principal amount of
the outstanding Notes notify the Company in writing and, in the
case of a notice given by the holders, the Trustee of the
default and the Company does not cure such default within the
time specified in clauses (4) and (5) of this
paragraph after receipt of such notice.
If an Event of Default (other than an Event of Default described
in clause (7) above) occurs and is continuing, the Trustee
by notice to the Company, or the holders of at least 25% in
principal amount of the outstanding Notes by notice to the
Company and the Trustee, may, and the Trustee at the request of
such holders shall, declare the principal of, premium, if any,
accrued and unpaid interest, if any, on all the Notes to be due
and payable. If an Event of Default described in clause (7)
above occurs and is continuing, the principal of, premium, if
any, accrued and unpaid interest, if any, on all the Notes will
become and be immediately due and payable without any
declaration or other act on the part of the Trustee or any
holders. The holders of a majority in principal amount of the
outstanding Notes may rescind any such acceleration with respect
to the Notes and its consequences if, among other requirements,
(1) rescission would not conflict with any judgment or
decree of a court of competent jurisdiction and (2) all
existing Events of Default, other than the nonpayment of the
principal of, premium, if any, and interest on the Notes that
have become due solely by such declaration of acceleration, have
been cured or waived.
Notwithstanding the foregoing, if an Event of Default specified
in clause (6) above shall have occurred and be continuing,
such Event of Default and any consequential acceleration (to the
extent not in violation of any applicable law or in conflict
with any judgment or decree of a court of competent
jurisdiction) shall be automatically rescinded if (i) the
Indebtedness that is the subject of such Event of Default has
been repaid or (ii) if the default relating to such
Indebtedness is waived by the holders of such Indebtedness or
cured and if such Indebtedness has been accelerated, then the
holders thereof have rescinded their declaration of acceleration
in respect of such Indebtedness, in each case within
20 days after the declaration of acceleration with respect
thereto, and (iii) any other existing Events of Default,
except nonpayment of
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principal, premium or interest on the Notes that became due
solely because of the acceleration of the Notes, have been cured
or waived.
Subject to the provisions of the Indenture relating to the
duties of the Trustee, if an Event of Default occurs and is
continuing, the Trustee will be under no obligation to exercise
any of the rights or powers under the Indenture at the request
or direction of any of the holders unless such holders have
offered to the Trustee reasonable indemnity or security against
any loss, liability or expense. Except to enforce the right to
receive payment of principal, premium, if any, or interest when
due, no holder may pursue any remedy with respect to the
Indenture or the Notes unless:
(1) such holder has previously given the Trustee notice
that an Event of Default is continuing;
(2) holders of at least 25% in principal amount of the
outstanding Notes have requested the Trustee to pursue the
remedy;
(3) such holders have offered the Trustee reasonable
security or indemnity against any loss, liability or expense;
(4) the Trustee has not complied with such request within
60 days after the receipt of the request and the offer of
security or indemnity; and
(5) the holders of a majority in principal amount of the
outstanding Notes have not waived such Event of Default or
otherwise given the Trustee a direction that, in the opinion of
the Trustee, is inconsistent with such request within such
60-day
period.
Subject to certain restrictions, the holders of a majority in
principal amount of the outstanding Notes are given the right to
direct the time, method and place of conducting any proceeding
for any remedy available to the Trustee or of exercising any
trust or power conferred on the Trustee. The Indenture provides
that in the event an Event of Default has occurred and is
continuing, the Trustee will be required in the exercise of its
powers to use the degree of care that a prudent person would use
in the conduct of his own affairs. The Trustee, however, may
refuse to follow any direction that conflicts with law or the
Indenture or that the Trustee determines is unduly prejudicial
to the rights of any other holder or that would involve the
Trustee in personal liability. Prior to taking any action under
the Indenture, the Trustee will be entitled to indemnification
satisfactory to it in its sole discretion against all losses and
expenses caused by taking or not taking such action.
If a Default occurs and is continuing and is known to the
Trustee, the Trustee must mail to each holder notice of the
Default within 90 days after it occurs. Except in the case
of a Default in the payment of principal of, premium, if any, or
interest on any Note, the Trustee may withhold such notice if
and so long as a committee of trust officers of the Trustee in
good faith determines that withholding notice is in the
interests of the holders. In addition, the Company is required
to deliver to the Trustee, within 120 days after the end of
each fiscal year, a certificate indicating whether the signers
thereof know of any Default that occurred during the previous
year. The Company also is required to deliver to the Trustee,
within 30 days after the occurrence thereof, written notice
of any Defaults, their status and what action the Company is
taking or proposing to take in respect thereof.
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Amendments and
waivers
Subject to certain exceptions, the Indenture and the Notes may
be amended with the consent of the holders of a majority in
principal amount of the Notes then outstanding (including
without limitation, consents obtained in connection with a
purchase of, or tender offer or exchange offer for, Notes) and,
subject to certain exceptions, any past default or compliance
with any provisions may be waived with the consent of the
holders of a majority in principal amount of the Notes then
outstanding (including, without limitation, consents obtained in
connection with a purchase of, or tender offer or exchange offer
for, Notes). However, without the consent of each holder of an
outstanding Note affected, no amendment may, among other things:
(1) reduce the principal amount of Notes whose holders must
consent to an amendment or waiver;
(2) reduce the stated rate of or extend the stated time for
payment of interest on any Note;
(3) reduce the principal of or extend the Stated Maturity
of any Note;
(4) reduce the premium payable upon the redemption of any
Note as described above under Optional
redemption, or change the time at which any Note may be
redeemed as described above under Optional
redemption;
(5) make any Note payable in money other than that stated
in the Note;
(6) impair the right of any holder to receive payment of
the principal of, premium, if any, and interest on such
holders Notes on or after the due dates therefor or to
institute suit for the enforcement of any payment on or with
respect to such holders Notes;
(7) make any change in the amendment provisions which
require each holders consent or in the waiver provisions;
(8) modify the Subsidiary Guarantees in any manner adverse
to the holders of the Notes; or
(9) make any change to or modify the ranking of the Notes
that would adversely affect the holders.
Notwithstanding the foregoing, without the consent of any
holder, the Company, the Subsidiary Guarantors and the Trustee
may amend the Indenture and the Notes to:
(1) cure any ambiguity, omission, defect, mistake or
inconsistency;
(2) provide for the assumption by a successor of the
obligations of the Company or any Subsidiary Guarantor under the
Indenture;
(3) provide for uncertificated Notes in addition to or in
place of certificated Notes (provided that the
uncertificated Notes are issued in registered form for purposes
of Section 163(f) of the Code, or in a manner such that the
uncertificated Notes are described in Section 163(f)(2)(B)
of the Code);
(4) add Guarantors with respect to the Notes, including
Subsidiary Guarantors, or release a Subsidiary Guarantor from
its Subsidiary Guarantee and terminate such Subsidiary
Guarantee; provided that the release and termination is
in accordance with the applicable provisions of the Indenture;
(5) secure the Notes or Subsidiary Guarantees;
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(6) add to the covenants of the Company or a Subsidiary
Guarantor for the benefit of the holders or surrender any right
or power conferred upon the Company or a Subsidiary Guarantor;
(7) make any change that does not adversely affect the
rights of any holder; provided, however, that any change
to conform the Indenture to this Description of
notes will not be deemed to adversely affect such legal
rights;
(8) comply with any requirement of the SEC in connection
with the qualification of the Indenture under the
Trust Indenture Act; or
(9) provide for the succession of a successor Trustee,
provided that the successor Trustee is otherwise
qualified and eligible to act as such under the Indenture.
The consent of the holders is not necessary under the Indenture
to approve the particular form of any proposed amendment. It is
sufficient if such consent approves the substance of the
proposed amendment. A consent to any amendment or waiver under
the Indenture by any holder of Notes given in connection with a
tender of such holders Notes will not be rendered invalid
by such tender. After an amendment under the Indenture requiring
the consent of the holders becomes effective, the Company is
required to mail to the holders a notice briefly describing such
amendment. However, the failure to give such notice to all the
holders, or any defect in the notice will not impair or affect
the validity of the amendment.
Defeasance
The Company at any time may terminate all its obligations under
the Notes and the Indenture (legal defeasance),
except for certain obligations, including those respecting the
defeasance trust and obligations to register the transfer or
exchange of the Notes, to replace mutilated, destroyed, lost or
stolen Notes and to maintain a registrar and paying agent in
respect of the Notes.
The Company at any time may terminate its obligations described
under Change of Control and under covenants
described under Certain covenants (other than
clauses (1), (2), (4) and (5) of Merger
and consolidation), the operation of the cross default
upon a payment default, cross acceleration provisions, the
bankruptcy provisions with respect to Significant Subsidiaries,
the judgment default provision, the Subsidiary Guarantee
provision described under Events of default
above and the limitations contained in clause (3) under
Certain covenantsMerger and
consolidation above (covenant defeasance).
If the Company exercises its legal defeasance or its covenant
defeasance option, the Subsidiary Guarantees in effect at such
time will terminate.
The Company may exercise its legal defeasance option
notwithstanding its prior exercise of its covenant defeasance
option. If the Company exercises its legal defeasance option,
payment of the Notes may not be accelerated because of an Event
of Default with respect to the Notes. If the Company exercises
its covenant defeasance option, payment of the Notes may not be
accelerated because of an Event of Default specified in clause
(4), (5), (6), (7) (with respect only to Significant
Subsidiaries), (8) or (9) under Events of
default above or because of the failure of the Company to
comply with clause (3) under Certain
covenantsMerger and consolidation above.
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In order to exercise either defeasance option, the Company must,
among other things, irrevocably deposit in trust (the
defeasance trust) with the Trustee money or
U.S. Government Obligations for the payment of principal,
premium, if any, and interest on the Notes to redemption or
Stated Maturity, as the case may be, and must comply with
certain other conditions, including delivery to the Trustee of
an Opinion of Counsel (subject to customary exceptions and
exclusions) to the effect that holders of the Notes will not
recognize income, gain or loss for federal income tax purposes
as a result of such deposit and defeasance and will be subject
to Federal income tax on the same amount and in the same manner
and at the same times as would have been the case if such
deposit and defeasance had not occurred. In the case of legal
defeasance only, such Opinion of Counsel must be based on a
ruling of the Internal Revenue Service or other change in
applicable federal income tax law.
Satisfaction and
discharge
The Indenture will be discharged and will cease to be of further
effect as to all Notes issued thereunder, when either:
(1) all Notes that have been authenticated (except lost,
stolen or destroyed Notes that have been replaced or paid and
Notes for whose payment money has theretofore been deposited in
trust or segregated and held in trust by the Company and
thereafter repaid to the Company or discharged from such trust)
have been delivered to the Trustee for cancellation, or
(2) all Notes that have not been delivered to the Trustee
for cancellation have become due and payable or will become due
and payable within one year by reason of the giving of a notice
of redemption or otherwise and the Company or any Subsidiary
Guarantor has irrevocably deposited or caused to be irrevocably
deposited with the Trustee as trust funds in trust solely for
such purpose, cash in U.S. dollars, U.S. Government
Obligations, or a combination thereof, in such amounts as will
be sufficient without consideration of any reinvestment of
interest, to pay and discharge the entire indebtedness on the
Notes not delivered to the Trustee for cancellation for
principal and accrued interest to the date of Stated Maturity or
redemption, and in each case certain other requirements set
forth in the Indenture are satisfied.
No personal
liability of directors, officers, employees and
stockholders
No director, officer, employee, incorporator, stockholder,
member, partner or trustee of the Company or any Subsidiary
Guarantor, as such, shall have any liability for any obligations
of the Company or any Subsidiary Guarantor under the Notes, the
Indenture or the Subsidiary Guarantees or for any claim based
on, in respect of, or by reason of, such obligations or their
creation. Each holder by accepting a Note waives and releases
all such liability. The waiver and release are part of the
consideration for issuance of the Notes.
Concerning the
trustee
Wells Fargo Bank, National Association will be the Trustee under
the Indenture and has been appointed by the Company as registrar
and paying agent with regard to the Notes. Such bank is a lender
under the Senior Secured Credit Agreement.
S-145
The Indenture will contain certain limitations on the rights of
the Trustee, should it become a creditor of the Company, to
obtain payment of claims in certain cases, or to realize on
certain property received in respect of any such claim as
security or otherwise. The Trustee will be permitted to engage
in other transactions; provided, however, that if it
acquires any conflicting interest (as defined in the
Trust Indenture Act) while any Default exists it must
eliminate such conflict within 90 days, apply to the SEC
for permission to continue as Trustee with such conflict or
resign as Trustee.
Governing
law
The Indenture provides that it and the Notes will be governed
by, and construed in accordance with, the laws of the State of
New York.
Certain
definitions
Acquired Indebtedness means Indebtedness
(i) of a Person or any of its Subsidiaries existing at the
time such Person becomes or is merged with and into a Restricted
Subsidiary or (ii) assumed in connection with the
acquisition of assets from such Person, in each case whether or
not Incurred by such Person in connection with, or in
anticipation or contemplation of, such Person becoming a
Restricted Subsidiary or such acquisition. Acquired Indebtedness
shall be deemed to have been Incurred, with respect to
clause (i) of the preceding sentence, on the date such
Person becomes or is merged with and into a Restricted
Subsidiary and, with respect to clause (ii) of the
preceding sentence, on the date of consummation of such
acquisition of assets.
Additional Assets means:
(1) any properties or assets to be used by the Company or a
Restricted Subsidiary in the Oil and Gas Business;
(2) capital expenditures by the Company or a Restricted
Subsidiary in the Oil and Gas Business;
(3) the Capital Stock of a Person that becomes a Restricted
Subsidiary as a result of the acquisition of such Capital Stock
by the Company or a Restricted Subsidiary; or
(4) Capital Stock constituting a minority interest in any
Person that at such time is a Restricted Subsidiary;
provided, however, that, in the case of
clauses (3) and (4), such Restricted Subsidiary is
primarily engaged in the Oil and Gas Business.
Adjusted Consolidated Net Tangible Assets of
the Company means (without duplication), as of the date of
determination, the remainder of:
(a) the sum of:
(i) discounted future net revenues from proved oil and gas
reserves of the Company and its Restricted Subsidiaries
calculated in accordance with SEC guidelines before any state or
federal income taxes, as estimated by the Company in a reserve
report prepared as of the end of the Companys most
recently completed fiscal year for which audited financial
statements are available, as increased by, as of the date of
determination, the estimated discounted future net revenues from
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(A) estimated proved oil and gas reserves acquired since
such year end, which reserves were not reflected in such year
end reserve report, and
(B) estimated oil and gas reserves attributable to
extensions, discoveries and other additions and upward revisions
of estimates of proved oil and gas reserves since such year end
due to exploration, development or exploitation, production or
other activities, which would, in accordance with standard
industry practice, cause such revisions (including the impact to
proved reserves and future net revenues from estimated
development costs incurred and the accretion of discount since
such year end), and decreased by, as of the date of
determination, the estimated discounted future net revenues from
(C) estimated proved oil and gas reserves produced or
disposed of since such year end, and
(D) estimated oil and gas reserves attributable to downward
revisions of estimates of proved oil and gas reserves since such
year end due to changes in geological conditions or other
factors which would, in accordance with standard industry
practice, cause such revisions, in each case calculated on a
pre-tax basis and substantially in accordance with SEC
guidelines,
in the case of clauses (A) through (D) utilizing
prices and costs calculated in accordance with SEC guidelines as
if the end of the most recent fiscal quarter preceding the date
of determination for which such information is available to the
Company were year end; provided, however, that in
the case of each of the determinations made pursuant to
clauses (A) through (D), such increases and decreases shall
be as estimated by the Companys petroleum engineers;
(ii) the capitalized costs that are attributable to Oil and
Gas Properties of the Company and its Restricted Subsidiaries to
which no proved oil and gas reserves are attributable, based on
the Companys books and records as of a date no earlier
than the date of the Companys latest available annual or
quarterly financial statements;
(iii) the Net Working Capital of the Company and its
Restricted Subsidiaries on a date no earlier than the date of
the Companys latest annual or quarterly financial
statements; and
(iv) the greater of
(A) the net book value of other tangible assets of the
Company and its Restricted Subsidiaries, as of a date no earlier
than the date of the Companys latest annual or quarterly
financial statements, and
(B) the appraised value, as estimated by independent
appraisers, of other tangible assets of the Company and its
Restricted Subsidiaries, as of a date no earlier than the date
of the Companys latest audited financial statements;
provided, that, if no such appraisal has been performed
the Company shall not be required to obtain such an appraisal
and only clause (iv)(A) of this definition shall apply;
S-147
minus
(b) the sum of:
(i) Minority Interests;
(ii) any net gas balancing liabilities of the Company and
its Restricted Subsidiaries reflected in the Companys
latest annual or quarterly balance sheet (to the extent not
deducted in calculating Net Working Capital of the Company in
accordance with clause (a)(iii) above of this definition);
(iii) to the extent included in (a)(i) above, the
discounted future net revenues, calculated in accordance with
SEC guidelines (but utilizing prices and costs calculated in
accordance with SEC guidelines as if the end of the most recent
fiscal quarter preceding the date of determination for which
such information is available to the Company were year end),
attributable to reserves which are required to be delivered to
third parties to fully satisfy the obligations of the Company
and its Restricted Subsidiaries with respect to Volumetric
Production Payments (determined, if applicable, using the
schedules specified with respect thereto); and
(iv) the discounted future net revenues, calculated in
accordance with SEC guidelines, attributable to reserves subject
to Dollar-Denominated Production Payments which, based on the
estimates of production and price assumptions included in
determining the discounted future net revenues specified in
(a)(i) above, would be necessary to fully satisfy the payment
obligations of the Company and its Subsidiaries with respect to
Dollar-Denominated Production Payments (determined, if
applicable, using the schedules specified with respect thereto).
If the Company changes its method of accounting from the
successful efforts method of accounting to the full cost or a
similar method, Adjusted Consolidated Net Tangible
Assets will continue to be calculated as if the Company
were still using the successful efforts method of accounting.
Affiliate of any specified Person means any
other Person, directly or indirectly, controlling or controlled
by or under direct or indirect common control with such
specified Person. For the purposes of this definition,
control when used with respect to any Person means
the power to direct the management and policies of such Person,
directly or indirectly, whether through the ownership of voting
securities, by contract or otherwise; and the terms
controlling and controlled have meanings
correlative to the foregoing.
Asset Disposition means any direct or
indirect sale, lease (including by means of Production Payments
and Reserve Sales and a Sale/Leaseback Transaction) (other than
an operating lease entered into in the ordinary course of the
Oil and Gas Business), transfer, issuance or other disposition,
or a series of related sales, leases, transfers, issuances or
dispositions that are part of a common plan, of (A) shares
of Capital Stock of a Restricted Subsidiary (other than
Preferred Stock of Restricted Subsidiaries issued in compliance
with the covenant described under the heading
Certain covenantsLimitation on Indebtedness
and Preferred Stock, and directors qualifying shares
or shares required by applicable law to be held by a Person
other than the Company or a Restricted Subsidiary), (B) all
or substantially all the assets of any division or line of
business of the Company or any Restricted Subsidiary (excluding
any division or line of business the assets of which are owned
by an Unrestricted Subsidiary) or (C) any other assets of
the Company or any Restricted Subsidiary outside of the ordinary
course of business of the
S-148
Company or such Restricted Subsidiary (each referred to for the
purposes of this definition as a disposition), in
each case by the Company or any of its Restricted Subsidiaries,
including any disposition by means of a merger, consolidation or
similar transaction.
Notwithstanding the preceding, the following items shall not be
deemed to be Asset Dispositions:
(1) a disposition by a Restricted Subsidiary to the Company
or by the Company or a Restricted Subsidiary to a Restricted
Subsidiary;
(2) a disposition of cash, Cash Equivalents or other
financial assets in the ordinary course of business;
(3) a disposition of Hydrocarbons or mineral products
inventory in the ordinary course of business;
(4) a disposition of damaged, unserviceable, obsolete or
worn out equipment or equipment that is no longer necessary for
the proper conduct of the business of the Company and its
Restricted Subsidiaries and that is disposed of in each case in
the ordinary course of business;
(5) transactions in accordance with the covenant described
under Certain covenantsMerger and
consolidation;
(6) an issuance of Capital Stock by a Restricted Subsidiary
to the Company or to a Restricted Subsidiary;
(7) the making of a Permitted Investment or a Restricted
Payment (or a disposition that would constitute a Restricted
Payment but for the exclusions from the definition thereof)
permitted by the covenant described under Certain
covenantsLimitation on Restricted Payments;
(8) an Asset Swap;
(9) dispositions of assets with a Fair Market Value of less
than $10.0 million;
(10) Permitted Liens;
(11) dispositions of receivables in connection with the
compromise, settlement or collection thereof in the ordinary
course of business or in bankruptcy or similar proceedings and
exclusive of factoring or similar arrangements;
(12) the licensing or sublicensing of intellectual property
(including, without limitation, the licensing of seismic data)
or other general intangibles and licenses, leases or subleases
of other property in the ordinary course of business which do
not materially interfere with the business of the Company and
its Restricted Subsidiaries;
(13) foreclosure on assets;
(14) any Production Payments and Reserve Sales; provided
that any such Production Payments and Reserve Sales, other
than incentive compensation programs on terms that are
reasonably customary in the Oil and Gas Business for geologists,
geophysicists and other providers of technical services to the
Company or a Restricted Subsidiary, shall have been created,
Incurred, issued, assumed or Guaranteed in connection with the
financing of, and within 60 days after the acquisition of,
the property that is subject thereto;
S-149
(15) a disposition of oil and natural gas properties in
connection with tax credit transactions complying with
Section 29 or any successor or analogous provisions of the
Code;
(16) surrender or waiver of contract rights, oil and gas
leases, or the settlement, release or surrender of contract,
tort or other claims of any kind;
(17) the abandonment, farmout, lease or sublease of
developed or undeveloped Oil and Gas Properties in the ordinary
course of business; and
(18) a disposition (whether or not in the ordinary course
of business) of any Oil and Gas Property or interest therein to
which no proved reserves are attributable at the time of such
disposition.
Asset Swap means any substantially
contemporaneous (and in any event occurring within 180 days
of each other) purchase and sale or exchange of any oil or
natural gas properties or assets or interests therein between
the Company or any of its Restricted Subsidiaries and another
Person; provided, that any cash received must be applied
in accordance with Certain covenantsLimitation
on sales of assets and Subsidiary stock as if the Asset
Swap were an Asset Disposition.
Average Life means, as of the date of
determination, with respect to any Indebtedness or Preferred
Stock, the quotient obtained by dividing (1) the sum of the
products of the numbers of years from the date of determination
to the dates of each successive scheduled principal payment of
such Indebtedness or redemption or similar payment with respect
to such Preferred Stock multiplied by the amount of such payment
by (2) the sum of all such payments.
Beneficial Owner has the meaning assigned to
such term in
Rule 13d-3
and
Rule 13d-5
under the Exchange Act, except that in calculating the
beneficial ownership of any particular person (as
that term is used in Section 13(d)(3) of the Exchange Act),
such person will be deemed to have beneficial
ownership of all securities that such person has the
right to acquire by conversion or exercise of other securities,
whether such right is currently exercisable or is exercisable
only after the passage of time. The terms Beneficially
Owns and Beneficially Owned have a
corresponding meaning.
Board of Directors means, as to any Person
that is a corporation, the board of directors of such Person or
any duly authorized committee thereof or as to any Person that
is not a corporation, the board of managers or such other
individual or group serving a similar function.
Business Day means each day that is not a
Saturday, Sunday or other day on which commercial banking
institutions in New York, New York are authorized or required by
law to close.
Capital Stock of any Person means any and all
shares, units, interests, rights to purchase, warrants, options,
participations or other equivalents of or interests in (however
designated) equity of such Person, including any Preferred
Stock, but excluding any debt securities convertible into, or
exchangeable for, such equity.
Capitalized Lease Obligations means an
obligation that is required to be classified and accounted for
as a capitalized lease for financial reporting purposes in
accordance with GAAP, and the amount of Indebtedness represented
by such obligation will be the capitalized amount of such
obligation at the time any determination thereof is to be made
as determined in accordance with GAAP, and the Stated Maturity
thereof will be the date of the last payment of rent or any
other amount due under such lease prior to the first date such
lease may be terminated without penalty.
S-150
Cash Equivalents means:
(1) securities issued or directly and fully guaranteed or
insured by the United States Government or any agency or
instrumentality of the United States (provided that the
full faith and credit of the United States is pledged in support
thereof), having maturities of not more than one year from the
date of acquisition;
(2) marketable general obligations issued by any state of
the United States of America or any political subdivision of any
such state or any public instrumentality thereof maturing within
one year from the date of acquisition and, at the time of
acquisition, having a credit rating of A (or the
equivalent thereof) or better from either S&P or
Moodys;
(3) certificates of deposit, time deposits, eurodollar time
deposits, overnight bank deposits or bankers acceptances
having maturities of not more than one year from the date of
acquisition thereof issued by any commercial bank the short-term
deposit of which is rated at the time of acquisition thereof at
least
A-2
or the equivalent thereof by S&P, or
P-2
or the equivalent thereof by Moodys, and having combined
capital and surplus in excess of $100.0 million;
(4) repurchase obligations with a term of not more than
seven days for underlying securities of the types described in
clauses (1), (2) and (3) entered into with any bank
meeting the qualifications specified in clause (3) above;
(5) commercial paper rated at the time of acquisition
thereof at least
A-2
or the equivalent thereof by S&P or
P-2
or the equivalent thereof by Moodys, or carrying an
equivalent rating by a nationally recognized rating agency, if
both of the two named Rating Agencies cease publishing ratings
of investments, and in any case maturing within one year after
the date of acquisition thereof; and
(6) interests in any investment company or money market
fund which invests 95% or more of its assets in instruments of
the type specified in clauses (1) through (5) above.
Change of Control means:
(1) any person or group of related
persons (as such terms are used in Sections 13(d) and 14(d)
of the Exchange Act), is or becomes the Beneficial Owner,
directly or indirectly, of more than 50% of the total voting
power of the Voting Stock of the Company (or its successor by
merger, consolidation or purchase of all or substantially all of
its assets) (for the purposes of this clause (1), such person or
group shall be deemed to Beneficially Own any Voting Stock of
the Company held by a parent entity, if such person or group
Beneficially Owns, directly or indirectly, more than 50% of the
total voting power of the Voting Stock of such parent entity);
(2) the first day on which a majority of the members of the
Board of Directors of the Company are not Continuing Directors;
(3) the sale, lease, transfer, conveyance or other
disposition (other than by way of merger or consolidation), in
one or a series of related transactions, of all or substantially
all of the assets of the Company and its Restricted Subsidiaries
taken as a whole to any person (as such term is used
in Sections 13(d) and 14(d) of the Exchange Act); or
(4) the adoption by the shareholders of the Company of a
plan or proposal for the liquidation or dissolution of the
Company.
S-151
Code means the Internal Revenue Code of 1986,
as amended.
Commodity Agreements means, in respect of any
Person, any forward contract, commodity swap agreement,
commodity option agreement or other similar agreement or
arrangement in respect of Hydrocarbons used, produced, processed
or sold by such Person that are customary in the Oil and Gas
Business and designed to protect such Person against fluctuation
in Hydrocarbon prices.
Common Stock means, with respect to any
Person, any and all shares, interests or other participations
in, and other equivalents (however designated and whether voting
or nonvoting) of such Persons common stock whether or not
outstanding on the Issue Date, and includes, without limitation,
all series and classes of such common stock.
Consolidated Coverage Ratio means as of any
date of determination, the ratio of (x) the aggregate
amount of Consolidated EBITDAX of such Person for the period of
the most recent four consecutive fiscal quarters ending prior to
the date of such determination for which financial statements
are in existence to (y) Consolidated Interest Expense for
such four fiscal quarters, provided, however, that:
(1) if the Company or any Restricted Subsidiary:
(a) has Incurred any Indebtedness since the beginning of
such period that remains outstanding on such date of
determination or if the transaction giving rise to the need to
calculate the Consolidated Coverage Ratio is an Incurrence of
Indebtedness, Consolidated EBITDAX and Consolidated Interest
Expense for such period will be calculated after giving effect
on a pro forma basis to such Indebtedness and the use of
proceeds thereof as if such Indebtedness had been Incurred on
the first day of such period and such proceeds had been applied
as of such date (except that in making such computation, the
amount of Indebtedness under any revolving Credit Facility
outstanding on the date of such calculation will be deemed to be
(i) the average daily balance of such Indebtedness during
such four fiscal quarters or such shorter period for which such
facility was outstanding or (ii) if such revolving Credit
Facility was created after the end of such four fiscal quarters,
the average daily balance of such Indebtedness during the period
from the date of creation of such revolving Credit Facility to
the date of such calculation, in each case, provided that
such average daily balance shall take into account any repayment
of Indebtedness under such revolving Credit Facility as provided
in clause (b)); or
(b) has repaid, repurchased, defeased or otherwise
discharged any Indebtedness since the beginning of the period,
including with the proceeds of such new Indebtedness, that is no
longer outstanding on such date of determination or if the
transaction giving rise to the need to calculate the
Consolidated Coverage Ratio involves a discharge of Indebtedness
(in each case other than Indebtedness Incurred under any
revolving Credit Facility unless such Indebtedness has been
permanently repaid and the related commitment terminated),
Consolidated EBITDAX and Consolidated Interest Expense for such
period will be calculated after giving effect on a pro forma
basis to such discharge of such Indebtedness as if such
discharge had occurred on the first day of such period;
(2) if, since the beginning of such period, the Company or
any Restricted Subsidiary has made any Asset Disposition or if
the transaction giving rise to the need to calculate the
Consolidated Coverage Ratio is such an Asset Disposition, the
Consolidated EBITDAX for such
S-152
period will be reduced by an amount equal to the Consolidated
EBITDAX (if positive) directly attributable to the assets which
are the subject of such Asset Disposition for such period or
increased by an amount equal to the Consolidated EBITDAX (if
negative) directly attributable thereto for such period and
Consolidated Interest Expense for such period shall be reduced
by an amount equal to the Consolidated Interest Expense directly
attributable to any Indebtedness of the Company or any
Restricted Subsidiary repaid, repurchased, defeased or otherwise
discharged with respect to the Company and its continuing
Restricted Subsidiaries in connection with or with the proceeds
from such Asset Disposition for such period (or, if the Capital
Stock of any Restricted Subsidiary is sold, the Consolidated
Interest Expense for such period directly attributable to the
Indebtedness of such Restricted Subsidiary to the extent the
Company and its continuing Restricted Subsidiaries are no longer
liable for such Indebtedness after such sale);
(3) if, since the beginning of such period, the Company or
any Restricted Subsidiary (by merger or otherwise) has made an
Investment in any Restricted Subsidiary (or any Person which
becomes a Restricted Subsidiary or is merged with or into the
Company or a Restricted Subsidiary) or an acquisition (or will
have received a contribution) of assets, including any
acquisition or contribution of assets occurring in connection
with a transaction causing a calculation to be made under the
Indenture, which constitutes all or substantially all of a
company, division, operating unit, segment, business, group of
related assets or line of business, Consolidated EBITDAX and
Consolidated Interest Expense for such period will be calculated
after giving pro forma effect thereto (including the Incurrence
of any Indebtedness) as if such Investment or acquisition or
contribution had occurred on the first day of such
period; and
(4) if, since the beginning of such period, any Person
(that subsequently became a Restricted Subsidiary or was merged
with or into the Company or any Restricted Subsidiary since the
beginning of such period) made any Asset Disposition or any
Investment or acquisition of assets that would have required an
adjustment pursuant to clause (2) or (3) above if made
by the Company or a Restricted Subsidiary during such period,
Consolidated EBITDAX and Consolidated Interest Expense for such
period will be calculated after giving pro forma effect thereto
as if such Asset Disposition or Investment or acquisition of
assets had occurred on the first day of such period.
For purposes of this definition, whenever pro forma effect is to
be given to any calculation under this definition, the pro forma
calculations will be determined in good faith by a responsible
financial or accounting officer of the Company; provided
that such officer may in his or her discretion include any
reasonably identifiable and factually supportable pro forma
changes to Consolidated EBITDAX, including any pro forma
expenses and cost reductions, that have occurred or in the
judgment of such officer are reasonably expected to occur within
12 months of the date of the applicable transaction
(regardless of whether such expense or cost reduction or any
other operating improvements could then be reflected properly in
pro forma financial statements prepared in accordance with
Regulation S-X
under the Securities Act or any other regulation or policy of
the SEC). If any Indebtedness bears a floating rate of interest
and is being given pro forma effect, the interest expense on
such Indebtedness will be calculated as if the average rate in
effect from the beginning of such period to the date of
determination had been the applicable rate for the entire period
(taking into account any Interest Rate Agreement applicable to
such Indebtedness, but if the remaining term of such Interest
Rate Agreement is less than 12 months, then such Interest
Rate Agreement shall only be taken into account for that portion
of the period equal to the remaining term thereof). If any
Indebtedness
S-153
that is being given pro forma effect bears an interest rate at
the option of the Company, the interest rate shall be calculated
by applying such optional rate chosen by the Company. Interest
on Indebtedness that may optionally be determined at an interest
rate based upon a factor of a prime or similar rate, a
eurocurrency interbank offered rate, or other rate, shall be
deemed to have been based upon the rate actually chosen, or, if
none, then based upon such optional rate chosen as the Company
may designate.
Consolidated EBITDAX for any period means,
without duplication, the Consolidated Net Income for such
period, plus the following, without duplication and to the
extent deducted (and not added back) in calculating such
Consolidated Net Income:
(1) Consolidated Interest Expense;
(2) Consolidated Income Tax Expense;
(3) consolidated depletion and depreciation expense of the
Company and its Restricted Subsidiaries;
(4) consolidated amortization expense or impairment charges
of the Company and its Restricted Subsidiaries recorded in
connection with the application of Statement of Financial
Accounting Standard No. 142, Goodwill and Other
Intangibles and Statement of Financial Accounting Standard
No. 144, Accounting for the Impairment or Disposal of
Long Lived Assets;
(5) other non-cash charges of the Company and its
Restricted Subsidiaries (excluding any such non-cash charge to
the extent it represents an accrual of or reserve for cash
charges in any future period or amortization of a prepaid cash
expense that was paid in a prior period not included in the
calculation); and
(6) consolidated exploration and abandonment expense of the
Company and its Restricted Subsidiaries,
if applicable for such period; and less, to the extent included
in calculating such Consolidated Net Income and in excess of any
costs or expenses attributable thereto that were deducted (and
not added back) in calculating such Consolidated Net Income, the
sum of (x) the amount of deferred revenues that are
amortized during such period and are attributable to reserves
that are subject to Volumetric Production Payments,
(y) amounts recorded in accordance with GAAP as repayments
of principal and interest pursuant to Dollar-Denominated
Production Payments and (z) other non-cash gains (excluding
any non-cash gain to the extent it represents the reversal of an
accrual or reserve for a potential cash item that reduced
Consolidated EBITDAX in any prior period).
Notwithstanding the preceding sentence, clauses (2) through
(6) relating to amounts of a Restricted Subsidiary of the
Company will be added to Consolidated Net Income to compute
Consolidated EBITDAX of the Company only to the extent (and in
the same proportion) that the net income (loss) of such
Restricted Subsidiary was included in calculating the
Consolidated Net Income of the Company and, to the extent the
amounts set forth in clauses (2) through (6) are in
excess of those necessary to offset a net loss of such
Restricted Subsidiary or if such Restricted Subsidiary has net
income for such period included in Consolidated Net Income, only
if a corresponding amount would be permitted at the date of
determination to be dividended to the Company by such Restricted
Subsidiary without prior approval (that has not been obtained),
pursuant to the terms of its charter and all agreements,
instruments, judgments, decrees, orders,
S-154
statutes, rules and governmental regulations applicable to that
Restricted Subsidiary or the holders of its Capital Stock.
Consolidated Income Tax Expense means, with
respect to any period, the provision for federal, state, local
and foreign income taxes (including state franchise taxes
accounted for as income taxes in accordance with GAAP) of the
Company and its Restricted Subsidiaries for such period as
determined in accordance with GAAP.
Consolidated Interest Expense means, for any
period, the total consolidated interest expense (less interest
income) of the Company and its Restricted Subsidiaries, whether
paid or accrued, plus, to the extent not included in such
interest expense and without duplication:
(1) interest expense attributable to Capitalized Lease
Obligations and the interest component of any deferred payment
obligations;
(2) amortization of debt discount and debt issuance cost
(provided that any amortization of bond premium will be
credited to reduce Consolidated Interest Expense unless,
pursuant to GAAP, such amortization of bond premium has
otherwise reduced Consolidated Interest Expense);
(3) non-cash interest expense;
(4) commissions, discounts and other fees and charges owed
with respect to letters of credit and bankers acceptance
financing;
(5) the interest expense on Indebtedness of another Person
that is Guaranteed by the Company or one of its Restricted
Subsidiaries or secured by a Lien on assets of the Company or
one of its Restricted Subsidiaries, to the extent such Guarantee
becomes payable or such Lien becomes subject to foreclosure;
(6) cash costs associated with Interest Rate Agreements
(including amortization of fees); provided,
however, that if Interest Rate Agreements result in net
cash benefits rather than costs, such benefits shall be credited
to reduce Consolidated Interest Expense unless, pursuant to
GAAP, such net benefits are otherwise reflected in Consolidated
Net Income;
(7) the consolidated interest expense of the Company and
its Restricted Subsidiaries that was capitalized during such
period; and
(8) all dividends paid or payable in cash, Cash Equivalents
or Indebtedness or accrued during such period on any series of
Disqualified Stock of the Company or on Preferred Stock of its
Restricted Subsidiaries payable to a party other than the
Company or a Wholly-Owned Subsidiary,
minus, to the extent included above, any interest attributable
to Dollar-Denominated Production Payments.
For the purpose of calculating the Consolidated Coverage Ratio
in connection with the Incurrence of any Indebtedness described
in the final paragraph of the definition of
Indebtedness, the calculation of Consolidated
Interest Expense shall include all interest expense (including
any amounts described in clauses (1) through
(8) above) relating to any Indebtedness of the Company or
any Restricted Subsidiary described in the final paragraph of
the definition of Indebtedness.
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Consolidated Net Income means, for any
period, the aggregate net income (loss) of the Company and its
consolidated Subsidiaries determined in accordance with GAAP and
before any reduction in respect of Preferred Stock dividends of
such Person; provided, however, that there will
not be included (to the extent otherwise included therein) in
such Consolidated Net Income:
(1) any net income (loss) of any Person (other than the
Company) if such Person is not a Restricted Subsidiary, except
that:
(a) subject to the limitations contained in
clauses (3) and (4) below, the Companys equity
in the net income of any such Person for such period will be
included in such Consolidated Net Income up to the aggregate
amount of cash actually distributed by such Person during such
period to the Company or a Restricted Subsidiary as a dividend
or other distribution (subject, in the case of a dividend or
other distribution to a Restricted Subsidiary, to the
limitations contained in clause (2) below); and
(b) the Companys equity in a net loss of any such
Person for such period will be included in determining such
Consolidated Net Income to the extent such loss has been funded
with cash from the Company or a Restricted Subsidiary during
such period;
(2) any net income (but not loss) of any Restricted
Subsidiary if such Subsidiary is subject to restrictions,
directly or indirectly, on the payment of dividends or the
making of distributions by such Restricted Subsidiary, directly
or indirectly, to the Company, except that:
(a) subject to the limitations contained in clauses (3),
(4) and (5) below, the Companys equity in the
net income of any such Restricted Subsidiary for such period
will be included in such Consolidated Net Income up to the
aggregate amount of cash that could have been distributed by
such Restricted Subsidiary during such period to the Company or
another Restricted Subsidiary as a dividend or other
distribution (subject, in the case of a dividend or other
distribution paid to another Restricted Subsidiary, to the
limitation contained in this clause); and
(b) the Companys equity in a net loss of any such
Restricted Subsidiary for such period will be included in
determining such Consolidated Net Income;
(3) any gain (loss) realized upon the sale or other
disposition of any property, plant or equipment of the Company
or its consolidated Subsidiaries (including pursuant to any
Sale/Leaseback Transaction) which is not sold or otherwise
disposed of in the ordinary course of business and any gain
(loss) realized upon the sale or other disposition of any
Capital Stock of any Person;
(4) any extraordinary or nonrecurring gains or losses,
together with any related provision for taxes on such gains or
losses and all related fees and expenses;
(5) the cumulative effect of a change in accounting
principles;
(6) any asset impairment writedowns on Oil and Gas
Properties under GAAP or SEC guidelines;
(7) any unrealized non-cash gains or losses or charges in
respect of Hedging Obligations (including those resulting from
the application of Statement of Financial Accounting Standard
No. 133);
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(8) income or loss attributable to discontinued operations
(including, without limitation, operations disposed of during
such period whether or not such operations were classified as
discontinued);
(9) all deferred financing costs written off, and premiums
paid, in connection with any early extinguishment of
Indebtedness; and
(10) any non-cash compensation charge arising from any
grant of stock, stock options or other equity based awards;
provided that the proceeds resulting from any such grant
will be excluded from clause (c)(ii) of the first paragraph of
the covenant described under Limitation on
Restricted Payments.
Continuing Directors means, as of any date of
determination, any member of the Board of Directors of the
Company who: (1) was a member of such Board of Directors on
the date of the Indenture; or (2) was nominated for
election or elected to such Board of Directors with the approval
of a majority of the Continuing Directors who were members of
such Board of Directors at the time of such nomination or
election.
Credit Facility means, with respect to the
Company or any Restricted Subsidiary, one or more debt
facilities (including, without limitation, the Senior Secured
Credit Agreement), indentures or commercial paper facilities
providing for revolving credit loans, term loans, receivables
financing (including through the sale of receivables to such
lenders or to special purpose entities formed to borrow from
such lenders against such receivables) or letters of credit, in
each case, as amended, restated, modified, renewed, refunded,
replaced or refinanced in whole or in part from time to time
(and whether or not with the original administrative agent and
lenders or another administrative agent or agents or other
lenders and whether provided under the original Senior Secured
Credit Agreement or any other credit or other agreement or
indenture).
Currency Agreement means in respect of a
Person any foreign exchange contract, currency swap agreement,
futures contract, option contract or other similar agreement as
to which such Person is a party or a beneficiary.
Default means any event which is, or after
notice or passage of time or both would be, an Event of Default.
Disqualified Stock means, with respect to any
Person, any Capital Stock of such Person which by its terms (or
by the terms of any security into which it is convertible or for
which it is exchangeable) at the option of the holder of the
Capital Stock or upon the happening of any event:
(1) matures or is mandatorily redeemable (other than
redeemable only for Capital Stock of such Person which is not
itself Disqualified Stock) pursuant to a sinking fund obligation
or otherwise;
(2) is convertible or exchangeable for Disqualified Stock
or other Indebtedness (excluding Capital Stock which is
convertible or exchangeable solely at the option of the Company
or a Restricted Subsidiary); or
(3) is redeemable at the option of the holder of the
Capital Stock in whole or in part,
in each case on or prior to the date that is 91 days after
the earlier of the date (a) of the Stated Maturity of the
Notes or (b) on which there are no Notes outstanding;
provided that only the portion of Capital Stock which so
matures or is mandatorily redeemable, is so convertible or
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exchangeable or is so redeemable at the option of the holder
thereof prior to such date will be deemed to be Disqualified
Stock; provided further, that any Capital Stock that
would constitute Disqualified Stock solely because the holders
thereof have the right to require the Company to repurchase such
Capital Stock upon the occurrence of a change of control or
asset sale (each defined in a substantially identical manner to
the corresponding definitions in the Indenture) shall not
constitute Disqualified Stock if the terms of such Capital Stock
(and all such securities into which it is convertible or for
which it is exchangeable) provide that (i) the Company may
not repurchase or redeem any such Capital Stock (and all such
securities into which it is convertible or for which it is
ratable or exchangeable) pursuant to such provision prior to
compliance by the Company with the provisions of the Indenture
described under the captions Change of control
and Certain covenantsLimitation on sales of
assets and Subsidiary stock and (ii) such repurchase
or redemption will be permitted solely to the extent also
permitted in accordance with the provisions of the Indenture
described under the caption Certain
covenantsLimitation on Restricted Payments.
Dollar-Denominated Production Payments means
production payment obligations recorded as liabilities in
accordance with GAAP, together with all undertakings and
obligations in connection therewith.
Domestic Subsidiary means any Restricted
Subsidiary that is organized under the laws of the United States
of America or any state thereof or the District of Columbia.
Equity Offering means a public or private
offering for cash by the Company of Capital Stock (other than
Disqualified Stock), other than public offerings registered on
Form S-8.
Exchange Act means the Securities Exchange
Act of 1934, as amended, and the rules and regulations of the
SEC promulgated thereunder.
Fair Market Value means, with respect to any
asset or property, the sale value that would be obtained in an
arms-length free market transaction between an informed
and willing seller under no compulsion to sell and an informed
and willing buyer under no compulsion to buy. Fair Market Value
of an asset or property in excess of $10.0 million shall be
determined by the Board of Directors of the Company acting in
good faith, whose determination shall be conclusive and
evidenced by a resolution of such Board of Directors, and any
lesser Fair Market Value may be determined by an officer of the
Company acting in good faith.
Foreign Subsidiary means any Restricted
Subsidiary that is not organized under the laws of the United
States of America or any state thereof or the District of
Columbia.
GAAP means generally accepted accounting
principles in the United States of America as in effect from
time to time. All ratios and computations based on GAAP
contained in the Indenture will be computed in conformity with
GAAP.
Guarantee means any obligation, contingent or
otherwise, of any Person directly or indirectly guaranteeing any
Indebtedness of any other Person and any obligation, direct or
indirect, contingent or otherwise, of such Person:
(1) to purchase or pay (or advance or supply funds for the
purchase or payment of) such Indebtedness of such other Person
(whether arising by virtue of partnership arrangements, or by
agreement to keep-well, to purchase assets, goods, securities or
services, to take-or-pay, or to maintain financial statement
conditions or otherwise); or
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(2) entered into for purposes of assuring in any other
manner the obligee of such Indebtedness of the payment thereof
or to protect such obligee against loss in respect thereof (in
whole or in part);
provided, however, that the term
Guarantee will not include endorsements for
collection or deposit in the ordinary course of business or any
obligation to the extent it is payable only in Capital Stock of
the Guarantor that is not Disqualified Stock. The term
Guarantee used as a verb has a corresponding meaning.
Guarantor Subordinated Obligation means, with
respect to a Subsidiary Guarantor, any Indebtedness of such
Subsidiary Guarantor (whether outstanding on the Issue Date or
thereafter Incurred) which is expressly subordinate in right of
payment to the obligations of such Subsidiary Guarantor under
its Subsidiary Guarantee pursuant to a written agreement.
Hedging Obligations of any Person means the
obligations of such Person pursuant to any Interest Rate
Agreement, Currency Agreement or Commodity Agreement.
holder means a Person in whose name a Note is
registered on the registrars books.
Hydrocarbons means oil, natural gas, casing
head gas, drip gasoline, natural gasoline, condensate,
distillate, liquid hydrocarbons, gaseous hydrocarbons and all
constituents, elements or compounds thereof and products refined
or processed therefrom.
Immaterial Subsidiary means, as of any date,
any Restricted Subsidiary whose total assets, as of the end of
the most recent month for which financial statements are
available, are less than $1,000,000 and whose total revenues for
the most recent
12-month
period for which financial statements are available do not
exceed $1,000,000; provided that a Restricted Subsidiary
will not be considered to be an Immaterial Subsidiary if it,
directly or indirectly, Guarantees or otherwise provides direct
credit support for any Indebtedness of the Company.
Incur means issue, create, assume, Guarantee,
incur or otherwise become directly or indirectly liable for,
contingently or otherwise; provided, however, that
any Indebtedness or Capital Stock of a Person existing at the
time such Person becomes a Restricted Subsidiary (whether by
merger, consolidation, acquisition or otherwise) will be deemed
to be Incurred by such Restricted Subsidiary at the time it
becomes a Restricted Subsidiary; and the terms
Incurred and Incurrence have meanings
correlative to the foregoing.
Indebtedness means, with respect to any
Person on any date of determination (without duplication,
whether or not contingent):
(1) the principal of and premium (if any) in respect of
indebtedness of such Person for borrowed money;
(2) the principal of and premium (if any) in respect of
obligations of such Person evidenced by bonds, debentures, notes
or other similar instruments;
(3) the principal component of all obligations of such
Person in respect of letters of credit, bankers
acceptances or other similar instruments (including
reimbursement obligations with respect thereto except to the
extent such reimbursement obligation relates to a trade payable,
to the extent such letters of credit are not drawn upon or, if
and to the extent drawn upon, such obligation is satisfied
within 30 days of payment on the letter of credit);
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(4) the principal component of all obligations of such
Person (other than obligations payable solely in Capital Stock
that is not Disqualified Stock) to pay the deferred and unpaid
purchase price of property (except as described in
clause (8) of the penultimate paragraph of this definition
of Indebtedness), which purchase price is due more
than six months after the date of placing such property in
service or taking delivery and title thereto to the extent such
obligations would appear as a liabilities upon the consolidated
balance sheet of such Person in accordance with GAAP;
(5) Capitalized Lease Obligations of such Person to the
extent such Capitalized Lease Obligations would appear as
liabilities on the consolidated balance sheet of such Person in
accordance with GAAP;
(6) the principal component or liquidation preference of
all obligations of such Person with respect to the redemption,
repayment or other repurchase of any Disqualified Stock or, with
respect to any Subsidiary that is not a Subsidiary Guarantor,
any Preferred Stock (but excluding, in each case, any accrued
dividends);
(7) the principal component of all Indebtedness of other
Persons secured by a Lien on any asset of such Person, whether
or not such Indebtedness is assumed by such Person;
provided, however, that the amount of such
Indebtedness will be the lesser of (a) the Fair Market
Value of such asset at such date of determination and
(b) the amount of such Indebtedness of such other Persons;
(8) the principal component of Indebtedness of other
Persons to the extent Guaranteed by such Person; and
(9) to the extent not otherwise included in this
definition, net obligations of such Person under Commodity
Agreements, Currency Agreements and Interest Rate Agreements
(the amount of any such obligations to be equal at any time to
the termination value of such agreement or arrangement giving
rise to such obligation that would be payable by such Person at
such time);
provided, however, that any indebtedness which has
been defeased in accordance with GAAP or defeased pursuant to
the deposit of cash or Cash Equivalents (in an amount sufficient
to satisfy all such indebtedness obligations at maturity or
redemption, as applicable, and all payments of interest and
premium, if any) in a trust or account created or pledged for
the sole benefit of the holders of such indebtedness, and
subject to no other Liens, shall not constitute
Indebtedness.
The amount of Indebtedness of any Person at any date will be the
outstanding balance at such date of all unconditional
obligations as described above and the maximum liability, upon
the occurrence of the contingency giving rise to the obligation,
of any contingent obligations at such date.
Notwithstanding the preceding, Indebtedness shall
not include:
(1) Production Payments and Reserve Sales;
(2) any obligation of a Person in respect of a farm-in
agreement or similar arrangement whereby such Person agrees to
pay all or a share of the drilling, completion or other expenses
of an exploratory or development well (which agreement may be
subject to a maximum payment obligation, after which expenses
are shared in accordance with the working or participation
interest therein or in accordance with the agreement of the
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parties) or perform the drilling, completion or other operation
on such well in exchange for an ownership interest in an oil or
gas property;
(3) any obligations under Currency Agreements, Commodity
Agreements and Interest Rate Agreements; provided that
such Agreements are entered into for bona fide hedging purposes
of the Company or its Restricted Subsidiaries (as determined in
good faith by the Board of Directors or senior management of the
Company, whether or not accounted for as a hedge in accordance
with GAAP) and, in the case of Currency Agreements or Commodity
Agreements, such Currency Agreements or Commodity Agreements are
related to business transactions of the Company or its
Restricted Subsidiaries entered into in the ordinary course of
business and, in the case of Interest Rate Agreements, such
Interest Rate Agreements substantially correspond in terms of
notional amount, duration and interest rates, as applicable, to
Indebtedness of the Company or its Restricted Subsidiaries
Incurred without violation of the Indenture;
(4) any obligation arising from agreements of the Company
or a Restricted Subsidiary providing for indemnification,
Guarantees, adjustment of purchase price, holdbacks, contingency
payment obligations or similar obligations, in each case,
Incurred or assumed in connection with the acquisition or
disposition of any business, assets or Capital Stock of a
Restricted Subsidiary, provided that such Indebtedness is
not reflected on the face of the balance sheet of the Company or
any Restricted Subsidiary;
(5) any obligation arising from the honoring by a bank or
other financial institution of a check, draft or similar
instrument (except in the case of daylight overdrafts) drawn
against insufficient funds in the ordinary course of business,
provided that such Indebtedness is extinguished within
five business days of Incurrence;
(6) in-kind obligations relating to net oil or natural gas
balancing positions arising in the ordinary course of business;
(7) all contracts and other obligations, agreements,
instruments or arrangements described in clauses (19), (20),
(21) or (28)(a) of the definition of Permitted
Liens; and
(8) accrued expenses and trade payables and other accrued
liabilities arising in the ordinary course of business that are
not overdue by 90 days past the invoice or billing date or
more or are being contested in good faith by appropriate
proceedings promptly instituted and diligently conducted.
In addition, Indebtedness of any Person shall
include Indebtedness described in the first paragraph of this
definition of Indebtedness that would not appear as
a liability on the balance sheet of such Person if:
(1) such Indebtedness is the obligation of a partnership or
joint venture that is not a Restricted Subsidiary (a Joint
Venture);
(2) such Person or a Restricted Subsidiary of such Person
is a general partner of the Joint Venture or otherwise liable
for all or a portion of the Joint Ventures liabilities (a
General Partner); and
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(3) there is recourse, by contract or operation of law,
with respect to the payment of such Indebtedness to property or
assets of such Person or a Restricted Subsidiary of such Person;
and then such Indebtedness shall be included in an amount not to
exceed:
(a) the lesser of (i) the net assets of the General
Partner and (ii) the amount of such obligations to the
extent that there is recourse, by contract or operation of law,
to the property or assets of such Person or a Restricted
Subsidiary of such Person; or
(b) if less than the amount determined pursuant to
clause (a) immediately above, the actual amount of such
Indebtedness that is with recourse to such Person or a
Restricted Subsidiary of such Person, if the Indebtedness is
evidenced by a writing and is for a determinable amount and the
related interest expense shall be included in Consolidated
Interest Expense to the extent actually paid by such Person and
its Restricted Subsidiaries.
Interest Rate Agreement means with respect to
any Person any interest rate protection agreement, interest rate
future agreement, interest rate option agreement, interest rate
swap agreement, interest rate cap agreement, interest rate
collar agreement, interest rate hedge agreement or other similar
agreement or arrangement as to which such Person is party or a
beneficiary.
Investment means, with respect to any Person,
all investments by such Person in other Persons (including
Affiliates) in the form of any direct or indirect advance, loan
or other extensions of credit (including by way of Guarantee or
similar arrangement, but excluding any debt or extension of
credit represented by a bank deposit other than a time deposit
and advances or extensions of credit to customers in the
ordinary course of business) or capital contribution to (by
means of any transfer of cash or other property to others or any
payment for property or services for the account or use of
others), or any purchase or acquisition of Capital Stock,
Indebtedness or other similar instruments (excluding any
interest in a crude oil or natural gas leasehold to the extent
constituting a security under applicable law) issued by, such
other Person and all other items that are or would be classified
as investments on a balance sheet prepared in accordance with
GAAP; provided that none of the following will be deemed
to be an Investment:
(1) Hedging Obligations entered into in the ordinary course
of business and in compliance with the Indenture;
(2) endorsements of negotiable instruments and documents in
the ordinary course of business; and
(3) an acquisition of assets, Capital Stock or other
securities by the Company or a Subsidiary for consideration to
the extent such consideration consists of Common Stock of the
Company.
The amount of any Investment shall not be adjusted for increases
or decreases in value,
write-ups,
write-downs or write-offs with respect to such Investment.
For purposes of the definition of Unrestricted
Subsidiary and the covenant described under
Certain covenantsLimitation on Restricted
Payments,
(1) Investment will include the portion
(proportionate to the Companys equity interest in a
Restricted Subsidiary to be designated as an Unrestricted
Subsidiary) of the Fair Market Value of the net assets of such
Restricted Subsidiary at the time that such Restricted
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Subsidiary is designated an Unrestricted Subsidiary;
provided, however, that upon a redesignation of
such Subsidiary as a Restricted Subsidiary, the Company will be
deemed to continue to have a permanent Investment in
an Unrestricted Subsidiary in an amount (if positive) equal to
(a) the Companys Investment in such
Subsidiary at the time of such redesignation less (b) the
portion (proportionate to the Companys equity interest in
such Subsidiary) of the Fair Market Value of the net assets of
such Subsidiary at the time that such Subsidiary is so
re-designated a Restricted Subsidiary; and
(2) any property transferred to or from an Unrestricted
Subsidiary will be valued at its Fair Market Value at the time
of such transfer.
Investment Grade Rating means a rating equal
to or higher than:
(1) Baa3 (or the equivalent) with a stable or better
outlook by Moodys; and
(2) BBB− (or the equivalent) with a stable or better
outlook by S&P,
or, if either such entity ceases to make a rating on the
Notes publicly available for reasons outside of the
Companys control, the equivalent investment grade credit
rating from any other Rating Agency.
Investment Grade Rating Event means the first
day on which the Notes have an Investment Grade Rating from each
Rating Agency, and no Default has occurred and is then
continuing under the Indenture.
Issue Date means the first date on which the
Notes are issued under the Indenture.
Lien means, with respect to any asset, any
mortgage, lien (statutory or otherwise), pledge, hypothecation,
charge, security interest, preference, priority or encumbrance
of any kind in respect of such asset, whether or not filed,
recorded or otherwise perfected under applicable law, including
any conditional sale or other title retention agreement, any
lease in the nature thereof, any option or other agreement to
sell or give a security interest in and any filing of or
agreement to give any financing statement under the Uniform
Commercial Code (or equivalent statutes) of any jurisdiction;
provided that in no event shall an operating lease be
deemed to constitute a Lien.
Minority Interest means the percentage
interest represented by any class of Capital Stock of a
Restricted Subsidiary that are not owned by the Company or a
Restricted Subsidiary.
Moodys means Moodys Investors
Service, Inc., or any successor to the rating agency business
thereof.
Net Available Cash from an Asset Disposition
means cash payments received (including any cash payments
received by way of deferred payment of principal pursuant to a
note or installment receivable or otherwise and net proceeds
from the sale or other disposition of any securities received as
consideration, but only as and when received, but excluding any
other consideration received in the form of assumption by the
acquiring Person of Indebtedness or other obligations relating
to the properties or assets that are the subject of such Asset
Disposition or received in any other non-cash form) therefrom,
in each case net of:
(1) all legal, accounting, investment banking, title and
recording tax expenses, commissions and other fees and expenses
Incurred, and all federal, state, provincial, foreign and local
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taxes required to be paid or accrued as a liability under GAAP
(after taking into account any available tax credits or
deductions and any tax sharing agreements), as a consequence of
such Asset Disposition;
(2) all payments made on any Indebtedness which is secured
by any assets subject to such Asset Disposition, in accordance
with the terms of any Lien upon such assets, or which must by
its terms, or in order to obtain a necessary consent to such
Asset Disposition, or by applicable law be repaid out of the
proceeds from such Asset Disposition;
(3) all distributions and other payments required to be
made to minority interest holders in Subsidiaries or joint
ventures or to holders of royalty or similar interests as a
result of such Asset Disposition;
(4) the deduction of appropriate amounts to be provided by
the seller as a reserve, in accordance with GAAP, against any
liabilities associated with the assets disposed of in such Asset
Disposition and retained by the Company or any Restricted
Subsidiary after such Asset Disposition; and
(5) all relocation expenses incurred as a result thereof
and all related severance and associated costs, expenses and
charges of personnel related to assets and related operations
disposed of;
provided, however, that if any consideration for an Asset
Disposition (that would otherwise constitute Net Available Cash)
is required to be held in escrow pending determination of
whether or not a purchase price adjustment will be made, such
consideration (or any portion thereof) shall become Net
Available Cash only at such time as it is released to the
Company or any of its Restricted Subsidiaries from escrow.
Net Cash Proceeds, with respect to any
issuance or sale of Capital Stock or any contribution to equity
capital, means the cash proceeds of such issuance, sale or
contribution net of attorneys fees, accountants
fees, underwriters or placement agents fees, listing
fees, discounts or commissions and brokerage, consultant and
other fees and charges actually Incurred in connection with such
issuance, sale or contribution and net of taxes paid or payable
as a result of such issuance or sale (after taking into account
any available tax credit or deductions and any tax sharing
arrangements).
Net Working Capital means (a) all
current assets of the Company and its Restricted Subsidiaries,
except current assets from commodity price risk management
activities arising in the ordinary course of the Oil and Gas
Business, less (b) all current liabilities of the Company
and its Restricted Subsidiaries, except current liabilities
(i) associated with asset retirement obligations relating
to Oil and Gas Properties, (ii) included in Indebtedness
and (iii) any current liabilities from commodity price risk
management activities arising in the ordinary course of the Oil
and Gas Business, in each case as set forth in the consolidated
financial statements of the Company prepared in accordance with
GAAP.
Non-Recourse Debt means Indebtedness of a
Person:
(1) as to which neither the Company nor any Restricted
Subsidiary (a) provides any Guarantee or credit support of
any kind (including any undertaking, guarantee, indemnity,
agreement or instrument that would constitute Indebtedness) or
(b) is directly or indirectly liable (as a guarantor or
otherwise);
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(2) no default with respect to which (including any rights
that the holders thereof may have to take enforcement action
against an Unrestricted Subsidiary) would permit (upon notice,
lapse of time or both) any holder of any other Indebtedness of
the Company or any Restricted Subsidiary to declare a default
under such other Indebtedness or cause the payment thereof to be
accelerated or payable prior to its stated maturity; and
(3) the explicit terms of which provide there is no
recourse against any of the assets of the Company or its
Restricted Subsidiaries.
Officer means the Chairman of the Board, the
Chief Executive Officer, the President, the Chief Financial
Officer, any Vice President, the Treasurer or the Secretary of
the Company. Officer of any Subsidiary Guarantor has a
correlative meaning.
Officers Certificate means a
certificate signed by two Officers of the Company.
Oil and Gas Business means:
(1) the business of acquiring, exploring, exploiting,
developing, producing, operating and disposing of interests in
oil, natural gas, liquefied natural gas and other Hydrocarbon
and mineral properties or products produced in association with
any of the foregoing;
(2) the business of gathering, marketing, distributing,
treating, processing, storing, refining, selling and
transporting of any production from such interests or properties
and products produced in association therewith and the marketing
of oil, natural gas, other Hydrocarbons and minerals obtained
from unrelated Persons;
(3) any other related energy business, including power
generation and electrical transmission business, directly or
indirectly, from oil, natural gas and other Hydrocarbons and
minerals produced substantially from properties in which the
Company or its Restricted Subsidiaries, directly or indirectly,
participate;
(4) any business relating to oil field sales and
service; and
(5) any business or activity relating to, arising from, or
necessary, appropriate or incidental to the activities described
in the foregoing clauses (1) through (4) of this
definition.
Oil and Gas Properties means all properties,
including equity or other ownership interests therein, owned by
a Person which contain or are believed to contain oil and gas
reserves.
Opinion of Counsel means a written opinion
from legal counsel who is acceptable to the Trustee. The counsel
may be an employee of or counsel to the Company or the Trustee.
Pari Passu Indebtedness means any
Indebtedness of the Company or any Subsidiary Guarantor that
ranks equally in right of payment to the Notes or the Subsidiary
Guarantees, as the case may be.
Permitted Acquisition Indebtedness means
Indebtedness (including Disqualified Stock) of the Company or
any of the Restricted Subsidiaries to the extent such
Indebtedness was Indebtedness:
(1) of an acquired Person prior to the date on which such
Person became a Restricted Subsidiary as a result of having been
acquired and not incurred in contemplation of such
acquisition; or
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(2) of a Person that was merged, consolidated or
amalgamated with or into the Company or a Restricted Subsidiary
that was not incurred in contemplation of such merger,
consolidation or amalgamation,
provided that on the date such Person became a Restricted
Subsidiary or the date such Person was merged, consolidated and
amalgamated with or into the Company or a Restricted Subsidiary,
as applicable, after giving pro forma effect thereto,
(a) the Restricted Subsidiary or the Company, as
applicable, would be permitted to incur at least $1.00 of
additional Indebtedness pursuant to the Consolidated Coverage
Ratio test described under Certain
covenantsLimitation on Indebtedness and Preferred
Stock, or
(b) the Consolidated Coverage Ratio for the Company would
be greater than the Consolidated Coverage Ratio for the Company
immediately prior to such transaction.
Permitted Business Investment means any
Investment made in the ordinary course of, and of a nature that
is or shall have become customary in, the Oil and Gas Business
including investments or expenditures for actively exploiting,
exploring for, acquiring, developing, producing, processing,
gathering, marketing or transporting oil, natural gas or other
Hydrocarbons and minerals through agreements, transactions,
interests or arrangements which permit one to share risks or
costs, comply with regulatory requirements regarding local
ownership or satisfy other objectives customarily achieved
through the conduct of the Oil and Gas Business jointly with
third parties including:
(1) ownership interests in oil, natural gas, other
Hydrocarbons and minerals properties, liquefied natural gas
facilities, processing facilities, gathering systems, pipelines,
storage facilities or related systems or ancillary real property
interests;
(2) Investments in the form of or pursuant to operating
agreements, working interests, royalty interests, mineral
leases, processing agreements, farm-in agreements, farm-out
agreements, contracts for the sale, transportation or exchange
of oil, natural gas, other Hydrocarbons and minerals, production
sharing agreements, participation agreements, development
agreements, area of mutual interest agreements, unitization
agreements, pooling agreements, joint bidding agreements,
service contracts, joint venture agreements, partnership
agreements (whether general or limited), subscription
agreements, stock purchase agreements, stockholder agreements
and other similar agreements (including for limited liability
companies) with third parties; and
(3) direct or indirect ownership interests in drilling rigs
and related equipment, including, without limitation,
transportation equipment.
Permitted Investment means an Investment by
the Company or any Restricted Subsidiary in:
(1) the Company, a Restricted Subsidiary or a Person which
will, upon the making of such Investment, become a Restricted
Subsidiary; provided, however, that the primary
business of such Restricted Subsidiary is the Oil and Gas
Business;
(2) another Person whose primary business is the Oil and
Gas Business if as a result of such Investment such other Person
becomes a Restricted Subsidiary or is merged or consolidated
with or into, or transfers or conveys all or substantially all
its assets to, the Company or a Restricted Subsidiary and, in
each case, any Investment held by such Person; provided
that such Investment was not acquired by such Person in
contemplation of such acquisition, merger, consolidation or
transfer;
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(3) cash and Cash Equivalents;
(4) receivables owing to the Company or any Restricted
Subsidiary created or acquired in the ordinary course of
business and payable or dischargeable in accordance with
customary trade terms; provided, however, that
such trade terms may include such concessionary trade terms as
the Company or any such Restricted Subsidiary deems reasonable
under the circumstances;
(5) payroll, commission, travel, relocation and similar
advances to cover matters that are expected at the time of such
advances ultimately to be treated as expenses for accounting
purposes and that are made in the ordinary course of business;
(6) loans or advances to employees (other than executive
officers) made in the ordinary course of business consistent
with past practices of the Company or such Restricted Subsidiary;
(7) Capital Stock, obligations or securities received in
settlement of debts (x) created in the ordinary course of
business and owing to the Company or any Restricted Subsidiary
or in satisfaction of judgments or (y) pursuant to any plan
of reorganization or similar arrangement in a bankruptcy or
insolvency proceeding;
(8) any Person as a result of the receipt of non-cash
consideration from an Asset Disposition that was made pursuant
to and in compliance with the covenant described under
Certain covenantsLimitation on sales of assets and
Subsidiary stock;
(9) Investments in existence on the Issue Date;
(10) Commodity Agreements, Currency Agreements, Interest
Rate Agreements and related Hedging Obligations, which
transactions or obligations are Incurred in compliance with
Certain covenantsLimitation on Indebtedness
and Preferred Stock;
(11) Guarantees issued in accordance with the covenant
described under Certain covenantsLimitation on
Indebtedness and Preferred Stock;
(12) Permitted Business Investments;
(13) any Person where such Investment was acquired by the
Company or any of its Restricted Subsidiaries (a) in
exchange for any other Investment or accounts receivable held by
the Company or any such Restricted Subsidiary in connection with
or as a result of a bankruptcy, workout, reorganization or
recapitalization of the issuer of such other Investment or
accounts receivable or (b) as a result of a foreclosure by
the Company or any of its Restricted Subsidiaries with respect
to any secured Investment or other transfer of title with
respect to any secured Investment in default;
(14) any Person to the extent such Investments consist of
prepaid expenses, negotiable instruments held for collection and
lease, utility and workers compensation, performance and
other similar deposits made in the ordinary course of business
by the Company or any Restricted Subsidiary;
(15) Guarantees of performance or other obligations (other
than Indebtedness) arising in the ordinary course in the Oil and
Gas Business, including obligations under oil and natural gas
exploration, development, joint operating, and related
agreements and licenses, concessions or operating leases related
to the Oil and Gas Business;
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(16) Investments in the Notes; and
(17) Investments by the Company or any of its Restricted
Subsidiaries, together with all other Investments pursuant to
this clause (17), in an aggregate amount outstanding at the time
of such Investment not to exceed the greater of
$20.0 million and 1.0% of the Companys Adjusted
Consolidated Net Tangible Assets (with the Fair Market Value of
such Investment being measured at the time such Investment is
made and without giving effect to subsequent changes in value).
Permitted Liens means, with respect to any
Person:
(1) Liens securing Indebtedness under a Credit Facility
permitted to be Incurred under the Indenture;
(2) pledges or deposits by such Person under workers
compensation laws, unemployment insurance laws, social security
or old age pension laws or similar legislation, or good faith
deposits in connection with bids, tenders, contracts (other than
for the payment of Indebtedness) or leases to which such Person
is a party, or deposits (which may be secured by a Lien) to
secure public or statutory obligations of such Person including
letters of credit and bank guarantees required or requested by
the United States, any State thereof or any foreign government
or any subdivision, department, agency, organization or
instrumentality of any of the foregoing in connection with any
contract or statute (including lessee or operator obligations
under statutes, governmental regulations, contracts or
instruments related to the ownership, exploration and production
of oil, natural gas, other hydrocarbons and minerals on State,
Federal or foreign lands or waters), or deposits of cash or
United States government bonds to secure indemnity performance,
surety or appeal bonds or other similar bonds to which such
Person is a party, or deposits as security for contested taxes
or import or customs duties or for the payment of rent, in each
case Incurred in the ordinary course of business;
(3) statutory and contractual Liens of landlords and Liens
imposed by law, including carriers, warehousemens,
mechanics, materialmens and repairmens Liens,
in each case for sums not yet due or being contested in good
faith by appropriate proceedings if a reserve or other
appropriate provisions, if any, as shall be required by GAAP
shall have been made in respect thereof;
(4) Liens for taxes, assessments or other governmental
charges or claims not yet subject to penalties for non-payment
or which are being contested in good faith by appropriate
proceedings; provided that appropriate reserves, if any,
required pursuant to GAAP have been made in respect thereof;
(5) Liens in favor of issuers of surety or performance
bonds or bankers acceptances issued pursuant to the
request of and for the account of such Person in the ordinary
course of its business;
(6) survey exceptions, encumbrances, ground leases,
easements or reservations of, or rights of others for, licenses,
rights of way, sewers, electric lines, telegraph and telephone
lines and other similar purposes, or zoning, building codes or
other restrictions (including, without limitation, minor defects
or irregularities in title and similar encumbrances) as to the
use of real properties or Liens incidental to the conduct of the
business of such Person or to the ownership of its properties
which do not in the aggregate materially adversely affect the
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value of the assets of such Person and its Restricted
Subsidiaries, taken as a whole, or materially impair their use
in the operation of the business of such Person;
(7) Liens securing Hedging Obligations;
(8) leases, licenses, subleases and sublicenses of assets
(including, without limitation, real property and intellectual
property rights) which do not materially interfere with the
ordinary conduct of the business of the Company or any of its
Restricted Subsidiaries;
(9) prejudgment Liens and judgment Liens not giving rise to
an Event of Default so long as such Lien is adequately bonded
and any appropriate legal proceedings which may have been duly
initiated for the review of such judgment have not been finally
terminated or the period within which such proceedings may be
initiated has not expired;
(10) Liens for the purpose of securing the payment of all
or a part of the purchase price of, or Capitalized Lease
Obligations, purchase money obligations or other payments
Incurred to finance the acquisition, lease, improvement or
construction of or repairs or additions to, assets or property
acquired or constructed in the ordinary course of business;
provided that:
(a) the aggregate principal amount of Indebtedness secured
by such Liens is otherwise permitted to be Incurred under the
Indenture and does not exceed the cost of the assets or property
so acquired or constructed; and
(b) such Liens are created within 180 days of the
later of the acquisition, lease, completion of improvements,
construction, repairs or additions or commencement of full
operation of the assets or property subject to such Lien and do
not encumber any other assets or property of the Company or any
Restricted Subsidiary other than such assets or property and
assets affixed or appurtenant thereto;
(11) Liens arising solely by virtue of any statutory or
common law provisions relating to bankers Liens, rights of
set-off or similar rights and remedies as to deposit accounts or
other funds maintained with a depositary institution;
provided that:
(a) such deposit account is not a dedicated cash collateral
account and is not subject to restrictions against access by the
Company in excess of those set forth by regulations promulgated
by the Federal Reserve Board; and
(b) such deposit account is not intended by the Company or
any Restricted Subsidiary to provide collateral to the
depository institution;
(12) Liens arising from Uniform Commercial Code financing
statement filings regarding operating leases entered into by the
Company and its Restricted Subsidiaries in the ordinary course
of business;
(13) Liens existing on the Issue Date;
(14) Liens on property or shares of Capital Stock of a
Person at the time such Person becomes a Subsidiary;
provided, however, that such Liens are not created
or Incurred in connection with, or in contemplation of, such
other Person becoming a Subsidiary; provided further,
however, that any such Lien may not extend to any other property
owned by the Company or any Restricted Subsidiary (other than
assets or property affixed or appurtenant thereto);
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(15) Liens on property at the time the Company or any of
its Subsidiaries acquired the property, including any
acquisition by means of a merger or consolidation with or into
the Company or any of its Subsidiaries; provided,
however, that such Liens are not created or Incurred in
connection with, or in contemplation of, such acquisition;
provided further, however, that such Liens may not
extend to any other property owned by the Company or any
Restricted Subsidiary (other than assets or property affixed or
appurtenant thereto);
(16) Liens securing the Notes, Subsidiary Guarantees and
other obligations under the Indenture;
(17) Liens securing Refinancing Indebtedness Incurred to
refinance Indebtedness that was previously so secured,
provided that any such Lien is limited to all or part of
the same property or assets (plus improvements, accessions,
proceeds or dividends or distributions in respect thereof) that
secured (or, under the written arrangements under which the
original Lien arose, could secure) the Indebtedness being
refinanced or is in respect of property or assets that is the
security for a Permitted Lien hereunder;
(18) any interest or title of a lessor under any
Capitalized Lease Obligation or operating lease;
(19) Liens in respect of Production Payments and Reserve
Sales, which Liens shall be limited to the property that is the
subject of such Production Payments and Reserve Sales;
(20) Liens arising under farm-out agreements, farm-in
agreements, division orders, contracts for the sale, purchase,
exchange, transportation, gathering or processing of
Hydrocarbons, unitizations and pooling designations,
declarations, orders and agreements, development agreements,
joint venture agreements, partnership agreements, operating
agreements, royalties, working interests, net profits interests,
joint interest billing arrangements, participation agreements,
production sales contracts, area of mutual interest agreements,
gas balancing or deferred production agreements, injection,
repressuring and recycling agreements, salt water or other
disposal agreements, seismic or geophysical permits or
agreements, and other agreements which are customary in the Oil
and Gas Business; provided, however, in all
instances that such Liens are limited to the assets that are the
subject of the relevant agreement, program, order or contract;
(21) Liens on pipelines or pipeline facilities that arise
by operation of law;
(22) Liens securing Indebtedness in an aggregate principal
amount outstanding at any one time, added together with all
other Indebtedness secured by Liens Incurred pursuant to this
clause (22), not to exceed the greater of $20.0 million and
1.0% of the Companys Adjusted Consolidated Net Tangible
Assets, as determined on the date of Incurrence of such
Indebtedness after giving pro forma effect to such Incurrence
and the application of the proceeds therefrom;
(23) Liens in favor of the Company or any Subsidiary
Guarantor;
(24) deposits made in the ordinary course of business to
secure liability to insurance carriers;
(25) Liens in favor of customs and revenue authorities
arising as a matter of law to secure payment of customs duties
in connection with the importation of goods in the ordinary
course of business;
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(26) Liens deemed to exist in connection with Investments
in repurchase agreements permitted under Certain
covenantsLimitation on Indebtedness and Preferred
Stock; provided that such Liens do not extend to
any assets other than those that are the subject of such
repurchase agreement;
(27) Liens encumbering reasonable customary initial
deposits and margin deposits and similar Liens attaching to
commodity trading accounts or other brokerage accounts incurred
in the ordinary course of business and not for speculative
purposes;
(28) any (a) interest or title of a lessor or
sublessor under any lease, liens reserved in oil, gas or other
Hydrocarbons, minerals, leases for bonus, royalty or rental
payments and for compliance with the terms of such leases;
(b) restriction or encumbrance that the interest or title
of such lessor or sublessor may be subject to (including,
without limitation, ground leases or other prior leases of the
demised premises, mortgages, mechanics liens, tax liens,
and easements); or (c) subordination of the interest of the
lessee or sublessee under such lease to any restrictions or
encumbrance referred to in the preceding clause (b);
(29) Liens upon specific items of inventory or other goods
and proceeds of any Person securing such Persons
obligations in respect of bankers acceptances issued or
created for the account of such Person to facilitate the
purchase, shipment or storage of such inventory or other goods;
(30) Liens arising under the Indenture in favor of the
Trustee for its own benefit and similar Liens in favor of other
trustees, agents and representatives arising under instruments
governing Indebtedness permitted to be incurred under the
Indenture, provided, however, that such Liens are
solely for the benefit of the trustees, agents or
representatives in their capacities as such and not for the
benefit of the holders of such Indebtedness;
(31) Liens arising from the deposit of funds or securities
in trust for the purpose of decreasing or defeasing Indebtedness
so long as such deposit of funds or securities and such
decreasing or defeasing of Indebtedness are permitted under the
covenant described under Certain
covenantsLimitation on Restricted Payments; and
(32) Liens in favor of collecting or payer banks having a
right of setoff, revocation, or charge back with respect to
money or instruments of the Company or any Subsidiary of the
Company on deposit with or in possession of such bank.
In each case set forth above, notwithstanding any stated
limitation on the assets that may be subject to such Lien, a
Permitted Lien on a specified asset or group or type of assets
may include Liens on all improvements, additions and accessions
thereto and all products and proceeds thereof (including
dividends, distributions and increases in respect thereof).
Person means any individual, corporation,
partnership, joint venture, association, joint-stock company,
trust, unincorporated organization, limited liability company,
government or any agency or political subdivision thereof or any
other entity.
Preferred Stock, as applied to the Capital
Stock of any corporation, means Capital Stock of any class or
classes (however designated) which is preferred as to the
payment of dividends, or as to the distribution of assets upon
any voluntary or involuntary liquidation or dissolution of such
corporation, over shares of Capital Stock of any other class of
such corporation.
Production Payments and Reserve Sales means
the grant or transfer by the Company or a Restricted Subsidiary
to any Person of a royalty, overriding royalty, net profits
interest,
S-171
production payment (whether volumetric or dollar denominated),
partnership or other interest in Oil and Gas Properties,
reserves or the right to receive all or a portion of the
production or the proceeds from the sale of production
attributable to such properties where the holder of such
interest has recourse solely to such production or proceeds of
production, subject to the obligation of the grantor or
transferor to operate and maintain, or cause the subject
interests to be operated and maintained, in a reasonably prudent
manner or other customary standard or subject to the obligation
of the grantor or transferor to indemnify for environmental,
title or other matters customary in the Oil and Gas Business,
including any such grants or transfers pursuant to incentive
compensation programs on terms that are reasonably customary in
the Oil and Gas Business for geologists, geophysicists or other
providers of technical services to the Company or a Restricted
Subsidiary.
Rating Agency means each of S&P and
Moodys, or if S&P or Moodys or both shall not
make a rating on the Notes publicly available, a nationally
recognized statistical rating agency or agencies, as the case
may be, selected by the Company (as certified by a resolution of
the Board of Directors) which shall be substituted for S&P
or Moodys, or both, as the case may be.
Refinancing Indebtedness means Indebtedness
that is Incurred to refund, refinance, replace, exchange, renew,
repay, extend, prepay, redeem or retire (including pursuant to
any defeasance or discharge mechanism) (collectively,
refinance and refinances and
refinanced shall have correlative meanings) any
Indebtedness (including Indebtedness of the Company that
refinances Indebtedness of any Restricted Subsidiary and
Indebtedness of any Restricted Subsidiary that refinances
Indebtedness of another Restricted Subsidiary, but excluding
Indebtedness of a Subsidiary that is not a Restricted Subsidiary
that refinances Indebtedness of the Company or a Restricted
Subsidiary), including Indebtedness that refinances Refinancing
Indebtedness, provided, however, that:
(1) (a) if the Stated Maturity of the Indebtedness
being Refinanced is earlier than the Stated Maturity of the
Notes, the Refinancing Indebtedness has a Stated Maturity no
earlier than the Stated Maturity of the Indebtedness being
refinanced or (b) if the Stated Maturity of the
Indebtedness being refinanced is later than the Stated Maturity
of the Notes, the Refinancing Indebtedness has a Stated Maturity
at least 91 days later than the Stated Maturity of the
Notes;
(2) the Refinancing Indebtedness has an Average Life at the
time such Refinancing Indebtedness is Incurred that is equal to
or greater than the Average Life of the Indebtedness being
refinanced;
(3) such Refinancing Indebtedness is Incurred in an
aggregate principal amount (or if issued with original issue
discount, an aggregate issue price) that is equal to or less
than the sum of the aggregate principal amount (or if issued
with original issue discount, the aggregate accreted value) then
outstanding of the Indebtedness being refinanced (plus, without
duplication, any additional Indebtedness Incurred to pay
interest, premiums or defeasance costs required by the
instruments governing such existing Indebtedness and fees and
expenses Incurred in connection therewith); and
(4) if the Indebtedness being Refinanced is subordinated in
right of payment to the Notes or the Subsidiary Guarantee, such
Refinancing Indebtedness is subordinated in right of payment to
the Notes or the Subsidiary Guarantee on terms at least as
favorable to the holders as those contained in the documentation
governing the Indebtedness being Refinanced.
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Reporting Failure means the failure of the
Company to file with the SEC and make available or otherwise
deliver to the Trustee and each holder of Notes, within the time
periods specified in Certain
covenantsProvision of financial information (after
giving effect to any grace period specified under
Rule 12b-25
under the Exchange Act), the periodic reports, information,
documents or other reports which the Company may be required to
file with the SEC pursuant to such provision.
Restricted Investment means any Investment
other than a Permitted Investment.
Restricted Subsidiary means any Subsidiary of
the Company other than an Unrestricted Subsidiary.
S&P means Standard & Poors
Rating Services, a division of The McGraw-Hill Companies, Inc.,
or any successor to the rating agency business thereof.
Sale/Leaseback Transaction means an
arrangement relating to property now owned or hereafter acquired
whereby the Company or a Restricted Subsidiary transfers such
property to a Person and the Company or a Restricted Subsidiary
leases it from such Person.
SEC means the United States Securities and
Exchange Commission.
Senior Secured Credit Agreement means the
Amended and Restated Credit Agreement dated as of July 31,
2008 among the Company, as Borrower, JPMorgan Chase Bank, N.A.,
as Administrative Agent, and the lenders parties thereto from
time to time, including any guarantees, collateral documents,
instruments and agreements executed in connection therewith, and
any amendments, supplements, modifications, extensions,
renewals, restatements, refundings or refinancings thereof and
any indentures or credit facilities or commercial paper
facilities with banks or other institutional lenders or
investors that replace, refund or refinance any part of the
loans, notes, other credit facilities or commitments thereunder,
including any such replacement, refunding or refinancing
facility or indenture that increases the amount borrowable
thereunder or alters the maturity thereof (provided that
such increase in borrowings is permitted under
Certain covenantsLimitation on Indebtedness
and Preferred Stock above).
Significant Subsidiary means any Restricted
Subsidiary that would be a Significant Subsidiary of
the Company within the meaning of
Rule 1-02
under
Regulation S-X
promulgated by the SEC, as in effect on the Issue Date.
Stated Maturity means, with respect to any
security, the date specified in such security as the fixed date
on which the payment of principal of such security is due and
payable, including pursuant to any mandatory redemption
provision, but shall not include any contingent obligations to
repay, redeem or repurchase any such principal prior to the date
originally scheduled for the payment thereof.
Subordinated Obligation means any
Indebtedness of the Company (whether outstanding on the Issue
Date or thereafter Incurred) which is expressly subordinate in
right of payment to the Notes pursuant to a written agreement.
Subsidiary of any Person means (a) any
corporation, association or other business entity (other than a
partnership, joint venture, limited liability company or similar
entity) of which more than 50% of the total ordinary voting
power of shares of Capital Stock entitled (without regard to the
occurrence of any contingency) to vote in the election of
directors, managers or trustees thereof (or Persons performing
similar functions) or (b) any partnership, joint venture,
limited liability company or similar entity of which more than
50% of the capital accounts, distribution
S-173
rights, total equity and voting interests or general or limited
partnership interests, as applicable, is, in the case of
clauses (a) and (b), at the time owned or controlled,
directly or indirectly, by (1) such Person, (2) such
Person and one or more Subsidiaries of such Person or
(3) one or more Subsidiaries of such Person. Unless
otherwise specified herein, each reference to a Subsidiary
(other than in this definition) will refer to a Subsidiary of
the Company.
Subsidiary Guarantee means, individually, any
Guarantee of payment of the Notes by a Subsidiary Guarantor
pursuant to the terms of the Indenture and any supplemental
indenture thereto, and, collectively, all such Guarantees.
Subsidiary Guarantors means any Subsidiary of
the Company that is a guarantor of the Notes, including any
Person that is required after the Issue Date to guarantee the
Notes pursuant to the Future subsidiary guarantors
covenant, in each case until a successor replaces such Person
pursuant to the applicable provisions of the Indenture and,
thereafter, means such successor.
Unrestricted Subsidiary means:
(1) any Subsidiary of the Company that at the time of
determination shall be designated an Unrestricted Subsidiary by
the Board of Directors of the Company in the manner provided
below; and
(2) any Subsidiary of an Unrestricted Subsidiary.
The Board of Directors of the Company may designate any
Subsidiary of the Company (including any newly acquired or newly
formed Subsidiary or a Person becoming a Subsidiary through
merger or consolidation or Investment therein) to be an
Unrestricted Subsidiary only if:
(1) such Subsidiary or any of its Subsidiaries does not own
any Capital Stock or Indebtedness of or have any Investment in,
or own or hold any Lien on any property of, any other Subsidiary
of the Company which is not a Subsidiary of the Subsidiary to be
so designated or otherwise an Unrestricted Subsidiary;
(2) all the Indebtedness of such Subsidiary and its
Subsidiaries shall, at the date of designation, and will at all
times thereafter, consist of Non-Recourse Debt;
(3) on the date of such designation, such designation and
the Investment of the Company or a Restricted Subsidiary in such
Subsidiary complies with Certain
covenantsLimitation on Restricted Payments;
(4) such Subsidiary is a Person with respect to which
neither the Company nor any of its Restricted Subsidiaries has
any direct or indirect obligation:
(a) to subscribe for additional Capital Stock of such
Person; or
(b) to maintain or preserve such Persons financial
condition or to cause such Person to achieve any specified
levels of operating results; and
(5) on the date such Subsidiary is designated an
Unrestricted Subsidiary, such Subsidiary is not a party to any
agreement, contract, arrangement or understanding with the
Company or any Restricted Subsidiary with terms substantially
less favorable to the Company or such Restricted Subsidiary than
those that might have been obtained from Persons who are not
Affiliates of the Company.
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Any such designation by the Board of Directors of the Company
shall be evidenced to the Trustee by filing with the Trustee a
resolution of the Board of Directors of the Company giving
effect to such designation and an Officers Certificate
certifying that such designation complies with the foregoing
conditions. If, at any time, any Unrestricted Subsidiary would
fail to meet the foregoing requirements as an Unrestricted
Subsidiary, it shall thereafter cease to be an Unrestricted
Subsidiary for purposes of the Indenture and any Indebtedness of
such Subsidiary shall be deemed to be Incurred as of such date.
The Board of Directors of the Company may designate any
Unrestricted Subsidiary to be a Restricted Subsidiary;
provided that immediately after giving effect to such
designation, no Default or Event of Default shall have occurred
and be continuing or would occur as a consequence thereof and
the Company could Incur at least $1.00 of additional
Indebtedness under the first paragraph of the covenant described
under Certain covenantsLimitation on
Indebtedness and Preferred Stock on a pro forma basis
taking into account such designation.
U.S. Government Obligations means
securities that are (a) direct obligations of the
United States of America for the timely payment of which
its full faith and credit is pledged or (b) obligations of
a Person controlled or supervised by and acting as an agency or
instrumentality of the United States of America the timely
payment of which is unconditionally guaranteed as a full faith
and credit obligation of the United States of America, which, in
either case, are not callable or redeemable at the option of the
issuer thereof, and shall also include a depositary receipt
issued by a bank (as defined in Section 3(a)(2) of the
Securities Act), as custodian with respect to any such
U.S. Government Obligations or a specific payment of
principal of or interest on any such U.S. Government
Obligations held by such custodian for the account of the holder
of such depositary receipt; provided that (except as
required by law) such custodian is not authorized to make any
deduction from the amount payable to the holder of such
depositary receipt from any amount received by the custodian in
respect of the U.S. Government Obligations or the specific
payment of principal of or interest on the U.S. Government
Obligations evidenced by such depositary receipt.
Volumetric Production Payments means
production payment obligations recorded as deferred revenue in
accordance with GAAP, together with all undertakings and
obligations in connection therewith.
Voting Stock of an entity means all classes
of Capital Stock of such entity then outstanding and normally
entitled to vote in the election of members of such
entitys Board of Directors.
Wholly-Owned Subsidiary means a Restricted
Subsidiary, all of the Capital Stock of which (other than
directors qualifying shares) is owned by the Company or
another Wholly-Owned Subsidiary.
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Book-entry,
delivery and form
We have obtained the information in this section concerning The
Depository Trust Company (DTC), Clearstream
Banking, S.A., Luxembourg (Clearstream, Luxembourg)
and Euroclear Bank S.A./N.V., as operator of the Euroclear
System (Euroclear), and their book-entry systems and
procedures from sources that we believe to be reliable. We take
no responsibility for an accurate portrayal of this information.
In addition, the description of the clearing systems in this
section reflects our understanding of the rules and procedures
of DTC, Clearstream, Luxembourg and Euroclear as they are
currently in effect. Those systems could change their rules and
procedures at any time.
The notes will initially be represented by one or more fully
registered global notes. Each such global note will be deposited
with, or on behalf of, DTC or any successor thereto and
registered in the name of Cede & Co. (DTCs
nominee). You may hold your interests in the global notes in the
United States through DTC, or in Europe through Clearstream,
Luxembourg or Euroclear, either as a participant in such systems
or indirectly through organizations which are participants in
such systems. Clearstream, Luxembourg and Euroclear will hold
interests in the global notes on behalf of their respective
participating organizations or customers through customers
securities accounts in Clearstream, Luxembourgs or
Euroclears names on the books of their respective
depositaries, which in turn will hold those positions in
customers securities accounts in the depositaries
names on the books of DTC. Citibank, N.A. will act as depositary
for Clearstream, Luxembourg and JPMorgan Chase Bank, N.A. will
act as depositary for Euroclear.
So long as DTC or its nominee is the registered owner of the
global securities representing the notes, DTC or such nominee
will be considered the sole owner and holder of the notes for
all purposes of the notes and the indenture. Except as provided
below, owners of beneficial interests in the notes will not be
entitled to have the notes registered in their names, will not
receive or be entitled to receive physical delivery of the notes
in definitive form and will not be considered the owners or
holders of the notes under the indenture, including for purposes
of receiving any reports delivered by us or the trustee pursuant
to the indenture. Accordingly, each person owning a beneficial
interest in a note must rely on the procedures of DTC or its
nominee and, if such person is not a participant, on the
procedures of the participant through which such person owns its
interest, in order to exercise any rights of a holder of notes.
Unless and until we issue the notes in fully certificated,
registered form under the limited circumstances described below
under the heading Certificated Notes:
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you will not be entitled to receive a certificate representing
your interest in the notes;
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all references in this prospectus supplement to actions by
holders will refer to actions taken by DTC upon instructions
from its direct participants; and
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all references in this prospectus supplement to payments and
notices to holders will refer to payments and notices to DTC or
Cede & Co., as the registered holder of the notes, for
distribution to you in accordance with DTC procedures.
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The Depository
Trust Company
DTC will act as securities depositary for the notes. The notes
will be issued as fully registered notes registered in the name
of Cede & Co. DTC is:
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a limited-purpose trust company organized under the New York
Banking Law;
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a banking organization under the New York Banking
Law;
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a member of the Federal Reserve System;
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a clearing corporation under the New York Uniform
Commercial Code; and
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a clearing agency registered under the provisions of
Section 17A of the Exchange Act.
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DTC holds securities that its direct participants deposit with
DTC. DTC facilitates the settlement among direct participants of
securities transactions, such as transfers and pledges, in
deposited securities through electronic computerized book-entry
changes in direct participants accounts, thereby
eliminating the need for physical movement of securities
certificates.
Direct participants of DTC include securities brokers and
dealers (including the underwriters), banks, trust companies,
clearing corporations and certain other organizations. DTC is
owned by a number of its direct participants. Indirect
participants of DTC, such as securities brokers and dealers,
banks and trust companies, can also access the DTC system if
they maintain a custodial relationship with a direct participant.
Purchases of notes under DTCs system must be made by or
through direct participants, which will receive a credit for the
notes on DTCs records. The ownership interest of each
beneficial owner is in turn to be recorded on the records of
direct participants and indirect participants. Beneficial owners
will not receive written confirmation from DTC of their
purchase, but beneficial owners are expected to receive written
confirmations providing details of the transaction, as well as
periodic statements of their holdings, from the direct
participants or indirect participants through which such
beneficial owners entered into the transaction. Transfers of
ownership interests in the notes are to be accomplished by
entries made on the books of participants acting on behalf of
beneficial owners. Beneficial owners will not receive
certificates representing their ownership interests in notes,
except as provided below in Certificated Notes.
To facilitate subsequent transfers, all notes deposited with DTC
are registered in the name of DTCs nominee,
Cede & Co. The deposit of notes with DTC and their
registration in the name of Cede & Co. effect no
change in beneficial ownership. DTC has no knowledge of the
actual beneficial owners of the notes. DTCs records
reflect only the identity of the direct participants to whose
accounts such notes are credited, which may or may not be the
beneficial owners. The participants will remain responsible for
keeping account of their holdings on behalf of their customers.
Conveyance of notices and other communications by DTC to direct
participants, by direct participants to indirect participants
and by direct participants and indirect participants to
beneficial owners will be governed by arrangements among them,
subject to any statutory or regulatory requirements as may be in
effect from time to time.
Book-entry
format
Under the book-entry format, the paying agent will pay interest
or principal payments to Cede & Co., as nominee of
DTC. DTC will forward the payment to the direct participants,
who will then forward the payment to the indirect participants
(including Clearstream, Luxembourg or Euroclear) or to you as
the beneficial owner. You may experience some delay in receiving
your payments under this system. None of us, any Subsidiary
Guarantor, the trustee under the indenture or any paying agent
has any direct responsibility or liability for the payment of
principal or interest on the notes to owners of beneficial
interests in the notes.
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DTC is required to make book-entry transfers on behalf of its
direct participants and is required to receive and transmit
payments of principal, premium, if any, and interest on the
notes. Any direct participant or indirect participant with which
you have an account is similarly required to make book-entry
transfers and to receive and transmit payments with respect to
the notes on your behalf. We, the Subsidiary Guarantors and the
trustee under the indenture have no responsibility for any
aspect of the actions of DTC, Clearstream, Luxembourg or
Euroclear or any of their direct or indirect participants. In
addition, we, the Subsidiary Guarantors and the trustee under
the indenture have no responsibility or liability for any aspect
of the records kept by DTC, Clearstream, Luxembourg, Euroclear
or any of their direct or indirect participants relating to or
payments made on account of beneficial ownership interests in
the notes or for maintaining, supervising or reviewing any
records relating to such beneficial ownership interests. We also
do not supervise these systems in any way.
The trustee will not recognize you as a holder under the
indenture, and you can only exercise the rights of a holder
indirectly through DTC and its direct participants. DTC has
advised us that it will only take action regarding a note if one
or more of the direct participants to whom the note is credited
direct DTC to take such action and only in respect of the
portion of the aggregate principal amount of the notes as to
which that participant or participants has or have given that
direction. DTC can only act on behalf of its direct
participants. Your ability to pledge notes to non-direct
participants, and to take other actions, may be limited because
you will not possess a physical certificate that represents your
notes.
Neither DTC nor Cede & Co. (nor any other DTC nominee)
will consent or vote with respect to the notes unless authorized
by a direct participant in accordance with DTCs
procedures. Under its usual procedures, DTC will mail an omnibus
proxy to its direct participant as soon as possible after the
record date. The omnibus proxy assigns Cede &
Co.s consenting or voting rights to those direct
participants to whose accounts the notes are credited on the
record date (identified in a listing attached to the omnibus
proxy).
Clearstream, Luxembourg or Euroclear will credit payments to the
cash accounts of Clearstream, Luxembourg customers or Euroclear
participants in accordance with the relevant systems rules
and procedures, to the extent received by its depositary. These
payments will be subject to tax reporting in accordance with
relevant United States tax laws and regulations. Clearstream,
Luxembourg or Euroclear, as the case may be, will take any other
action permitted to be taken by a holder under the indenture on
behalf of a Clearstream, Luxembourg customer or Euroclear
participant only in accordance with its relevant rules and
procedures and subject to its depositarys ability to
effect those actions on its behalf through DTC.
DTC, Clearstream, Luxembourg and Euroclear have agreed to the
foregoing procedures in order to facilitate transfers of the
notes among participants of DTC, Clearstream, Luxembourg and
Euroclear. However, they are under no obligation to perform or
continue to perform those procedures, and they may discontinue
those procedures at any time.
Transfers within
and among book-entry systems
Transfers between DTCs direct participants will occur in
accordance with DTC rules. Transfers between Clearstream,
Luxembourg customers and Euroclear participants will occur in
accordance with their respective applicable rules and operating
procedures.
DTC will effect cross-market transfers between persons holding
directly or indirectly through DTC, on the one hand, and
directly or indirectly through Clearstream, Luxembourg customers
or
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Euroclear participants, on the other hand, in accordance with
DTC rules on behalf of the relevant European international
clearing system by its depositary. However, cross-market
transactions will require delivery of instructions to the
relevant European international clearing system by the
counterparty in that system in accordance with its rules and
procedures and within its established deadlines (European time).
The relevant European international clearing system will, if the
transaction meets its settlement requirements, instruct its
depositary to effect final settlement on its behalf by
delivering or receiving securities in DTC and making or
receiving payment in accordance with normal procedures for
same-day
funds settlement applicable to DTC. Clearstream, Luxembourg
customers and Euroclear participants may not deliver
instructions directly to the depositaries.
Because of time-zone differences, credits of securities received
in Clearstream, Luxembourg or Euroclear resulting from a
transaction with a DTC direct participant will be made during
the subsequent securities settlement processing, dated the
business day following the DTC settlement date. Those credits or
any transactions in those securities settled during that
processing will be reported to the relevant Clearstream,
Luxembourg customer or Euroclear participant on that business
day. Cash received in Clearstream, Luxembourg or Euroclear as a
result of sales of securities by or through a Clearstream,
Luxembourg customer or a Euroclear participant to a DTC direct
participant will be received with value on the DTC settlement
date but will be available in the relevant Clearstream,
Luxembourg or Euroclear cash amount only as of the business day
following settlement in DTC.
Although DTC, Clearstream, Luxembourg and Euroclear have agreed
to the foregoing procedures in order to facilitate transfers of
debt securities among their respective participants, they are
under no obligation to perform or continue to perform such
procedures and such procedures may be discontinued at any time.
Certificated
Notes
Unless and until they are exchanged, in whole or in part, for
notes in definitive form in accordance with the terms of the
notes, the notes may not be transferred except (1) as a
whole by DTC to a nominee of DTC or (2) by a nominee of DTC
to DTC or another nominee of DTC or (3) by DTC or any such
nominee to a successor of DTC or a nominee of such successor.
We will issue notes to you or your nominees, in fully
certificated registered form, rather than to DTC or its
nominees, only if:
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we advise the trustee in writing that DTC is no longer willing
or able to discharge its responsibilities properly or that DTC
is no longer a registered clearing agency under the Exchange
Act, and we have not appointed a qualified successor within
90 days;
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an event of default has occurred and is continuing under the
indenture and DTC has notified us and the trustee of its desire
to exchange the global notes for certificated notes; or
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subject to DTCs rules, we, at our option, elect to
terminate the book-entry system through DTC.
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If any of the three above events occurs, DTC is required to
notify all direct participants that notes in fully certificated
registered form are available through DTC. DTC will then
surrender the global note representing the notes along with
instructions for re-registration. We will re-issue the notes in
fully certificated registered form and will recognize the
registered holders of the certificated notes as holders under
the indenture.
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Unless and until we issue the notes in fully certificated,
registered form, (1) you will not be entitled to receive a
certificate representing your interest in the notes;
(2) all references in this prospectus supplement to actions
by holders will refer to actions taken by the depositary upon
instructions from its direct participants; and (3) all
references in this prospectus supplement to payments and notices
to holders will refer to payments and notices to the depositary
or its nominee, as the registered holder of the notes, for
distribution to you in accordance with its policies and
procedures.
Same day
settlement and payment
We will make payments in respect of the notes represented by the
global notes (including principal, premium, if any, and
interest) by wire transfer of immediately available funds to the
accounts specified by DTC or its nominee. We will make all
payments of principal, interest and premium, if any, with
respect to certificated notes by wire transfer of immediately
available funds to the accounts specified by the holders of the
certificated notes or, if no such account is specified, by
mailing a check to each such holders registered address.
The notes represented by the global notes are expected to be
eligible to trade in DTCs
Same-Day
Funds Settlement System, and any permitted secondary market
trading activity in such notes will, therefore, be required by
DTC to be settled in immediately available funds. We expect that
secondary trading in any certificated notes will also be settled
in immediately available funds.
Because of time zone differences, the securities account of a
Clearstream, Luxembourg customer or Euroclear participant
purchasing an interest in a global note from another customer or
participant will be credited, and any such crediting will be
reported to the relevant Clearstream, Luxembourg customer or
Euroclear participant, during the securities settlement
processing day (which must be a business day for Euroclear and
Clearstream) immediately following the settlement date of DTC.
DTC has advised us that cash received in Clearstream, Luxembourg
or Euroclear as a result of sales of interests in a global note
by or through a Clearstream, Luxembourg customer or Euroclear
participant to another customer or participant will be received
with value on the settlement date of DTC but will be available
in the relevant Clearstream, Luxembourg or Euroclear cash
account only as of the business day for Euroclear or
Clearstream, Luxembourg following DTCs settlement date.
S-180
United States
federal income and estate tax consequences
The following discussion summarizes certain U.S. federal
income tax considerations and, in the case of a
non-U.S. holder
(as defined below), U.S. federal estate tax considerations,
that may be relevant to the acquisition, ownership and
disposition of the notes. This discussion is based upon the
provisions of the Internal Revenue Code of 1986, as amended (the
Code), applicable U.S. Treasury Regulations
promulgated thereunder, judicial authority and administrative
interpretations, as of the date of this document, all of which
are subject to change, possibly with retroactive effect, or are
subject to different interpretations. We cannot assure you that
the Internal Revenue Service, or IRS, will not challenge one or
more of the tax consequences described in this discussion, and
we have not obtained, nor do we intend to obtain, a ruling from
the IRS or an opinion of counsel with respect to the
U.S. federal tax consequences of acquiring, holding or
disposing of the notes.
This discussion is limited to holders who purchase the notes in
this offering for a price equal to the issue price of the notes
(i.e., the first price at which a substantial amount of the
notes is sold other than to bond houses, brokers or similar
persons or organizations acting in the capacity of underwriters,
placement agents or wholesalers) and who hold the notes as
capital assets (generally, property held for investment). This
discussion does not address the tax considerations arising under
the laws of any foreign, state, local or other jurisdiction. In
addition, this discussion does not address all tax
considerations that may be important to a particular holder in
light of the holders circumstances, or to certain
categories of investors that may be subject to special rules,
such as:
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dealers in securities or currencies;
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traders in securities that have elected the
mark-to-market
method of accounting for their securities;
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U.S. holders (as defined below) whose functional currency
is not the U.S. dollar;
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persons holding notes as part of a hedge, straddle, conversion
or other synthetic security or integrated
transaction;
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certain U.S. expatriates;
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financial institutions;
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insurance companies;
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regulated investment companies;
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real estate investment trusts;
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persons subject to the alternative minimum tax;
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entities that are tax-exempt for U.S. federal income tax
purposes; and
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partnerships and other pass-through entities and holders of
interests therein.
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If a partnership (or an entity treated as a partnership for
U.S. federal income tax purposes) holds notes, the tax
treatment of a partner generally will depend upon the status of
the partner and the activities of the partnership. If you are a
partner of a partnership acquiring the notes, you
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are urged to consult your own tax advisor about the
U.S. federal income tax consequences of acquiring, holding
and disposing of the notes.
INVESTORS CONSIDERING THE PURCHASE OF NOTES ARE URGED TO
CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE
U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS
AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP OR
DISPOSITION OF THE NOTES UNDER U.S. FEDERAL ESTATE OR
GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL OR FOREIGN
JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.
In certain circumstances (see Description of
notesOptional redemption and Change of
control), we may be obligated to pay amounts on the notes
that are in excess of stated interest or principal on the notes.
We do not intend to treat the possibility of paying such
additional amounts as causing the notes to be treated as
contingent payment debt instruments. However, additional income
will be recognized if any such additional payment is made. It is
possible that the IRS may take a different position, in which
case a holder might be required to accrue interest income at a
higher rate than the stated interest rate and to treat as
ordinary interest income any gain realized on the taxable
disposition of the note. The remainder of this discussion
assumes that the notes will not be treated as contingent payment
debt instruments. Investors should consult their own tax
advisors regarding the possible application of the contingent
payment debt instrument rules to the notes.
Tax consequences
to U.S. holders
You are a U.S. holder for purposes of this
discussion if you are a beneficial owner of a note and you are
for U.S. federal income tax purposes:
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an individual who is a U.S. citizen or U.S. resident
alien;
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a corporation, or other entity taxable as a corporation for
U.S. federal income tax purposes, that was created or
organized in or under the laws of the United States, any state
thereof or the District of Columbia;
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an estate whose income is subject to U.S. federal income
taxation regardless of its source; or
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a trust if a court within the United States is able to exercise
primary supervision over the administration of the trust and one
or more United States persons have the authority to control all
substantial decisions of the trust, or that has a valid election
in effect under applicable U.S. Treasury Regulations to be
treated as a United States person.
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Stated interest
on the notes
Stated interest on the notes generally will be taxable to you as
ordinary income at the time it is received or accrued in
accordance with your regular method of accounting for United
States federal income tax purposes.
Disposition of
the notes
You will generally recognize capital gain or loss on the sale,
redemption, exchange, retirement or other taxable disposition of
a note. This gain or loss will equal the difference between the
proceeds you receive (excluding any proceeds attributable to
accrued but unpaid stated interest,
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which will be recognized as ordinary interest income to the
extent you have not previously included such amounts in income)
and your adjusted tax basis in the note. The proceeds you
receive will include the amount of any cash and the fair market
value of any other property received for the note. Your adjusted
tax basis in the note will generally equal the amount you paid
for the note. The gain or loss will be long-term capital gain or
loss if you held the note for more than one year at the time of
the sale, redemption, exchange, retirement or other disposition.
Long-term capital gains of individuals, estates and trusts
generally are subject to a reduced rate of U.S. federal
income tax. The deductibility of capital losses may be subject
to limitation.
Information
reporting and backup withholding
Information reporting generally will apply to payments of
principal and interest on, and the proceeds of the sale or other
disposition (including a retirement or redemption) of, notes
held by you unless, in each case, you are an exempt recipient
such as a corporation. Backup withholding may apply to such
payments unless you provide the appropriate intermediary with a
taxpayer identification number, certified under penalties of
perjury, as well as certain other information. Backup
withholding is not an additional tax. Any amount withheld under
the backup withholding rules is allowable as a credit against
your U.S. federal income tax liability, if any, and a
refund may be obtained if the amounts withheld exceed your
actual U.S. federal income tax liability and you timely
provide the required information or appropriate claim form to
the IRS.
Tax consequences
to non-U.S.
holders
Except as otherwise modified for U.S. federal estate tax
purposes, you are a
non-U.S. holder
for purposes of this discussion if you are a beneficial owner of
notes that is an individual, corporation, estate or trust and is
not a U.S. holder.
Interest on the
notes
Payments to you of interest on the notes generally will be
exempt from U.S. federal withholding tax under the
portfolio interest exemption if you properly certify
as to your foreign status as described below, and:
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you do not own, actually or constructively, 10% or more of the
total combined voting power of all classes of our stock entitled
to vote;
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you are not a controlled foreign corporation that is
related to us (actually or constructively);
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you are not a bank whose receipt of interest on the notes is in
connection with an extension of credit made pursuant to a loan
agreement entered into in the ordinary course of your trade or
business; and
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interest on the notes is not effectively connected with your
conduct of a U.S. trade or business.
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The portfolio interest exemption and several of the special
rules for
non-U.S. holders
described below generally apply only if you appropriately
certify as to your foreign status. You can generally meet this
certification requirement by providing a properly executed IRS
Form W-8BEN
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or appropriate substitute form to us, or our paying agent. If
you hold the notes through a financial institution or other
agent acting on your behalf, you may be required to provide
appropriate certifications to the agent. Your agent will then
generally be required to provide appropriate certifications to
us or our paying agent, either directly or through other
intermediaries. Special rules apply to foreign partnerships,
estates and trusts, and in certain circumstances certifications
as to foreign status of partners, trust owners or beneficiaries
may have to be provided to us or our paying agent. In addition,
special rules apply to qualified intermediaries that enter into
withholding agreements with the IRS.
If you cannot satisfy the requirements described above, payments
of interest made to you will be subject to U.S. federal
withholding tax at a 30% rate, unless you provide us or our
paying agent with a properly executed IRS
Form W-8BEN
(or successor form) claiming an exemption from (or a reduction
of) withholding under the benefit of a tax treaty (in which
case, you generally will be required to provide a
U.S. taxpayer identification number), or the payments of
interest are effectively connected with your conduct of a trade
or business in the United States (and if required by an
applicable income tax treaty, are treated as attributable to a
permanent establishment maintained by you in the United States)
and you meet the certification requirements described below.
(See Income or gain effectively connected with a
U.S. trade or business.)
Disposition of
notes
You generally will not be subject to U.S. federal income
tax on any gain realized on the sale, redemption, exchange,
retirement or other taxable disposition of a note unless:
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the gain is effectively connected with the conduct by you of a
U.S. trade or business (and, if required by an applicable
income tax treaty, is treated as attributable to a permanent
establishment maintained by you in the United States); or
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you are an individual who has been present in the United States
for 183 days or more in the taxable year of disposition and
certain other requirements are met.
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If you are a
non-U.S. holder
described in the first bullet point above, you generally will be
subject to U.S. federal income tax in the manner described
under Income or gain effectively connected with a
U.S. trade or business. If you are a
non-U.S. holder
described in the second bullet point above, you will be subject
to a flat 30% U.S. federal income tax on the gain derived
from the sale or other disposition, which may be offset by
U.S. source capital losses.
Income or gain
effectively connected with a U.S. trade or business
If any interest on the notes or gain from the sale, exchange or
other taxable disposition of the notes is effectively connected
with a U.S. trade or business conducted by you (and, if
required by an applicable income tax treaty, is treated as
attributable to a permanent establishment in the United States),
then the income or gain will be subject to U.S. federal
income tax at regular graduated income tax rates in generally
the same manner as if you were a U.S. holder. Effectively
connected interest income will not be subject to
U.S. withholding tax if you satisfy certain certification
requirements by providing to us or our paying agent a properly
executed IRS
Form W-8ECI
(or successor form). If you are a corporation, that portion of
your earnings and profits that is effectively connected with
your U.S. trade or business may also be subject to a
branch profits tax at a 30% rate, although an
applicable income tax treaty may provide for a lower rate.
S-184
Information
reporting and backup withholding
Payments to you of interest on a note, and amounts withheld from
such payments, if any, generally will be required to be reported
to the IRS and to you.
United States backup withholding generally will not apply to
payments to you of interest on a note if the certification
requirements described in Tax consequences to
non-U.S. holdersInterest
on the notes are met or you otherwise establish an
exemption, provided that we do not have actual knowledge or
reason to know that you are a United States person.
Payment of the proceeds of a disposition (including a retirement
or redemption) of a note effected by the U.S. office of a
U.S. or foreign broker will be subject to information
reporting requirements and backup withholding unless you
properly certify under penalties of perjury as to your foreign
status and certain other conditions are met or you otherwise
establish an exemption. Information reporting requirements and
backup withholding generally will not apply to any payment of
the proceeds of the disposition of a note effected outside the
United States by a foreign office of a broker. However, unless
such a broker has documentary evidence in its records that you
are a
non-U.S. holder
and certain other conditions are met, or you otherwise establish
an exemption, information reporting will apply to a payment of
the proceeds of the disposition of a note effected outside the
United States by such a broker if it:
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is a United States person;
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is a foreign person that derives 50% or more of its gross income
for certain periods from the conduct of a trade or business in
the United States;
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is a controlled foreign corporation for U.S. federal income
tax purposes; or
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is a foreign partnership that, at any time during its taxable
year, has more than 50% of its income or capital interests owned
by United States persons or is engaged in the conduct of a
U.S. trade or business.
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Backup withholding is not an additional tax. Any amount withheld
under the backup withholding rules is allowable as a credit
against your U.S. federal income tax liability, if any, and
a refund may be obtained if the amounts withheld exceed your
actual U.S. federal income tax liability and you timely
provide the required information or appropriate claim form to
the IRS.
U.S. federal
estate tax
If you are an individual and are not a resident of the United
States (as specially defined for U.S. federal estate tax
purposes) at the time of your death, the notes will not be
included in your estate for U.S. federal estate tax
purposes provided, at the time of your death, interest on the
notes qualifies for the portfolio interest exemption under the
rules described above without regard to the certification
requirement.
THE PRECEDING DISCUSSION OF CERTAIN U.S. FEDERAL INCOME
AND ESTATE TAX CONSIDERATIONS IS FOR GENERAL INFORMATION ONLY
AND IS NOT TAX ADVICE. WE URGE EACH PROSPECTIVE INVESTOR TO
CONSULT ITS OWN TAX ADVISOR REGARDING THE PARTICULAR FEDERAL,
STATE, LOCAL AND FOREIGN TAX CONSEQUENCES OF PURCHASING, HOLDING
AND DISPOSING OF OUR NOTES, INCLUDING THE CONSEQUENCES OF ANY
PROPOSED CHANGE IN APPLICABLE LAWS.
S-185
Certain ERISA
considerations
The following is a summary of certain considerations associated
with the purchase of the notes by employee benefit plans that
are subject to Title I of the U.S. Employee Retirement
Income Security Act of 1974, as amended (ERISA),
plans, individual retirement accounts and other arrangements
that are subject to Section 4975 of the Code or provisions
under any other federal, state, local,
non-U.S. or
other laws or regulations that are similar to such provisions of
ERISA or the Code (collectively, Similar Laws), and
entities whose underlying assets are considered to include
plan assets of any such plan, account or arrangement
(each, a Plan).
General fiduciary
matters
ERISA and the Code impose certain duties on persons who are
fiduciaries of a Plan subject to Title I of ERISA or
Section 4975 of the Code (an ERISA Plan) and
prohibit certain transactions involving the assets of an ERISA
Plan and its fiduciaries or other interested parties. Under
ERISA and the Code, any person who exercises any discretionary
authority or control over the administration of such an ERISA
Plan or the management or disposition of the assets of such an
ERISA Plan, or who renders investment advice for a fee or other
compensation to such an ERISA Plan, is generally considered to
be a fiduciary of the ERISA Plan.
In considering an investment in the notes of a portion of the
assets of any Plan, a fiduciary should determine whether the
investment is in accordance with the documents and instruments
governing the Plan and the applicable provisions of ERISA, the
Code or any Similar Law relating to a fiduciarys duties to
the Plan including, without limitation, the prudence,
diversification, delegation of control and prohibited
transaction provisions of ERISA, the Code and any other
applicable Similar Laws.
Prohibited
transaction issues
Section 406 of ERISA and Section 4975 of the Code
prohibit ERISA Plans from engaging in specified transactions
involving plan assets with persons or entities who are
parties in interest, within the meaning of ERISA, or
disqualified persons, within the meaning of
Section 4975 of the Code, unless an exemption is available.
A party in interest or disqualified person who engaged in a
non-exempt prohibited transaction may be subject to excise taxes
and other penalties and liabilities under ERISA and the Code. In
addition, the fiduciary of the ERISA Plan that engaged in such a
non-exempt prohibited transaction may be subject to penalties
and liabilities under ERISA and the Code. The acquisition
and/or
holding of notes by an ERISA Plan with respect to which we, an
underwriter, or a guarantor is considered a party in interest or
a disqualified person may constitute or result in a direct or
indirect prohibited transaction under Section 406 of ERISA
and/or
Section 4975 of the Code, unless the investment is acquired
and is held in accordance with an applicable statutory, class or
individual prohibited transaction exemption. In this regard, the
U.S. Department of Labor has issued prohibited transaction
class exemptions, or PTCEs, that may apply to the
acquisition and holding of the notes. These class exemptions
include, without limitation,
PTCE 84-14
respecting transactions determined by independent qualified
professional asset managers,
PTCE 90-1
respecting insurance company pooled separate accounts,
PTCE 91-38
respecting bank collective investment funds,
PTCE 95-60
respecting life insurance company general accounts and
PTCE 96-23
respecting transactions determined by in-house asset managers.
In addition, Section 408(b)(17) of ERISA and
Section 4975(d)(20) of the Code provide relief from the
prohibited transaction provisions of ERISA and Section 4975
of
S-186
the Code for certain transactions, provided that neither the
issuer of the securities nor any of its affiliates (directly or
indirectly) have or exercise any discretionary authority or
control or render any investment advice with respect to the
assets of any ERISA Plan involved in the transaction and
provided further that the ERISA Plan pays no more than adequate
consideration in connection with the transaction. There can be
no assurance that all of the conditions of any such exemptions
will be satisfied.
Because of the foregoing, the notes should not be purchased or
held by any person investing plan assets of any
Plan, unless such purchase and holding will not constitute a
non-exempt prohibited transaction under ERISA and the Code or a
similar violation of any applicable Similar Law.
Representation
Accordingly, by acceptance of a note, each purchaser and
subsequent transferee of a note will be deemed to have
represented and warranted that either (i) no portion of the
assets used by such purchaser or transferee to acquire or hold
the notes constitutes assets of any Plan or (ii) the
purchase and holding of the notes by such purchaser or
transferee will not constitute a non-exempt prohibited
transaction under Section 406 of ERISA or Section 4975
of the Code or a similar violation under any applicable Similar
Law.
The foregoing discussion is general in nature and is not
intended to be all inclusive. Due to the complexity of these
rules and the penalties that may be imposed upon persons
involved in non-exempt prohibited transactions, it is
particularly important that fiduciaries or other persons
considering purchasing the notes on behalf of, or with the
assets of, any Plan, consult with their counsel regarding the
potential applicability of ERISA, Section 4975 of the Code
and any Similar Laws to such investment and whether an exemption
would be applicable to the purchase and holding of the notes.
S-187
Underwriting
Subject to the terms and conditions stated in the underwriting
agreement among us, the guarantors and J.P. Morgan Securities
Inc., on behalf of the several underwriters, we have agreed to
sell to each underwriter and each underwriter named below has
severally agreed to purchase from us, the principal amount of
notes that appears opposite its name in the table below.
|
|
|
|
|
|
|
Underwriter
|
|
Principal amount
|
|
|
|
|
J.P. Morgan Securities Inc.
|
|
$
|
120,000,000
|
|
Banc of America Securities LLC
|
|
|
45,000,000
|
|
BNP Paribas Securities Corp.
|
|
|
30,000,000
|
|
Wells Fargo Securities, LLC
|
|
|
30,000,000
|
|
Calyon Securities (USA) Inc.
|
|
|
15,000,000
|
|
Scotia Capital (USA) Inc.
|
|
|
15,000,000
|
|
SunTrust Robinson Humphrey, Inc.
|
|
|
15,000,000
|
|
Deutsche Bank Securities Inc.
|
|
|
5,001,000
|
|
ING Financial Markets LLC
|
|
|
5,001,000
|
|
KeyBanc Capital Markets Inc.
|
|
|
5,001,000
|
|
Mitsubishi UFJ Securities (USA), Inc.
|
|
|
5,001,000
|
|
Natixis Bleichroeder Inc.
|
|
|
5,001,000
|
|
Raymond James & Associates, Inc.
|
|
|
4,995,000
|
|
|
|
|
|
|
Total
|
|
$
|
300,000,000
|
|
|
|
The underwriters have agreed to purchase all of the notes if any
of them are purchased. The underwriting agreement provides that
the obligations of the underwriters to purchase the notes
included in this offering are subject to, among other customary
conditions, the delivery of certain legal opinions by their
counsel. The underwriting agreement also provides that if an
underwriter defaults, the purchase commitments of non-defaulting
underwriters may also be increased or the offering may be
terminated.
The underwriters initially propose to offer the notes to the
public at the public offering price that appears on the cover
page of this prospectus supplement. The underwriters may offer
the notes to selected dealers at the public offering price minus
a concession of up to 0.375% of the principal amount. In
addition, the underwriters may allow, and those selected dealers
may reallow, a concession of up to 0.25% of the principal amount
to certain other dealers. After the initial offering, the
underwriters may change the public offering price and any other
selling terms. The underwriters may offer and sell notes through
certain of their affiliates.
In the underwriting agreement, we have agreed that:
|
|
|
we will not offer or sell any of our debt securities (other than
the notes) for a period of 45 days after the date of this
prospectus supplement without the prior consent of
J.P. Morgan Securities Inc.; and
|
S-188
|
|
|
we will indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act, or contribute to
payments that the underwriters may be required to make in
respect of those liabilities.
|
The notes are new issues of securities with no established
trading market. We do not intend to apply for the notes to be
listed on any securities exchange or to arrange for the notes to
be quoted on any quotation system. The underwriters have advised
us that they intend to make a market in the notes. However, they
are not obligated to do so and they may discontinue any market
making at any time in their sole discretion. Therefore, we
cannot assure you that a liquid trading market will develop for
the notes, that you will be able to sell your notes at a
particular time or that the prices that you receive when you
sell will be favorable.
In relation to each Member State of the European Economic Area
which has implemented the Prospectus Directive (each, a
Relevant Member State), with effect from and
including the date on which the Prospectus Directive is
implemented in that Relevant Member State (the Relevant
Implementation Date), each underwriter has not made and
will not make an offer of notes to the public in that Relevant
Member State prior to the publication of a prospectus in
relation to the notes which has been approved by the competent
authority in that Relevant Member State or, where appropriate,
approved in another Relevant Member State and notified to the
competent authority in that Relevant Member State, all in
accordance with the Prospectus Directive, except that it may,
with effect from and including the Relevant Implementation Date,
make an offer of notes to the public in that Relevant Member
State at any time:
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|
|
to legal entities which are authorized or regulated to operate
in the financial markets or, if not so authorized or regulated,
whose corporate purpose is solely to invest in securities;
|
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|
to any legal entity which has two or more of (1) an average
of at least 250 employees during the last financial year;
(2) a total balance sheet of more than 43,000,000;
and (3) an annual net turnover of more than
50,000,000, as shown in its last annual or consolidated
accounts; or
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in any other circumstances which do not require the publication
by us of a prospectus pursuant to Article 3 of the
Prospectus Directive.
|
For the purposes of this provision, the expression an
offer of notes to the public in relation to any
notes in any Relevant Member State means the communication in
any form and by any means of sufficient information on the terms
of the offer and the notes to be offered so as to enable an
investor to decide to purchase or subscribe the notes, as the
same may be varied in that Member State by any measure
implementing the Prospectus Directive in that Member State and
the expression Prospectus Directive means Directive
2003/71/EC and includes any relevant implementing measure in
each Relevant Member State.
This prospectus is only being distributed to, and is only
directed at, persons in the United Kingdom that are qualified
investors within the meaning of Article 2(1)(e) of the
Prospectus Directive (Qualified Investors) that are
also (i) investment professionals falling within
Article 19(5) of the Financial Services and Markets Act
2000 (Financial Promotion) Order 2005 (the Order) or
(ii) high net worth entities, and other persons to whom it
may lawfully be communicated, falling within
Article 49(2)(a) to (d) of the Order (all such persons
together being referred to as relevant persons).
This prospectus and its contents are confidential and should not
be distributed, published or reproduced (in whole or in part) or
disclosed by recipients to
S-189
any other persons in the United Kingdom. Any person in the
United Kingdom that is not a relevant person should not act or
rely on this document or any of its contents.
In connection with this offering of the notes, the underwriters
may engage in overallotments, stabilizing transactions and
syndicate covering transactions in accordance with
Regulation M under the Exchange Act. Overallotment involves
sales in excess of the offering size, which creates a short
position for the underwriter. Stabilizing transactions involve
bids to purchase the notes in the open market for the purpose of
pegging, fixing or maintaining the price of the notes, as
applicable. Syndicate covering transactions involve purchases of
the notes in the open market after the distribution has been
completed in order to cover short positions. Stabilizing
transactions and syndicate covering transactions may cause the
price of the notes to be higher than it would otherwise be in
the absence of those transactions. If any of the underwriters
engages in stabilizing or syndicate covering transactions, it
may discontinue them at any time.
We estimate that our total expenses of this offering, excluding
underwriting discounts and commissions, will be approximately
$1.25 million.
Conflicts of
interest
For a discussion of certain conflicts of interest involving the
underwriters, see Conflicts of interest.
S-190
Conflicts of
interest
Certain of the underwriters and their affiliates have in the
past provided, and may in the future provide, investment
banking, commercial banking, derivative transactions and
financial advisory services to us and our affiliates in the
ordinary course of business. Specifically, affiliates of the
underwriters serve various roles in our credit facility;
JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan
Securities Inc., serves as administrative agent, a lender, L/C
issuer and swing line lender; Bank of America, N.A., an
affiliate of Banc of America Securities LLC, serves as
syndication agent and a lender; BNP Paribas, an affiliate of BNP
Paribas Securities Corp., serves as co-documentation agent and a
lender; Wachovia Bank, National Association, and Wells Fargo
Bank, National Association, affiliates of Wells Fargo
Securities, LLC, serve as lenders; Calyon New York Branch, an
affiliate of Calyon Securities (USA) Inc., serves as
co-documentation agent and a lender; Scotiabanc Inc., an
affiliate of Scotia Capital (USA) Inc., serves as a lender;
SunTrust Bank, an affiliate of SunTrust Robinson Humphrey, Inc.,
serves as a lender; Deutsche Bank Trust Company Americas,
an affiliate of Deutsche Bank Securities Inc., serves as a
lender; ING Capital LLC, an affiliate of ING Financial Markets
LLC, serves as co-documentation agent and a lender; KeyBank
National Association, an affiliate of KeyBanc Capital Markets
Inc., serves as a lender; Union Bank, N.A., an affiliate of
Mitsubishi UFJ Securities (USA), Inc., serves as a lender; and
Natixis, an affiliate of Natixis Bleichroeder Inc., serves as a
lender.
Wells Fargo Bank, National Association, an affiliate of Wells
Fargo Securities, LLC, will serve as the trustee for the
indenture governing the notes.
We intend to use at least 5% of the net proceeds of this
offering to repay indebtedness owed by us to certain affiliates
of the underwriters who are lenders under our credit facility.
See Use of proceeds. Accordingly, this offering is
being made in compliance with the requirements of NASD Conduct
Rule 2720 of the Financial Industry Regulatory Authority.
This rule provides that if at least 5% of the net proceeds from
the sale of debt securities, not including underwriting
compensation, are used to reduce or retire the balance of a loan
or credit facility extended by the underwriters or their
affiliates, a qualified independent underwriter
meeting certain standards must participate in the preparation of
the registration statement and the prospectus and exercise the
usual standards of due diligence with respect thereto. Raymond
James & Associates, Inc. is assuming the
responsibilities of acting as the qualified independent
underwriter in connection with this offering. J.P. Morgan
Securities Inc., Banc of America Securities LLC, BNP Paribas
Securities Corp. and Wells Fargo Securities, LLC will not
confirm sales of the debt securities to any account over which
they exercise discretionary authority without the prior written
approval of the customer.
S-191
Legal
matters
Certain legal matters in connection with the notes will be
passed upon by Vinson & Elkins L.L.P., Houston, Texas,
as our counsel. Certain legal matters will be passed upon for
the underwriters by Simpson Thacher & Bartlett LLP,
New York, New York.
Experts
The consolidated financial statements and managements
assessment of the effectiveness of internal control over
financial reporting incorporated in this prospectus supplement
by reference to the Annual Report on
Form 10-K
for the year ended December 31, 2008 have been so
incorporated by reference in reliance upon the reports of Grant
Thornton LLP, independent registered public accountants, upon
the authority of said firm as experts in auditing and accounting
in giving said reports.
Certain estimates of our net oil and natural gas reserves and
related information included or incorporated by reference in
this prospectus supplement have been derived from reports
prepared by Cawley, Gillespie & Associates, Inc. and
Netherland, Sewell & Associates, Inc. All such
information has been so included or incorporated by reference on
the authority of such firms as experts regarding the matters
contained in their reports.
S-192
Glossary of oil
and natural gas terms
Bbl. One stock tank barrel, of 42 U.S. gallons
liquid volume, used herein in reference to oil, condensate or
natural gas liquids.
Boe. One barrel of oil equivalent, a standard
convention used to express oil and natural gas volumes on a
comparable oil equivalent basis. Natural gas equivalents are
determined under the relative energy content method by using the
ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or
condensate.
Bcfe. One billion cubic feet of natural gas
equivalent using the ratio of one barrel of oil, condensate or
natural gas liquids to six Mcf of natural gas.
Basin. A large natural depression on the
earths surface in which sediments accumulate.
Development wells. Wells drilled within the proved
area of an oil or gas reservoir to the depth of a stratigraphic
horizon known to be productive.
Dry hole. A well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from
the sale of such production would exceed production expenses,
taxes and the royalty burden.
Exploitation. A drilling or other project which may
target proven or unproven reserves (such as probable or possible
reserves), but which generally is reasonably expected to have
lower risk.
Exploratory wells. Wells drilled to find and produce
oil or gas in an unproved area, to find a new reservoir in a
field previously found to be productive of oil or gas in another
reservoir, or to extend a known reservoir.
Field. An area consisting of a single reservoir or
multiple reservoirs all grouped on, or related to, the same
individual geological structural feature or stratigraphic
condition. The field name refers to the surface area, although
it may refer to both the surface and the underground productive
formations.
Gross wells. The number of wells in which a working
interest is owned.
Horizontal drilling. A drilling technique used in
certain formations where a well is drilled vertically to a
certain depth and then drilled at a high angle to vertical
(which can be greater than 90 degrees) in order to stay within a
specified interval.
Infill wells. Wells drilled into the same pool as
known producing wells so that oil or natural gas does not have
to travel as far through the formation.
LIBOR. London Interbank Offered Rate, which is a
market rate of interest.
MBbl. One thousand barrels of oil, condensate or
natural gas liquids.
MBoe. One thousand Boe.
Mcf. One thousand cubic feet of natural gas.
MMBbl. One million barrels of oil, condensate or
natural gas liquids.
MMBoe. One million Boe.
MMBtu. One million British thermal units.
G-1
MMcf. One million cubic feet of natural gas.
NYMEX. The New York Mercantile Exchange.
NYSE. The New York Stock Exchange.
Net acres. The percentage of total acres an owner
owns out of a particular number of acres within a specified
tract. For example, an owner who has a 50 percent interest
in 100 acres owns 50 net acres.
Net revenue interest. A working interest
owners gross working interest in production, less the
related royalty, overriding royalty, production payment, and net
profits interests.
Net wells. The total of fractional working interests
owned in gross wells.
PV-10. When
used with respect to oil and natural gas reserves,
PV-10 means
the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and
future development and abandonment costs, using prices and costs
in effect at the determination date, before income taxes, and
without giving effect to non-property-related expenses except
for specific general and administrative expenses incurred to
operate the properties, discounted to a present value using an
annual discount rate of 10 percent.
Primary recovery. The period of production in which
oil and natural gas is produced from its reservoir through the
wellbore without enhanced recovery technologies, such as water
flooding or gas injection.
Productive wells. Wells that produce commercial
quantities of hydrocarbons, exclusive of their capacity to
produce at a reasonable rate of return.
Proved developed reserves. Has the meaning given to
such term in
Rule 4-10(a)(3)
of
Regulation S-X,
which defines proved developed reserves as:
Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as
proved developed reserves only after testing by a pilot project
or after the operation of an installed program has confirmed
through production response that increased recovery will be
achieved.
Proved reserves. Has the meaning given to such term
in
Rule 4-10(a)(2)
of
Regulation S-X,
which defines proved reserves as:
Proved oil and gas reserves are the estimated quantities of oil,
natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future
conditions.
(i) Reservoirs are considered proved if economic
producibility is supported by either actual production or
conclusive formation test. The area of a reservoir considered
proved includes (a) that portion delineated by drilling and
defined by gas-oil
and/or
oil-water contacts, if any, and (b) the immediately
adjoining portions not yet drilled, but which
G-2
can be reasonably judged as economically productive on the basis
of available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of
the reservoir.
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the proved classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the
following: (a) oil that may become available from known
reservoirs but is classified separately as indicated additional
reserves; (b) oil, natural gas, and natural gas liquids,
the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or
economic factors; (c) oil, natural gas, and natural gas
liquids, that may occur in undrilled prospects; and
(d) oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such
sources.
Proved undeveloped reserves. Has the meaning given
to such term in
Rule 4-10(a)(4)
of
Regulation S-X,
which defines proved undeveloped reserves as:
Proved undeveloped oil and gas reserves are reserves that are
expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage shall
be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves
be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
Recompletion. The addition of production from
another interval or formation in an existing wellbore.
Reservoir. A formation beneath the surface of the
earth from which hydrocarbons may be present. Its
make-up is
sufficiently homogenous to differentiate it from other
formations.
SEC. The United States Securities and Exchange
Commission.
Secondary recovery. The recovery of oil and gas
through the injection of liquids or gases into the reservoir,
supplementing its natural energy. Secondary recovery methods are
often applied when production slows due to depletion of the
natural pressure.
Seismic survey. Also known as a seismograph survey,
is a survey of an area by means of an instrument which records
the travel time of the vibrations of the earth. By recording the
time interval between the source of the shock wave and the
reflected or refracted shock waves from various formations,
geophysicists are better able to define the underground
configurations.
Spacing. The distance between wells producing from
the same reservoir. Spacing is expressed in terms of acres,
e.g.,
40-acre
spacing, and is established by regulatory agencies.
G-3
Standardized measure. The present value (discounted
at an annual rate of 10%) of estimated future net revenues to be
generated from the production of proved reserves net of
estimated income taxes associated with such net revenues, as
determined in accordance with Statement of Financial Accounting
Standards No. 69 (using prices and costs in effect as of
the period end date) without giving effect to non-property
related expenses such as indirect general and administrative
expenses, and debt service or to depreciation, depletion and
amortization. Standardized measure does not give effect to
derivative transactions.
Step-out drilling. The drilling of a well adjacent
to existing production in an effort to expand the aerial extent
of a known producing field.
Undeveloped acreage. Acreage owned or leased on
which wells can be drilled or completed to a point that would
permit the production of commercial quantities of oil and
natural gas regardless of whether such acreage contains proved
reserves.
Unit. The joining of all or substantially all
interests in a reservoir or field, rather than single tracts, to
provide for development and operation without regard to separate
property interests. Also, the area covered by a unitization
agreement.
Wellbore. The hole drilled by the bit that is
equipped for oil or gas production on a completed well. Also
called a well or borehole.
Working interest. The right granted to the lessee of
a property to explore for and to produce and own oil, gas, or
other minerals. The working interest owners bear the
exploration, development, and operating costs on either a cash,
penalty, or carried basis.
Workover. Operations on a producing well to restore
or increase production.
G-4
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|
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|
|
Unaudited consolidated financial statements:
|
|
|
|
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
Audited consolidated financial statements:
|
|
|
|
|
|
|
|
F-40
|
|
|
|
|
F-41
|
|
|
|
|
F-42
|
|
|
|
|
F-43
|
|
|
|
|
F-44
|
|
|
|
|
F-45
|
|
|
|
|
F-90
|
|
F-1
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
(in thousands, except share and
per share data)
|
|
2009
|
|
|
2008
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,081
|
|
|
$
|
17,752
|
|
Accounts receivable, net of allowance for doubtful accounts:
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
|
58,430
|
|
|
|
48,793
|
|
Joint operations and other
|
|
|
73,992
|
|
|
|
92,833
|
|
Related parties
|
|
|
174
|
|
|
|
314
|
|
Derivative instruments
|
|
|
26,272
|
|
|
|
113,149
|
|
Prepaid costs and other
|
|
|
5,330
|
|
|
|
5,942
|
|
|
|
|
|
|
|
Total current assets
|
|
|
167,279
|
|
|
|
278,783
|
|
|
|
|
|
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
2,885,275
|
|
|
|
2,693,574
|
|
Accumulated depletion
|
|
|
(413,252
|
)
|
|
|
(306,990
|
)
|
|
|
|
|
|
|
Total oil and natural gas properties, net
|
|
|
2,472,023
|
|
|
|
2,386,584
|
|
Other property and equipment, net
|
|
|
15,143
|
|
|
|
14,820
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
2,487,166
|
|
|
|
2,401,404
|
|
|
|
|
|
|
|
Deferred loan costs, net
|
|
|
13,988
|
|
|
|
15,701
|
|
Inventory
|
|
|
27,158
|
|
|
|
19,956
|
|
Intangible asset, netoperating rights
|
|
|
37,319
|
|
|
|
37,768
|
|
Noncurrent derivative instruments
|
|
|
31,438
|
|
|
|
61,157
|
|
Other assets
|
|
|
451
|
|
|
|
434
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,764,799
|
|
|
$
|
2,815,203
|
|
|
|
|
|
|
|
Liabilities and stockholders equity
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
15,837
|
|
|
$
|
7,462
|
|
Related parties
|
|
|
1,352
|
|
|
|
312
|
|
Other current liabilities:
|
|
|
|
|
|
|
|
|
Bank overdrafts
|
|
|
2,628
|
|
|
|
9,434
|
|
Revenue payable
|
|
|
31,262
|
|
|
|
22,286
|
|
Accrued and prepaid drilling costs
|
|
|
111,172
|
|
|
|
154,196
|
|
Derivative instruments
|
|
|
15,731
|
|
|
|
1,866
|
|
Deferred income taxes
|
|
|
3,300
|
|
|
|
37,205
|
|
Other current liabilities
|
|
|
38,149
|
|
|
|
38,057
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
219,431
|
|
|
|
270,818
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
660,000
|
|
|
|
630,000
|
|
Noncurrent derivative instruments
|
|
|
17,656
|
|
|
|
|
|
Deferred income taxes
|
|
|
565,217
|
|
|
|
573,763
|
|
Asset retirement obligations and other long-term liabilities
|
|
|
12,940
|
|
|
|
15,468
|
|
Commitments and contingencies (Note K)
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; 300,000,000 authorized;
85,529,591 and 84,828,824 shares issued at June 30,
2009 and December 31, 2008, respectively
|
|
|
86
|
|
|
|
85
|
|
Additional paid-in capital
|
|
|
1,020,060
|
|
|
|
1,009,025
|
|
Retained earnings
|
|
|
269,726
|
|
|
|
316,169
|
|
Treasury stock, at cost; 9,341 and 3,142 shares at
June 30, 2009 and December 31, 2008, respectively
|
|
|
(317
|
)
|
|
|
(125
|
)
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,289,555
|
|
|
|
1,325,154
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
2,764,799
|
|
|
$
|
2,815,203
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
Six months ended June 30,
|
|
(in thousands, except per share
amounts)
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
101,511
|
|
|
$
|
95,408
|
|
|
$
|
166,485
|
|
|
$
|
171,226
|
|
Natural gas sales
|
|
|
25,821
|
|
|
|
41,975
|
|
|
|
46,849
|
|
|
|
72,868
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
127,332
|
|
|
|
137,383
|
|
|
|
213,334
|
|
|
|
244,094
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
|
25,817
|
|
|
|
21,979
|
|
|
|
50,583
|
|
|
|
38,874
|
|
Exploration and abandonments
|
|
|
1,424
|
|
|
|
723
|
|
|
|
7,419
|
|
|
|
3,464
|
|
Depreciation, depletion and amortization
|
|
|
52,402
|
|
|
|
22,010
|
|
|
|
103,150
|
|
|
|
43,294
|
|
Accretion of discount on asset retirement obligations
|
|
|
301
|
|
|
|
148
|
|
|
|
579
|
|
|
|
301
|
|
Impairments of long-lived assets
|
|
|
4,499
|
|
|
|
53
|
|
|
|
8,555
|
|
|
|
69
|
|
General and administrative (including non-cash stock-based
compensation of $2,188 and $1,730 for the three months ended
June 30, 2009 and 2008, respectively, and $4,113 and $3,029
for the six months ended June 30, 2009 and 2008,
respectively)
|
|
|
14,172
|
|
|
|
8,586
|
|
|
|
25,918
|
|
|
|
16,266
|
|
Bad debt expense
|
|
|
|
|
|
|
1,799
|
|
|
|
|
|
|
|
1,799
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
(356
|
)
|
|
|
|
|
|
|
(920
|
)
|
Loss on derivatives not designated as hedges
|
|
|
81,606
|
|
|
|
102,456
|
|
|
|
86,652
|
|
|
|
119,634
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
180,221
|
|
|
|
157,398
|
|
|
|
282,856
|
|
|
|
222,781
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(52,889
|
)
|
|
|
(20,015
|
)
|
|
|
(69,522
|
)
|
|
|
21,313
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(6,200
|
)
|
|
|
(3,885
|
)
|
|
|
(10,570
|
)
|
|
|
(9,500
|
)
|
Other, net
|
|
|
180
|
|
|
|
311
|
|
|
|
(148
|
)
|
|
|
1,331
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(6,020
|
)
|
|
|
(3,574
|
)
|
|
|
(10,718
|
)
|
|
|
(8,169
|
)
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(58,909
|
)
|
|
|
(23,589
|
)
|
|
|
(80,240
|
)
|
|
|
13,144
|
|
Income tax (expense) benefit
|
|
|
25,691
|
|
|
|
9,169
|
|
|
|
33,797
|
|
|
|
(5,199
|
)
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(33,218
|
)
|
|
$
|
(14,420
|
)
|
|
$
|
(46,443
|
)
|
|
$
|
7,945
|
|
|
|
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
$
|
(0.39
|
)
|
|
$
|
(0.19
|
)
|
|
$
|
(0.55
|
)
|
|
$
|
0.11
|
|
|
|
|
|
|
|
Weighted average shares used in basic earnings per share
|
|
|
84,799
|
|
|
|
75,665
|
|
|
|
84,665
|
|
|
|
75,569
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
$
|
(0.39
|
)
|
|
$
|
(0.19
|
)
|
|
$
|
(0.55
|
)
|
|
$
|
0.10
|
|
|
|
|
|
|
|
Weighted average shares used in diluted earnings per share
|
|
|
84,799
|
|
|
|
75,665
|
|
|
|
84,665
|
|
|
|
77,034
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Common stock
|
|
|
paid-in
|
|
|
Retained
|
|
|
Treasury stock
|
|
|
stockholders
|
|
(in thousands)
|
|
Shares
|
|
|
Amount
|
|
|
capital
|
|
|
earnings
|
|
|
Shares
|
|
|
Amount
|
|
|
equity
|
|
|
|
|
Balance at December 31, 2008
|
|
|
84,829
|
|
|
$
|
85
|
|
|
$
|
1,009,025
|
|
|
$
|
316,169
|
|
|
|
3
|
|
|
$
|
(125
|
)
|
|
$
|
1,325,154
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(46,443
|
)
|
|
|
|
|
|
|
|
|
|
|
(46,443
|
)
|
Stock options exercise
|
|
|
446
|
|
|
|
1
|
|
|
|
3,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,931
|
|
Stock-based compensation for restricted stock
|
|
|
257
|
|
|
|
|
|
|
|
2,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,200
|
|
Cancellation of restricted stock
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
1,913
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,913
|
|
Excess tax benefits related to stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
2,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,992
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
(192
|
)
|
|
|
(192
|
)
|
|
|
|
|
|
|
Balance at June 30, 2009
|
|
|
85,530
|
|
|
$
|
86
|
|
|
$
|
1,020,060
|
|
|
$
|
269,726
|
|
|
|
9
|
|
|
$
|
(317
|
)
|
|
$
|
1,289,555
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-4
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
(in thousands)
|
|
2009
|
|
|
2008
|
|
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(46,443
|
)
|
|
$
|
7,945
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
103,150
|
|
|
|
43,294
|
|
Impairments of long-lived assets
|
|
|
8,555
|
|
|
|
69
|
|
Accretion of discount on asset retirement obligations
|
|
|
579
|
|
|
|
301
|
|
Exploration expense, including dry holes
|
|
|
6,294
|
|
|
|
1,147
|
|
Non-cash compensation expense
|
|
|
4,113
|
|
|
|
3,029
|
|
Bad debt expense
|
|
|
|
|
|
|
1,799
|
|
Deferred income taxes
|
|
|
(39,799
|
)
|
|
|
4,504
|
|
(Gain) loss on sale of assets
|
|
|
191
|
|
|
|
(777
|
)
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
(920
|
)
|
Loss on derivatives not designated as hedges
|
|
|
86,652
|
|
|
|
119,634
|
|
Dedesignated cash flow hedges reclassified from accumulated
other comprehensive income
|
|
|
|
|
|
|
222
|
|
Other non-cash items
|
|
|
1,686
|
|
|
|
558
|
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(18,401
|
)
|
|
|
(12,003
|
)
|
Prepaid costs and other
|
|
|
612
|
|
|
|
793
|
|
Inventory
|
|
|
(6,786
|
)
|
|
|
(7,243
|
)
|
Accounts payable
|
|
|
9,415
|
|
|
|
(10,209
|
)
|
Revenue payable
|
|
|
8,976
|
|
|
|
7,718
|
|
Other current liabilities
|
|
|
(562
|
)
|
|
|
3,087
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
118,232
|
|
|
|
162,948
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Capital expenditures on oil and natural gas properties
|
|
|
(223,283
|
)
|
|
|
(122,757
|
)
|
Additions to other property and equipment
|
|
|
(2,014
|
)
|
|
|
(4,017
|
)
|
Proceeds from the sale of oil and natural gas properties and
other assets
|
|
|
1,004
|
|
|
|
1,034
|
|
Settlements received (paid) on derivatives not designated as
hedges
|
|
|
61,465
|
|
|
|
(16,387
|
)
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(162,828
|
)
|
|
|
(142,127
|
)
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
211,650
|
|
|
|
13,000
|
|
Payments of long-term debt
|
|
|
(181,650
|
)
|
|
|
(39,500
|
)
|
Exercise of stock options
|
|
|
3,931
|
|
|
|
2,373
|
|
Excess tax benefit from stock-based compensation
|
|
|
2,992
|
|
|
|
2,146
|
|
Proceeds from repayment of employee notes
|
|
|
|
|
|
|
333
|
|
Payments for loan origination costs
|
|
|
|
|
|
|
(1,001
|
)
|
Purchase of treasury stock
|
|
|
(192
|
)
|
|
|
(125
|
)
|
Bank overdrafts
|
|
|
(6,806
|
)
|
|
|
3,245
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
29,925
|
|
|
|
(19,529
|
)
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(14,671
|
)
|
|
|
1,292
|
|
Cash and cash equivalents at beginning of period
|
|
|
17,752
|
|
|
|
30,424
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
3,081
|
|
|
$
|
31,716
|
|
|
|
|
|
|
|
Supplemental cash flows:
|
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $18 and $840 capitalized
interest
|
|
$
|
6,911
|
|
|
$
|
9,918
|
|
Cash paid for income taxes
|
|
$
|
4,232
|
|
|
$
|
650
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-5
|
|
Note A.
|
Organization
and nature of operations
|
Concho Resources Inc. (the Company) is a Delaware
corporation formed on February 22, 2006. The Companys
principal business is the acquisition, development, exploitation
and exploration of oil and natural gas properties in the Permian
Basin region of Southeast New Mexico and West Texas.
|
|
Note B.
|
Summary of
significant accounting policies
|
Principles of consolidation. The consolidated
financial statements of the Company include the accounts of the
Company and its wholly-owned subsidiaries. All material
intercompany balances and transactions have been eliminated.
Use of estimates in the preparation of financial
statements. Preparation of financial statements in
conformity with generally accepted accounting principles in the
United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting periods. Actual
results could differ from these estimates. Depletion of oil and
natural gas properties are determined using estimates of proved
oil and natural gas reserves. There are numerous uncertainties
inherent in the estimation of quantities of proved reserves and
in the projection of future rates of production and the timing
of development expenditures. Similarly, evaluations for
impairment of proved and unproved oil and natural gas properties
are subject to numerous uncertainties including, among others,
estimates of future recoverable reserves and commodity price
outlooks. Other significant estimates include, but are not
limited to, asset retirement obligations, fair value of
derivative financial instruments, purchase price allocations for
business and oil and natural gas property acquisitions and fair
value of stock-based compensation.
Interim financial statements. The accompanying
consolidated financial statements of the Company have not been
audited by the Companys independent registered public
accounting firm, except that the consolidated balance sheet at
December 31, 2008 is derived from audited consolidated
financial statements. In the opinion of management, the
accompanying consolidated financial statements reflect all
adjustments necessary to present fairly the Companys
financial position at June 30, 2009, its results of
operations for the three and six months ended June 30, 2009
and 2008, and its cash flows for the six months ended
June 30, 2009 and 2008. All such adjustments are of a
normal recurring nature. In preparing the accompanying
consolidated financial statements, management has made certain
estimates and assumptions that affect reported amounts in the
consolidated financial statements and disclosures of
contingencies. Actual results may differ from those estimates.
The results for interim periods are not necessarily indicative
of annual results.
Certain disclosures have been condensed or omitted from these
consolidated financial statements. Accordingly, these
consolidated financial statements should be read with the
audited
F-6
consolidated financial statements and notes thereto included in
the Companys Annual Report on
Form 10-K
for the year ended December 31, 2008.
Deferred loan costs. Deferred loan costs are stated
at cost, net of amortization, which is computed using the
effective interest and straight-line methods. The Company had
deferred loan costs of $14.0 million and
$15.7 million, net of accumulated amortization of
$6.6 million and $4.9 million, at June 30, 2009
and December 31, 2008, respectively.
Future amortization expense of deferred loan costs at
June 30, 2009 is as follows (in thousands):
|
|
|
|
|
Remaining 2009
|
|
$
|
1,713
|
|
2010
|
|
|
3,426
|
|
2011
|
|
|
3,426
|
|
2012
|
|
|
3,426
|
|
2013
|
|
|
1,997
|
|
|
|
|
|
|
Total
|
|
$
|
13,988
|
|
|
|
Intangible assets. The Company has capitalized
certain operating rights acquired in an acquisition, see
Note D. The gross operating rights of approximately
$38.7 million, which have no residual value, are amortized
over the estimated economic life of approximately 25 years.
Impairment will be assessed if indicators of potential
impairment exist or when there is a material change in the
remaining useful economic life. Amortization expense for the
three and six months ended June 30, 2009 was approximately
$0.4 million and $0.8 million, respectively. The
following table reflects the estimated aggregate amortization
expense at June 30, 2009 for each of the periods presented
below (in thousands):
|
|
|
|
|
Remaining 2009
|
|
$
|
775
|
|
2010
|
|
|
1,550
|
|
2011
|
|
|
1,550
|
|
2012
|
|
|
1,550
|
|
2013
|
|
|
1,550
|
|
Thereafter
|
|
|
30,344
|
|
|
|
|
|
|
Total
|
|
$
|
37,319
|
|
|
|
Oil and natural gas sales and imbalances. Oil and
natural gas revenues are recorded at the time of delivery of
such products to pipelines for the account of the purchaser or
at the time of physical transfer of such products to the
purchaser. The Company follows the sales method of accounting
for oil and natural gas sales, recognizing revenues based on the
Companys share of actual proceeds from the oil and natural
gas sold to purchasers. Oil and natural gas imbalances are
generated on properties for which two or more owners have the
right to take production in-kind and, in doing so,
take more or less than their respective entitled percentage.
Imbalances are tracked by well, but the Company does not record
any receivable from or payable to the other owners unless the
imbalance has reached a level at which it exceeds the remaining
reserves in the respective well. If reserves are insufficient to
offset the imbalance and the Company is in an overtake position,
a liability is recorded for the amount of shortfall in reserves
valued at a contract price or the market price in effect at the
time the imbalance is generated. If the Company is in an
undertake position, a receivable is recorded for an amount
F-7
that is reasonably expected to be received, not to exceed the
current market value of such imbalance.
The following table reflects the Companys natural gas
imbalance positions at June 30, 2009 and December 31,
2008 as well as amounts reflected in oil and natural gas
production expense for the three and six months ended
June 30, 2009 and 2008 ($ in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Natural gas imbalance receivable (included in other assets)
|
|
$
|
423
|
|
|
$
|
406
|
|
Undertake position (Mcf)
|
|
|
(94,102
|
)
|
|
|
(90,321
|
)
|
Natural gas imbalance liability (included in asset retirement
obligations and other long-term liabilities)
|
|
$
|
449
|
|
|
$
|
472
|
|
Overtake position (Mcf)
|
|
|
79,408
|
|
|
|
85,698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months
|
|
|
|
Three months ended June 30,
|
|
|
ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Value of net overtake (undertake) arising during the period
(increasing (reducing) oil and natural gas production expense)
|
|
$
|
9
|
|
|
$
|
(133
|
)
|
|
$
|
(40
|
)
|
|
$
|
(137
|
)
|
Net overtake (undertake) position arising during the period (Mcf)
|
|
|
1,697
|
|
|
|
(9,117
|
)
|
|
|
(10,069
|
)
|
|
|
(8,103
|
)
|
|
|
Treasury stock. Treasury stock purchases are
recorded at cost. Upon reissuance, the cost of treasury shares
held is reduced by the average purchase price per share of the
aggregate treasury shares held.
General and administrative expense. The Company
receives fees for the operation of jointly owned oil and natural
gas properties and records such reimbursements as reductions of
general and administrative expense. Such fees totaled
approximately $2.8 million and $0.3 million for the
three months ended June 30, 2009 and 2008, respectively,
and $5.4 million and $0.5 million for the six months
ended June 30, 2009 and 2008, respectively.
Reclassifications. Certain prior period amounts have
been reclassified to conform to the 2009 presentation. These
reclassifications had no impact on net income (loss), total
stockholders equity or cash flows.
Recent accounting pronouncements. In December 2007,
the Financial Accounting Standards Board (FASB)
issued SFAS No. 141(R), Business Combinations
(SFAS No. 141(R)), which replaces FASB
Statement No. 141. SFAS No. 141(R) establishes
principles and requirements for how an acquirer recognizes and
measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any non-controlling interest
in the acquiree and the goodwill acquired.
SFAS No. 141(R) also establishes disclosure
requirements that will enable users to evaluate the nature and
financial effects of the business combination.
SFAS No. 141(R) is effective for acquisitions that
occur in an entitys fiscal year that begins after
December 15, 2008. The Company adopted
SFAS No. 141(R) effective January 1, 2009. There
has been no impact on the Companys consolidated financial
statements, as it has not entered into any significant business
combinations during 2009.
F-8
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statementsan amendment of ARB No. 51
(SFAS No. 160). SFAS No. 160
requires that accounting and reporting for minority interests
will be recharacterized as noncontrolling interests and
classified as a component of equity. SFAS No. 160 also
establishes reporting requirements that provide sufficient
disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the noncontrolling
owners. SFAS No. 160 applies to all entities that
prepare consolidated financial statements, except
not-for-profit
organizations, but will affect only those entities that have an
outstanding noncontrolling interest in one or more subsidiaries
or that deconsolidate a subsidiary. This statement is effective
as of the beginning of an entitys first fiscal year
beginning after December 15, 2008. The Company adopted
SFAS No. 160 effective January 1, 2009, with no
impact on the Companys consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities (SFAS No. 161) ,
which amends and expands the interim and annual disclosure
requirements of SFAS No. 133 to provide an enhanced
understanding of an entitys use of derivative instruments,
how they are accounted for under SFAS No. 133 and
their effect on the entitys financial position, financial
performance and cash flows. The provisions of
SFAS No. 161 are effective as of January 1, 2009.
The Company adopted SFAS No. 161 effective
January 1, 2009, with no significant impact on the
Companys consolidated financial statements, other than
additional disclosures which are set forth below in Notes H
and I.
In April 2008, the FASB issued FASB Staff Position
(FSP)
No. SFAS 142-3,
Determination of the Useful Life of Intangible Assets
(FSP
SFAS No. 142-3).
FSP
SFAS No. 142-3
amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under
SFAS No. 142, Goodwill and Other Intangible Assets
(SFAS No. 142). The intent of FSP
SFAS No. 142-3
is to improve the consistency between the useful life of a
recognized intangible asset under SFAS No. 142 and the
period of expected cash flows used to measure the fair value of
the asset under SFAS No. 141R and other applicable
accounting literature. FSP
SFAS No. 142-3
is effective for financial statements issued for fiscal years
beginning after December 15, 2008 and must be applied
prospectively to intangible assets acquired after the effective
date. The Company adopted FSP
SFAS No. 142-3
effective January 1, 2009, with no significant impact on
the Companys consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162, The
Hierarchy of Generally Accepted Accounting Principles
(SFAS No. 162), which identifies the
sources of accounting principles and the framework for selecting
the principles used in the preparation of financial statements
of nongovernmental entities that are presented in conformity
with generally accepted accounting principles (GAAP)
in the United States of America. SFAS No. 162 arranges
these sources of GAAP in a hierarchy for users to apply
accordingly. This statement became effective for the Company on
November 15, 2008. The adoption of SFAS No. 162
did not have a significant impact on the Companys
consolidated financial statements. In June 2009, this statement
was replaced with SFAS No. 168, The FASB Accounting
Standards
Codificationtm
(Codification) and the Hierarchy of Generally
Accepted Accounting Principles
(SFAS No. 168). Once the Codification
is in effect, all of its content will carry the same level of
authority, effectively superseding SFAS No. 162. In
other words, the GAAP hierarchy will be modified to include only
two levels of GAAP: authoritative and non authoritative.
SFAS No. 168 is effective for financial statements
issued for interim and annual periods ending after
September 15, 2009. The Company does not expect the
adoption of SFAS No. 168 to have an impact on its
consolidated financial statements.
F-9
In June 2008, the FASB issued FSP
No. EITF 03-6-1,
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities ,
(FSP
EITF 03-6-1)
which provides that unvested share-based payment awards that
contain non-forfeitable rights to dividends or dividend
equivalents (whether paid or unpaid) are participating
securities and, therefore, need to be included in the earnings
allocation in computing earnings per share under the two class
method. FSP
EITF 03-6-1
was effective for the Company on January 1, 2009. There was
no impact on the Companys consolidated financial
statements.
In April 2009, the FASB issued FSP SFAS No. 141(R)-1,
Accounting for Assets Acquired and Liabilities Assumed in a
Business Combination That Arise from Contingencies. This FSP
amends and clarifies SFAS No. 141(R) to address
application issues raised by preparers, auditors, and members of
the legal profession on initial recognition and measurement,
subsequent measurement and accounting, and disclosure of assets
and liabilities arising from contingencies in a business
combination. This FSP is effective for assets or liabilities
arising from contingencies in business combinations for which
the acquisition date is on or after the beginning of the first
annual reporting period beginning on or after December 15,
2008. The Company has not made any acquisitions during 2009, and
as such, the adoption of this statement on January 1, 2009
did not have a significant impact.
In April 2009, the FASB issued FSP
SFAS No. 107-1
and APB Opinion
No. 28-1,
Interim Disclosures about Fair Value of Financial Instrument
(FSP
SFAS No. 107-1).
This FSP amends FASB Statement No. 107, Disclosures
about Fair Value of Financial Instruments, to require
disclosures about fair value of financial instruments for
interim reporting periods of publicly traded companies as well
as in annual financial statements. This FSP also amends APB
Opinion No. 28, Interim Financial Reporting, to
require those disclosures in summarized financial information at
interim reporting periods. This FSP is effective for interim
reporting periods ending after June 15, 2009. This FSP does
not require disclosures for earlier periods presented for
comparative purposes at initial adoption. In periods after
initial adoption, this FSP requires comparative disclosures only
for periods ending after initial adoption. As of June 15,
2009, the Company adopted the provisions of FSP
SFAS No. 107-1
related to the fair value of financial instruments. The adoption
of the provisions of FSP
SFAS No. 107-1
did not have a material effect on the financial condition or
results of operations of the Company. See Note H for
additional disclosures required by FSP
SFAS No. 107-1.
In April 2009, the FASB issued FSP
SFAS No. 157-4,
Determining Fair Value When the Volume and Level of Activity for
the Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly (FSP
SFAS No. 157-4).
This FSP:
|
|
|
Affirms that the objective of fair value when the market for an
asset is not active is the price that would be received to sell
the asset in an orderly transaction;
|
|
|
Clarifies and includes additional factors for determining
whether there has been a significant decrease in market activity
for an asset when the market for that asset is not active;
|
|
|
Eliminates the proposed presumption that all transactions are
distressed (not orderly) unless proven otherwise. The FSP
instead requires an entity to base its conclusion about whether
a transaction was not orderly on the weight of the evidence;
|
|
|
Includes an example that provides additional explanation on
estimating fair value when the market activity for an asset has
declined significantly;
|
F-10
|
|
|
Requires an entity to disclose a change in valuation technique
(and the related inputs) resulting from the application of the
FSP and to quantify its effects, if practicable; and
|
|
|
Applies to all fair value measurements when appropriate.
|
FSP
SFAS No. 157-4
must be applied prospectively and retrospective application is
not permitted. FSP
SFAS No. 157-4
is effective for interim and annual periods ending after
June 15, 2009. As of June 15, 2009, the Company
adopted the provisions of FSP
SFAS No. 157-4
related to assets and liabilities that are measured at fair
value on a recurring and nonrecurring basis. The adoption of the
provisions of FSP
SFAS No. 157-4
did not have a material effect on the financial condition or
results of operations of the Company. See Note H for
additional information regarding the Companys adoption of
FSP
SFAS No. 157-4.
In May 2009, the FASB issued SFAS No. 165,
Subsequent Events (SFAS No. 165)
which establishes general standards of accounting for and
disclosure of events that occur after the balance sheet date,
but before financial statements are issued or are available to
be issued. In particular, SFAS No. 165 sets forth:
|
|
|
The period after the balance sheet date during which management
of a reporting entity should evaluate events or transactions
that may occur for potential recognition or disclosure in the
financial statements;
|
|
|
The circumstances under which a reporting entity should
recognize events or transactions occurring after the balance
sheet date in its financial statements; and
|
|
|
The disclosures that a reporting entity should make about events
or transactions that occurred after the balance sheet date.
|
In accordance with this Statement, a reporting entity should
apply the requirements to interim or annual financial periods
ending after June 15, 2009. See Note P.
In June 2009, the FASB issued SFAS No. 166, Accounting
for Transfers of Financial Assets
(SFAS No. 166), which amends
SFAS No. 140, Accounting for Transfers and Servicing
of Financial Assets and Extinguishments of Liabilities . This
statement improves the relevance, representational faithfulness,
and comparability of the information that a reporting entity
provides in its financial reports about a transfer of financial
assets; the effects of a transfer on its financial position,
financial performance, and cash flows; and a transferors
continuing involvement in transferred financial assets.
SFAS No. 166 must be applied as of the beginning of a
reporting entitys first annual reporting period that
begins after November 15, 2009, for interim periods within
that first annual reporting period and for interim and annual
reporting periods thereafter. Earlier application is prohibited.
SFAS No. 166 must be applied to transfers occurring on
or after the effective date. The Company does not expect the
adoption of SFAS No. 166 to have an impact on its
consolidated financial statements.
Recent developments in reserves reporting. In
December 2008, the United States Securities and Exchange
Commission (the SEC) released Final Rule,
Modernization of Oil and Gas Reporting (the Reserve
Ruling). The Reserve Ruling revises oil and gas reporting
disclosures. The Reserve Ruling permits the use of new
technologies to determine proved reserves estimates if those
technologies have been demonstrated empirically to lead to
reliable conclusions about reserve volume estimates. The Reserve
Ruling will also allow, but not require, companies to disclose
their probable and possible reserves to investors in documents
filed with the SEC. In addition, the new disclosure requirements
require companies to: (i) report the independence and
F-11
qualifications of its reserves preparer or auditor;
(ii) file reports when a third party is relied upon to
prepare reserves estimates or conduct a reserves audit; and
(iii) report oil and gas reserves using an average price
based upon the prior
12-month
period rather than a year-end price. The Reserve Ruling becomes
effective for fiscal years ending on or after December 31,
2009. The Company is currently assessing the impact that
adoption of the provisions of the Reserve Ruling will have on
its financial position, results of operations and disclosures.
|
|
Note C.
|
Exploratory
well costs
|
The Company capitalizes exploratory well costs until a
determination is made that the well has either found proved
reserves or that it is impaired. The capitalized exploratory
well costs are presented in unproved properties in the
consolidated balance sheets. If the exploratory well is
determined to be impaired, the well costs are charged to expense.
The following table reflects the Companys capitalized
exploratory well activity during the three and six months ended
June 30, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
|
June 30, 2009
|
|
|
June 30, 2009
|
|
|
|
|
Beginning capitalized exploratory well costs
|
|
$
|
2,536
|
|
|
$
|
25,553
|
|
Additions to exploratory well costs pending the determination of
proved reserves
|
|
|
91,305
|
|
|
|
93,842
|
|
Reclassifications due to determination of proved reserves
|
|
|
(86,537
|
)
|
|
|
(111,640
|
)
|
Exploratory well costs charged to expense
|
|
|
|
|
|
|
(451
|
)
|
|
|
|
|
|
|
Ending capitalized exploratory well costs
|
|
$
|
7,304
|
|
|
$
|
7,304
|
|
|
|
The following table provides an aging, at June 30, 2009 and
December 31, 2008, of capitalized exploratory well costs
based on the date drilling was completed (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Wells in drilling progress
|
|
$
|
533
|
|
|
$
|
7,765
|
|
Capitalized exploratory well costs that have been capitalized
for a period of one year or less
|
|
|
6,771
|
|
|
|
17,788
|
|
Capitalized exploratory well costs that have been capitalized
for a period greater than one year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalized exploratory well costs
|
|
$
|
7,304
|
|
|
$
|
25,553
|
|
|
|
At June 30, 2009, the Company had seven gross exploratory
wells waiting on completion and two exploratory wells drilling,
all of which were in the New Mexico Permian area.
Henry Entities acquisition. On July 31, 2008,
the Company closed the acquisition of Henry Petroleum LP and
certain entities affiliated with Henry Petroleum LP (the
Henry Entities) and additional non-operated
interests in oil and natural gas properties from persons
affiliated with the Henry Entities. In August 2008 and September
2008, the Company acquired additional non-operated interests in
oil and natural gas properties from persons affiliated with the
Henry
F-12
Entities. The assets acquired in the Henry Entities acquisition,
including the additional non-operated interests, are referred to
as the Henry Properties. The Company paid
$583.5 million in cash for the Henry Properties acquisition.
The cash paid for the Henry Properties acquisition was funded
with (i) borrowings under the Companys credit
facility and (ii) proceeds from a private placement of
approximately 8.3 million shares of the Companys
common stock.
The Henry Properties acquisition is being accounted for using
the purchase method of accounting for business combinations.
Under the purchase method of accounting, the Company recorded
the Henry Properties assets and liabilities at fair value.
The purchase price of the acquired Henry Properties net
assets is based on the total value of the cash consideration.
The initial purchase price allocation is preliminary and subject
to adjustment primarily due to resolution of certain tax
matters. Any future adjustments to the allocation of the total
purchase price are not anticipated to be material to the
Companys consolidated financial statements.
The following tables represent the preliminary allocation of the
total purchase price of the Henry Properties to the acquired
assets and liabilities of the Henry Properties and the
consideration paid for the Henry Properties. The allocation
represents the fair values assigned to each of the assets
acquired and liabilities assumed (in thousands):
|
|
|
|
|
Fair value of Henry Properties net assets:
|
|
|
|
|
Current assets, net of cash acquired of
$19,049a
|
|
$
|
86,005
|
|
Proved oil and natural gas properties
|
|
|
593,984
|
|
Unproved oil and natural gas properties
|
|
|
233,492
|
|
Other long-term assets
|
|
|
7,392
|
|
Intangible assetsoperating rights
|
|
|
38,740
|
|
|
|
|
|
|
Total assets acquired
|
|
|
959,613
|
|
|
|
|
|
|
Current liabilities
|
|
|
(113,729
|
)
|
Asset retirement obligations and other long-term liabilities
|
|
|
(7,529
|
)
|
Noncurrent derivative liabilities
|
|
|
(39,037
|
)
|
Deferred tax liability
|
|
|
(215,815
|
)
|
|
|
|
|
|
Total liabilities assumed
|
|
|
(376,110
|
)
|
|
|
|
|
|
Net purchase price
|
|
$
|
583,503
|
|
|
|
|
|
|
Consideration paid for Henry Properties net assets:
|
|
|
|
|
Cash consideration paid, net of cash acquired of $19,049
|
|
$
|
577,853
|
|
Acquisition
costsb
|
|
|
5,650
|
|
|
|
|
|
|
Total purchase price
|
|
$
|
583,503
|
|
|
|
|
|
|
(a)
|
|
Includes a deferred tax asset of
approximately $9.0 million.
|
|
(b)
|
|
Acquisition costs include legal and
accounting fees, advisory fees and other acquisition-related
costs.
|
The following unaudited pro forma combined condensed financial
data for the three and six months ended June 30, 2008 was
derived from the historical financial statements of the Company
and Henry Properties giving effect to the acquisition as if it
had occurred on January 1, 2008. The unaudited pro forma
combined condensed financial data has been included for
comparative purposes only and is not necessarily indicative of
the results that might have
F-13
occurred had the Henry Properties acquisition taken place as of
the date indicated and is not intended to be a projection of
future results (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
|
|
|
Six months
|
|
|
|
ended
|
|
|
ended
|
|
|
|
June 30, 2008
|
|
|
June 30, 2008
|
|
|
|
|
Operating revenues
|
|
$
|
185,095
|
|
|
$
|
339,519
|
|
Net income
|
|
$
|
5,941
|
|
|
$
|
20,483
|
|
Earnings per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.07
|
|
|
$
|
0.24
|
|
Diluted
|
|
$
|
0.07
|
|
|
$
|
0.24
|
|
|
|
|
|
Note E.
|
Asset
retirement obligations
|
The Companys asset retirement obligations represent the
estimated present value of the estimated cash flows the Company
will incur to plug, abandon and remediate its producing
properties at the end of their production lives, in accordance
with applicable state laws. The Company does not provide for a
market risk premium associated with asset retirement obligations
because a reliable estimate cannot be determined. The Company
has no assets that are legally restricted for purposes of
settling asset retirement obligations.
The following table summarizes the Companys asset
retirement obligations (ARO) recorded during the
three and six months ended June 30, 2009 and 2008 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
|
|
|
Six months
|
|
|
|
ended June 30,
|
|
|
ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Asset retirement obligations, beginning of period
|
|
$
|
18,254
|
|
|
$
|
8,795
|
|
|
$
|
16,809
|
|
|
$
|
9,418
|
|
Liabilities incurred from new wells
|
|
|
102
|
|
|
|
275
|
|
|
|
270
|
|
|
|
309
|
|
Accretion expense
|
|
|
301
|
|
|
|
148
|
|
|
|
579
|
|
|
|
301
|
|
Disposition of wells sold
|
|
|
|
|
|
|
|
|
|
|
(142
|
)
|
|
|
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
(343
|
)
|
|
|
|
|
|
|
(353
|
)
|
|
|
|
|
Revision of estimates
|
|
|
(3,928
|
)
|
|
|
1,138
|
|
|
|
(2,777
|
)
|
|
|
328
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period
|
|
$
|
14,386
|
|
|
$
|
10,356
|
|
|
$
|
14,386
|
|
|
$
|
10,356
|
|
|
|
|
|
Note F.
|
Stockholders
equity
|
Common stock private placement. On June 5,
2008, the Company entered into a common stock purchase agreement
with certain unaffiliated third-party investors to sell certain
shares of the Companys common stock in a private placement
(the Private Placement) contemporaneous with the
closing of the Henry Properties acquisition. On July 31,
2008, the Company issued 8,302,894 shares of its common
stock at $30.11 per share. The Private Placement resulted in net
proceeds of approximately $242.4 million to the Company,
after payment of approximately $7.6 million for the fee
paid to the placement agent.
Treasury stock. On June 12, 2008, the
restrictions on certain restricted stock awards issued to five
of the Companys executive officers lapsed. Immediately
upon the lapse of restrictions, these executive officers became
liable for certain federal income taxes on the value of such
shares. In
F-14
accordance with the Companys 2006 Stock Incentive Plan and
the applicable restricted stock award agreements, four of such
officers elected to deliver shares of the Companys common
stock to the Company to satisfy such tax liability, and the
Company acquired 3,142 shares to be held as treasury stock
in the approximate amount of $125,000.
During the second quarter of 2009, the restrictions on certain
restricted stock awards issued to five of the Companys
executive officers lapsed. Immediately upon the lapse of
restrictions, these executive officers became liable for certain
federal income taxes on the value of such shares. In accordance
with the Companys 2006 Stock Incentive Plan and the
applicable restricted stock award agreements, all of such
officers elected to deliver shares of the Companys common
stock to the Company to satisfy such tax liability, and the
Company acquired 6,199 shares to be held as treasury stock
in the approximate amount of $192,000.
Defined contribution plan. The Company sponsors a
401(k) defined contribution plan for the benefit of all
employees and maintains certain other acquired plans. The
Company matches 100 percent of employee contributions, not
to exceed 6 percent of the employees annual salary.
The Company contributions to the plans for the three months
ended June 30, 2009 and 2008 were approximately
$0.2 million and $0.1 million, respectively, and
$0.5 million and $0.3 million for the six months ended
June 30, 2009 and 2008, respectively.
Stock incentive plan. The Companys 2006 Stock
Incentive Plan (together with applicable option agreements and
restricted stock agreements, the Plan) provides for
granting stock options and restricted stock awards to employees
and individuals associated with the Company. The following table
shows the number of awards available under the Companys
Plan at June 30, 2009:
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
common shares
|
|
|
|
|
Approved and authorized awards
|
|
|
5,850,000
|
|
Stock option grants, net of forfeitures
|
|
|
(3,461,485
|
)
|
Restricted stock grants, net of forfeitures
|
|
|
(767,787
|
)
|
|
|
|
|
|
Awards available for future grant
|
|
|
1,620,728
|
|
|
|
Restricted stock awards. All restricted shares are
treated as issued and outstanding in the accompanying
consolidated balance sheets. If an employee terminates
employment prior to the lapse date, restricted shares awarded to
such employee are forfeited and cancelled and are no longer
considered issued and outstanding. A summary of the
Companys restricted stock awards activity for the six
months ended June 30, 2009 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Grant date
|
|
|
|
restricted
|
|
|
fair value
|
|
|
|
shares
|
|
|
per share
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
407,351
|
|
|
|
|
|
Shares granted
|
|
|
257,398
|
|
|
$
|
25.14
|
|
Shares cancelled/forfeited
|
|
|
(2,420
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
(169,519
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2009
|
|
|
492,810
|
|
|
|
|
|
|
|
F-15
A summary of the impact on the consolidated statements of
operations for the Companys restricted stock awards during
the three and six months ended June 30, 2009 and 2008 is
presented below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months
|
|
|
|
Three months ended June 30,
|
|
|
ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Stock-based compensation expense related to restricted stock
|
|
$
|
1,303
|
|
|
$
|
468
|
|
|
$
|
2,200
|
|
|
$
|
862
|
|
Income tax benefit related to restricted stock
|
|
$
|
586
|
|
|
$
|
187
|
|
|
$
|
927
|
|
|
$
|
341
|
|
Deductions in current taxable income related to restricted stock
|
|
$
|
3,989
|
|
|
$
|
771
|
|
|
$
|
4,367
|
|
|
$
|
1,200
|
|
|
|
Stock option awards. A summary of the Companys
stock option award activity under the Plan for the six months
ended June 30, 2009 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted average
|
|
|
|
options
|
|
|
exercise price
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
2,731,324
|
|
|
$
|
12.46
|
|
Options granted
|
|
|
117,801
|
|
|
$
|
20.40
|
|
Options exercised
|
|
|
(445,789
|
)
|
|
$
|
8.82
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2009
|
|
|
2,403,336
|
|
|
$
|
13.53
|
|
|
|
|
|
|
|
|
|
|
Vested at end of period
|
|
|
1,637,752
|
|
|
$
|
10.38
|
|
|
|
|
|
|
|
|
|
|
Vested and exercisable at end of period
|
|
|
812,760
|
|
|
$
|
12.62
|
|
|
|
The following table summarizes information about the
Companys vested and exercisable stock options outstanding
at June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
average
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
stock
|
|
|
remaining
|
|
|
average
|
|
|
Intrinsic
|
|
(in thousands)
|
|
|
|
|
options
|
|
|
contractual life
|
|
|
exercise price
|
|
|
value
|
|
|
|
|
Vested options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
1,183,214
|
|
|
|
2.64 years
|
|
|
$
|
8.00
|
|
|
$
|
24,481
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
122,516
|
|
|
|
4.85 years
|
|
|
$
|
12.00
|
|
|
|
2,045
|
|
Exercise price
|
|
$
|
15.35
|
|
|
|
210,000
|
|
|
|
6.98 years
|
|
|
$
|
15.35
|
|
|
|
2,800
|
|
Exercise price
|
|
$
|
21.85
|
|
|
|
103,500
|
|
|
|
8.67 years
|
|
|
$
|
21.85
|
|
|
|
708
|
|
Exercise price
|
|
$
|
31.33
|
|
|
|
18,522
|
|
|
|
8.90 years
|
|
|
$
|
31.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,637,752
|
|
|
|
|
|
|
$
|
10.38
|
|
|
$
|
30,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
394,183
|
|
|
|
3.93 years
|
|
|
$
|
8.00
|
|
|
$
|
8,156
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
86,555
|
|
|
|
6.04 years
|
|
|
$
|
12.00
|
|
|
|
1,445
|
|
Exercise price
|
|
$
|
15.35
|
|
|
|
210,000
|
|
|
|
6.98 years
|
|
|
$
|
15.35
|
|
|
|
2,800
|
|
Exercise price
|
|
$
|
21.85
|
|
|
|
103,500
|
|
|
|
8.67 years
|
|
|
$
|
21.85
|
|
|
|
708
|
|
Exercise price
|
|
$
|
31.33
|
|
|
|
18,522
|
|
|
|
8.90 years
|
|
|
$
|
31.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
812,760
|
|
|
|
|
|
|
$
|
12.62
|
|
|
$
|
13,109
|
|
|
|
F-16
The following table summarizes information about stock-based
compensation for stock options for the three and six months
ended June 30, 2009 and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
Six months ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Grant date fair value for awards during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting options
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
183
|
|
Stock option grants under the plan
|
|
|
|
|
|
|
794
|
|
|
|
1,454
|
|
|
|
5,090
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
794
|
|
|
$
|
1,454
|
|
|
$
|
5,273
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock
options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting options
|
|
$
|
70
|
|
|
$
|
35
|
|
|
$
|
141
|
|
|
$
|
65
|
|
Performance vesting optionsofficers
|
|
|
|
|
|
|
133
|
|
|
|
71
|
|
|
|
284
|
|
Stock option grants under the plan
|
|
|
815
|
|
|
|
1,094
|
|
|
|
1,701
|
|
|
|
1,818
|
|
|
|
|
|
|
|
Total
|
|
$
|
885
|
|
|
$
|
1,262
|
|
|
$
|
1,913
|
|
|
$
|
2,167
|
|
|
|
|
|
|
|
Income taxes and other information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to stock options
|
|
$
|
415
|
|
|
$
|
504
|
|
|
$
|
806
|
|
|
$
|
858
|
|
Deductions in current taxable income related to stock options
exercised
|
|
$
|
4,117
|
|
|
$
|
3,132
|
|
|
$
|
7,157
|
|
|
$
|
5,338
|
|
|
|
In calculating compensation expense for options granted during
the six months ended June 30, 2009, the Company estimated
the fair value of each grant using the Black-Scholes
option-pricing model. Assumptions utilized in the model are
shown below:
|
|
|
|
|
Risk-free interest rate
|
|
|
2.46%
|
|
Expected term (years)
|
|
|
6.25
|
|
Expected volatility
|
|
|
63.40%
|
|
Expected dividend yield
|
|
|
|
|
|
|
As permitted by Staff Accounting Bulletin No. 110,
Share-Based Payment, the Company used the simplified
method to calculate the expected term for stock options granted
during the three and six months ended June 30, 2009, since
it does not have sufficient historical exercise data to provide
a reasonable basis upon which to estimate expected term due to
the limited period of time its shares of common stock have been
publicly traded. Expected volatilities are based on a
combination of historical and implied volatilities of comparable
companies.
Future stock-based compensation expense. Future
stock-based compensation expense at June 30, 2009 is
summarized in the table below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
|
|
|
Stock
|
|
|
|
|
|
|
stock
|
|
|
options
|
|
|
Total
|
|
|
|
|
Remaining 2009
|
|
$
|
2,333
|
|
|
$
|
1,423
|
|
|
$
|
3,756
|
|
2010
|
|
|
3,431
|
|
|
|
1,694
|
|
|
|
5,125
|
|
2011
|
|
|
2,159
|
|
|
|
706
|
|
|
|
2,865
|
|
2012
|
|
|
643
|
|
|
|
166
|
|
|
|
809
|
|
2013
|
|
|
24
|
|
|
|
14
|
|
|
|
38
|
|
|
|
|
|
|
|
Total
|
|
$
|
8,590
|
|
|
$
|
4,003
|
|
|
$
|
12,593
|
|
|
|
F-17
Note H. Disclosures
about fair value of financial instruments
The Company adopted SFAS No. 157, Fair Value
Measurements, (SFAS No. 157) effective
January 1, 2008 for financial assets and liabilities
measured on a recurring basis. SFAS No. 157 applies to
all financial assets and financial liabilities that are being
measured and reported on a fair value basis. In February 2008,
the FASB issued FSP
No. 157-2,
Effective Date of FASB Statement No. 157, which
delayed the effective date of SFAS No. 157 by one year
for nonfinancial assets and liabilities. As of January 1,
2009, the Company adopted the provisions of SFAS 157
related to the Companys nonfinancial assets and
liabilities, including nonfinancial assets and liabilities
measured at fair value in a business combination; impaired
long-lived assets; and initial recognition of asset retirement
obligations. As defined in SFAS No. 157, fair value is
the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market
participants at the measurement date. SFAS No. 157
requires disclosure that establishes a framework for measuring
fair value and expands disclosure about fair value measurements.
The statement requires fair value measurements be classified and
disclosed in one of the following categories:
Level 1: Unadjusted quoted prices in active
markets that are accessible at the measurement date for
identical, unrestricted assets or liabilities. The Company
considers active markets to be those in which transactions for
the assets or liabilities occur in sufficient frequency and
volume to provide pricing information on an ongoing basis.
Level 2: Quoted prices in markets that are not
active, or inputs which are observable, either directly or
indirectly, for substantially the full term of the asset or
liability. This category includes those derivative instruments
that the Company values using observable market data.
Substantially all of these inputs are observable in the
marketplace throughout the full term of the derivative
instrument, can be derived from observable data, or supported by
observable levels at which transactions are executed in the
marketplace. Level 2 instruments primarily include
non-exchange traded derivatives such as over-the-counter
commodity price swaps, basis swaps, investments and interest
rate swaps. The Companys valuation models are primarily
industry-standard models that consider various inputs including:
(i) quoted forward prices for commodities, (ii) time
value and (iii) current market and contractual prices for
the underlying instruments, as well as other relevant economic
measures. The Company utilizes its counterparties
valuations to assess the reasonableness of its prices and
valuation techniques.
Level 3: Measured based on prices or valuation
models that require inputs that are both significant to the fair
value measurement and less observable from objective sources (
i.e. , supported by little or no market activity).
Level 3 instruments primarily include derivative
instruments, such as commodity price collars and floors, as well
as investments. The Companys valuation models are
primarily industry-standard models that consider various inputs
including: (i) quoted forward prices for commodities,
(ii) time value, (iii) volatility factors and
(iv) current market and contractual prices for the
underlying instruments, as well as other relevant economic
measures. Although the Company utilizes its counterparties
valuations to assess the reasonableness of our prices and
valuation techniques, the Company does not have sufficient
corroborating market evidence to support classifying these
assets and liabilities as Level 2.
F-18
The following represents information about the estimated fair
values of the Companys financial instruments:
Cash and cash equivalents, accounts receivable, other current
assets, accounts payable, interest payable and other current
liabilities. The carrying amounts approximate fair
value due to the short maturity of these instruments.
Line of credit. The carrying amount of borrowings
outstanding under the Companys credit facility
approximates fair value, because the instrument bears interest
at variable market rates.
Assets and
liabilities measured at fair value on a recurring
basis
Derivative instruments. The fair value of the
Companys derivative instruments are estimated by
management considering various factors, including closing
exchange and over-the-counter quotations and the time value of
the underlying commitments. As required by
SFAS No. 157, financial assets and liabilities are
classified based on the lowest level of input that is
significant to the fair value measurement. The Companys
assessment of the significance of a particular input to the fair
value measurement requires judgment, and may affect the
valuation of the fair value of assets and liabilities and their
placement within the fair value hierarchy levels. The following
table (i) summarizes the valuation of each of the
Companys financial instruments by SFAS No. 157
pricing levels and (ii) summarizes the gross fair value by
the appropriate balance sheet classification, in accordance with
SFAS No. 161, even when the derivative instruments are
subject to netting arrangements and qualify for net presentation
in the Companys consolidated balance sheets at
June 30, 2009 and December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using
|
|
|
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
|
|
|
Total
|
|
|
|
prices
|
|
|
other
|
|
|
Significant
|
|
|
carrying value
|
|
|
|
in active
|
|
|
observable
|
|
|
unobservable
|
|
|
at
|
|
|
|
markets
|
|
|
inputs
|
|
|
inputs
|
|
|
June 30,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2009
|
|
|
|
|
Assets1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
26,408
|
|
|
$
|
|
|
|
$
|
26,408
|
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
18,856
|
|
|
|
18,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,408
|
|
|
|
18,856
|
|
|
|
45,264
|
|
Noncurrent:b
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
43,604
|
|
|
|
|
|
|
|
43,604
|
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
3,541
|
|
|
|
|
|
|
|
3,541
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47,145
|
|
|
|
|
|
|
|
47,145
|
|
|
|
F-19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using
|
|
|
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
|
|
|
Total
|
|
|
|
prices
|
|
|
other
|
|
|
Significant
|
|
|
carrying value
|
|
|
|
in active
|
|
|
observable
|
|
|
unobservable
|
|
|
at
|
|
|
|
markets
|
|
|
inputs
|
|
|
inputs
|
|
|
June 30,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2009
|
|
|
|
|
Liabilities1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
(27,650
|
)
|
|
|
|
|
|
|
(27,650
|
)
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
(2,456
|
)
|
|
|
|
|
|
|
(2,456
|
)
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
(3,624
|
)
|
|
|
|
|
|
|
(3,624
|
)
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
(993
|
)
|
|
|
(993
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33,730
|
)
|
|
|
(993
|
)
|
|
|
(34,723
|
)
|
Noncurrent:b
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
(29,782
|
)
|
|
|
|
|
|
|
(29,782
|
)
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
(1,476
|
)
|
|
|
|
|
|
|
(1,476
|
)
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
(2,105
|
)
|
|
|
(2,105
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,258
|
)
|
|
|
(2,105
|
)
|
|
|
(33,363
|
)
|
|
|
|
|
|
|
Total financial assets (liabilities)
|
|
$
|
|
|
|
$
|
8,565
|
|
|
$
|
15,758
|
|
|
$
|
24,323
|
|
|
|
|
|
|
|
(a) Total current financial assets (liabilities), gross
basis
|
|
$
|
10,541
|
|
(b) Total noncurrent financial assets (liabilities),
gross basis
|
|
|
13,782
|
|
|
|
|
|
|
Total financial assets (liabilities)
|
|
$
|
24,323
|
|
|
|
F-20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using
|
|
|
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
prices in
|
|
|
other
|
|
|
Significant
|
|
|
Total carrying
|
|
|
|
active
|
|
|
observable
|
|
|
unobservable
|
|
|
value at
|
|
|
|
markets
|
|
|
inputs
|
|
|
inputs
|
|
|
December 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2008
|
|
|
|
|
Assets1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
64,162
|
|
|
$
|
|
|
|
$
|
64,162
|
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
49,562
|
|
|
|
49,562
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64,162
|
|
|
|
49,562
|
|
|
|
113,724
|
|
Noncurrent:b
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
60,995
|
|
|
|
|
|
|
|
60,995
|
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
678
|
|
|
|
|
|
|
|
678
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61,673
|
|
|
|
|
|
|
|
61,673
|
|
Liabilities1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
(680
|
)
|
|
|
|
|
|
|
(680
|
)
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
(1,761
|
)
|
|
|
|
|
|
|
(1,761
|
)
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,441
|
)
|
|
|
|
|
|
|
(2,441
|
)
|
Noncurrent:b
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
(516
|
)
|
|
|
|
|
|
|
(516
|
)
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(516
|
)
|
|
|
|
|
|
|
(516
|
)
|
|
|
|
|
|
|
Total financial assets (liabilities)
|
|
$
|
|
|
|
$
|
122,878
|
|
|
$
|
49,562
|
|
|
$
|
172,440
|
|
|
|
|
|
|
|
(a) Total current financial assets (liabilities), gross
basis
|
|
$
|
111,283
|
|
(b) Total noncurrent financial assets (liabilities),
gross basis
|
|
|
61,157
|
|
|
|
|
|
|
Total financial assets (liabilities)
|
|
$
|
172,440
|
|
|
|
F-21
|
|
|
(1)
|
|
The fair value of derivative
instruments reported in the Companys consolidated balance
sheets are subject to netting arrangements and qualify for net
presentation. The following table reports the net basis
derivative fair values as reported in the consolidated balance
sheets at June 30, 2009 and December 31, 2008 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Consolidated balance sheet classification:
|
|
|
|
|
|
|
|
|
Current derivative contracts:
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
26,272
|
|
|
$
|
113,149
|
|
Liabilities
|
|
|
(15,731
|
)
|
|
|
(1,866
|
)
|
|
|
|
|
|
|
Net current
|
|
$
|
10,541
|
|
|
$
|
111,283
|
|
|
|
|
|
|
|
Noncurrent derivative contracts:
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
31,438
|
|
|
$
|
61,157
|
|
Liabilities
|
|
|
(17,656
|
)
|
|
|
|
|
|
|
|
|
|
|
Net noncurrent
|
|
$
|
13,782
|
|
|
$
|
61,157
|
|
|
|
The following table sets forth a reconciliation of changes in
the fair value of financial assets and liabilities classified as
Level 3 in the fair value hierarchy (in thousands):
|
|
|
|
|
Balance at December 31, 2008
|
|
$
|
49,562
|
|
Realized and unrealized losses
|
|
|
(9,686
|
)
|
Purchases, issuances, and settlements
|
|
|
(24,118
|
)
|
|
|
|
|
|
Balance at June 30, 2009
|
|
$
|
15,758
|
|
|
|
|
|
|
Total losses for the period included in earnings attributable to
the change in unrealized losses relating to assets still held at
the reporting date
|
|
$
|
(33,804
|
)
|
|
|
For additional information on the Companys derivative
instruments see Note I.
Assets and
liabilities measured at fair value on a nonrecurring
basis
Certain assets and liabilities are reported at fair value on a
nonrecurring basis in the Companys consolidated balance
sheets. The following methods and assumptions were used to
estimate the fair values:
Impairments of long-lived assetsIn accordance with
SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets , the Company reviews its
long-lived assets to be held and used, including proved oil and
gas properties, whenever events or circumstances indicate that
the carrying value of those assets may not be recoverable. An
impairment loss is indicated if the sum of the expected future
cash flows is less than the carrying amount of the assets. In
this circumstance, the Company recognizes an impairment loss for
the amount by which the carrying amount of the asset exceeds the
estimated fair value of the asset. The Company reviews its oil
and gas properties by amortization base or by individual well
for those wells not constituting part of an amortization base.
For each property determined to be impaired, an impairment loss
equal to the difference between the carrying value of the
properties and the estimated fair value (discounted future cash
flows) of the properties would be recognized at that time.
Estimating future cash flows involves the use of judgments,
including estimation of the proved and unproved oil and gas
reserve quantities, timing of development and production,
expected future commodity prices, capital expenditures and
production costs.
The Company periodically reviews its proved oil and gas
properties that are sensitive to oil and natural gas prices for
impairment. Due to downward adjustments to the economically
recoverable resource potential associated with declines in
commodity prices and well performance, the Company recognized
impairment expense of $4.5 million and $8.6 million
for the three and six months ended June 30, 2009,
respectively, related to its proved oil and gas properties. For
the
F-22
three months ended June 30, 2009, the impaired assets,
which had a total carrying amount of $7.3 million, were
reduced to their estimated fair value of $2.8 million. For
the six months ended June 30, 2009, the impaired assets,
which had a total carrying amount of $14.2 million, were
reduced to their estimated fair value of $5.6 million.
Asset retirement obligationsThe Company estimates
the fair value of AROs based on discounted cash flow projections
using numerous estimates, assumptions and judgments regarding
such factors as the existence of a legal obligation for an ARO;
amounts and timing of settlements; the credit-adjusted risk-free
rate to be used; and inflation rates. See Note E for a
summary of changes in AROs.
Measurement information for assets that are measured at fair
value on a nonrecurring basis was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
prices in
|
|
|
other
|
|
|
Significant
|
|
|
|
|
|
|
active
|
|
|
observable
|
|
|
unobservable
|
|
|
Total
|
|
|
|
markets
|
|
|
inputs
|
|
|
inputs
|
|
|
impairments
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
loss
|
|
|
|
|
Three months ended June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,733
|
|
|
$
|
(4,499
|
)
|
Asset retirement obligations incurred in current period
|
|
|
|
|
|
|
|
|
|
|
102
|
|
|
|
|
|
Three months ended June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7
|
|
|
$
|
(53
|
)
|
Asset retirement obligations incurred in current period
|
|
|
|
|
|
|
|
|
|
|
275
|
|
|
|
|
|
Six months ended June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5,620
|
|
|
$
|
(8,555
|
)
|
Asset retirement obligations incurred in current period
|
|
|
|
|
|
|
|
|
|
|
270
|
|
|
|
|
|
Six months ended June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7
|
|
|
$
|
(69
|
)
|
Asset retirement obligations incurred in current period
|
|
|
|
|
|
|
|
|
|
|
309
|
|
|
|
|
|
|
|
|
|
Note I.
|
Derivative
financial instruments
|
The Company uses derivative financial contracts to manage
exposures to commodity price and interest rate fluctuations.
Commodity hedges are used to (i) reduce the effect of the
volatility of price changes on the natural gas and oil the
Company produces and sells, (ii) support the Companys
capital budget and expenditure plans and (iii) support the
economics associated with acquisitions. Interest rate hedges are
used to mitigate the cash flow risk associated with rising
interest rates. The Company does not enter into derivative
financial instruments for speculative or trading purposes. The
Company also may enter into physical delivery contracts to
effectively provide commodity price hedges. Because these
contracts are not expected to be net cash settled, they are
considered to be normal sales contracts and not derivatives.
Therefore, these contracts are not recorded in the
Companys consolidated financial statements.
F-23
Currently, the Company does not designate its derivative
instruments to qualify for hedge accounting. Accordingly, the
Company reflects changes in the fair value of its derivative
instruments in its statements of operations. All of the
Companys remaining hedges that historically qualified for
hedge accounting or were dedesignated from hedge accounting were
settled in 2008.
New commodity derivatives contracts in 2009. During
the six months ended June 30, 2009, the Company entered
into additional commodity derivative contracts to hedge a
portion of its estimated future production. The following table
summarizes information about these additional commodity
derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
Index
|
|
|
Contract
|
|
|
|
volume
|
|
|
price
|
|
|
period
|
|
|
|
|
Oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
|
600,000
|
|
|
$
|
45.00 $49.00
|
a d
|
|
|
3/1/09 5/31/09
|
|
Price swap
|
|
|
270,000
|
|
|
$
|
69.50
|
a
|
|
|
7/1/09 9/30/09
|
|
Price swap
|
|
|
540,000
|
|
|
$
|
51.62
|
a d
|
|
|
7/1/09 12/31/09
|
|
Price swap
|
|
|
150,000
|
|
|
$
|
69.50
|
a
|
|
|
10/1/09 12/31/09
|
|
Price swap
|
|
|
2,508,000
|
|
|
$
|
62.15
|
a d
|
|
|
1/1/10 12/31/10
|
|
Price swap
|
|
|
1,800,000
|
|
|
$
|
72.17
|
a d
|
|
|
1/1/11 12/31/11
|
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
|
1,500,000
|
|
|
$
|
5.00 $5.81
|
b
|
|
|
10/1/09 12/31/09
|
|
Price collar
|
|
|
1,500,000
|
|
|
$
|
5.00 $5.81
|
b
|
|
|
1/1/10 3/31/10
|
|
Price collar
|
|
|
3,000,000
|
|
|
$
|
5.25 $5.75
|
b
|
|
|
4/1/10 9/30/10
|
|
Price collar
|
|
|
1,500,000
|
|
|
$
|
6.00 $6.80
|
b
|
|
|
10/1/10 12/31/10
|
|
Price collar
|
|
|
1,500,000
|
|
|
$
|
6.00 $6.80
|
b
|
|
|
1/1/11 3/31/11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
3,000,000
|
|
|
$
|
4.31
|
b
|
|
|
4/1/09 9/30/09
|
|
Price swap
|
|
|
600,000
|
|
|
$
|
4.66
|
b
|
|
|
7/1/09 9/30/09
|
|
Price swap
|
|
|
450,000
|
|
|
$
|
4.66
|
b
|
|
|
10/1/09 12/31/09
|
|
Price swap
|
|
|
2,400,000
|
|
|
$
|
6.31
|
b
|
|
|
1/1/10 12/31/10
|
|
Price swap
|
|
|
300,000
|
|
|
$
|
7.29
|
b
|
|
|
1/1/11 3/31/11
|
|
Price swap
|
|
|
5,400,000
|
|
|
$
|
6.96
|
b d
|
|
|
4/1/11 12/31/11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swap
|
|
|
600,000
|
|
|
$
|
0.79
|
c
|
|
|
7/1/09 9/30/09
|
|
Basis swap
|
|
|
450,000
|
|
|
$
|
0.89
|
c
|
|
|
10/1/09 12/31/09
|
|
Basis swap
|
|
|
8,400,000
|
|
|
$
|
0.85
|
c d
|
|
|
1/1/10 12/31/10
|
|
Basis swap
|
|
|
1,800,000
|
|
|
$
|
0.87
|
c d
|
|
|
1/1/11 3/31/11
|
|
Basis swap
|
|
|
5,400,000
|
|
|
$
|
0.76
|
c
|
|
|
4/1/11 12/31/11
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
swaps and collars are based on the NYMEX-West Texas Intermediate
monthly average futures price.
|
|
(b)
|
|
The index prices for the natural
gas price swaps and collars are based on the NYMEX-Henry Hub
last trading day futures price.
|
|
(c)
|
|
Represents the basis differential
between the El Paso Permian delivery point and NYMEX Henry
Hub delivery point.
|
|
(d)
|
|
Prices represent weighted average
prices.
|
F-24
In July 2009, the Company entered into the following oil price
swaps to hedge an additional portion of its estimated oil
production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
Index
|
|
|
Contract
|
|
|
|
volume
|
|
|
price
|
|
|
period
|
|
|
|
|
Oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
273,000
|
|
|
$
|
67.50
|
a
|
|
|
8/1/09 12/31/09
|
|
Price swap
|
|
|
799,000
|
|
|
$
|
67.50
|
a
|
|
|
1/1/10 12/31/10
|
|
Price swap
|
|
|
801,000
|
|
|
$
|
70.53
|
a b
|
|
|
1/1/11 12/31/11
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price.
|
|
(b)
|
|
Prices represent weighted average
prices.
|
Commodity derivative contracts at June 30,
2009. The following table sets forth the Companys
outstanding commodity derivative contracts at June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
|
|
quarter
|
|
|
quarter
|
|
|
quarter
|
|
|
quarter
|
|
|
Total
|
|
|
|
|
Oil
swaps:a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
|
|
|
|
|
|
|
995,473
|
|
|
|
875,473
|
|
|
|
1,870,946
|
|
Price per
Bble
|
|
|
|
|
|
|
|
|
|
$
|
72.71
|
|
|
$
|
73.15
|
|
|
$
|
72.92
|
|
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
787,436
|
|
|
|
787,436
|
|
|
|
787,436
|
|
|
|
787,436
|
|
|
|
3,149,744
|
|
Price per
Bble
|
|
$
|
68.49
|
|
|
$
|
68.49
|
|
|
$
|
68.49
|
|
|
$
|
68.49
|
|
|
$
|
68.49
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
589,436
|
|
|
|
589,436
|
|
|
|
589,436
|
|
|
|
589,436
|
|
|
|
2,357,744
|
|
Price per
Bble
|
|
$
|
79.91
|
|
|
$
|
79.91
|
|
|
$
|
79.91
|
|
|
$
|
79.91
|
|
|
$
|
79.91
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
126,000
|
|
|
|
126,000
|
|
|
|
126,000
|
|
|
|
126,000
|
|
|
|
504,000
|
|
Price per Bbl
|
|
$
|
127.80
|
|
|
$
|
127.80
|
|
|
$
|
127.80
|
|
|
$
|
127.80
|
|
|
$
|
127.80
|
|
Oil
collars:a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
|
|
|
|
|
|
|
192,000
|
|
|
|
192,000
|
|
|
|
384,000
|
|
Price per
Bble
|
|
|
|
|
|
|
|
|
|
$
|
120.00-$134.60
|
|
|
$
|
120.00-$134.60
|
|
|
$
|
120.00-$134.60
|
|
Natural gas
swaps:b
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
|
|
|
|
|
|
|
460,000
|
|
|
|
460,000
|
|
|
|
920,000
|
|
Price per MMBtu
|
|
|
|
|
|
|
|
|
|
$
|
8.44
|
|
|
$
|
8.44
|
|
|
$
|
8.44
|
|
Natural gas
swaps:c
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
|
|
|
|
|
|
|
2,100,000
|
|
|
|
450,000
|
|
|
|
2,550,000
|
|
Price per MMBtu
|
|
|
|
|
|
|
|
|
|
$
|
4.41
|
|
|
$
|
4.66
|
|
|
$
|
4.45
|
|
F-25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
|
|
quarter
|
|
|
quarter
|
|
|
quarter
|
|
|
quarter
|
|
|
Total
|
|
|
|
|
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
600,000
|
|
|
|
600,000
|
|
|
|
600,000
|
|
|
|
600,000
|
|
|
|
2,400,000
|
|
Price per MMBtu
|
|
$
|
6.31
|
|
|
$
|
6.31
|
|
|
$
|
6.31
|
|
|
$
|
6.31
|
|
|
$
|
6.31
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
300,000
|
|
|
|
1,800,000
|
|
|
|
1,800,000
|
|
|
|
1,800,000
|
|
|
|
5,700,000
|
|
Price per MMBtu
|
|
$
|
7.29
|
|
|
$
|
6.96
|
|
|
$
|
6.96
|
|
|
$
|
6.96
|
|
|
$
|
6.98
|
|
Natural gas
collars:c
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000
|
|
|
|
1,500,000
|
|
Price per MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5.00-$5.81
|
|
|
$
|
5.00-$5.81
|
|
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
1,500,000
|
|
|
|
1,500,000
|
|
|
|
1,500,000
|
|
|
|
1,500,000
|
|
|
|
6,000,000
|
|
Price per MMBtu
|
|
$
|
5.00-$5.81
|
|
|
$
|
5.25-$5.75
|
|
|
$
|
5.25-$5.75
|
|
|
$
|
6.00-$6.80
|
|
|
$
|
5.38-$6.03
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
1,500,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000
|
|
Price per MMBtu
|
|
$
|
6.00-$6.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6.00-$6.80
|
|
Natural gas basis
swaps:d
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
|
|
|
|
|
|
|
2,118,000
|
|
|
|
1,968,000
|
|
|
|
4,086,000
|
|
Price per
MMBtue
|
|
|
|
|
|
|
|
|
|
$
|
0.99
|
|
|
$
|
1.03
|
|
|
$
|
1.01
|
|
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
2,100,000
|
|
|
|
2,100,000
|
|
|
|
2,100,000
|
|
|
|
2,100,000
|
|
|
|
8,400,000
|
|
Price per
MMBtue
|
|
$
|
0.85
|
|
|
$
|
0.85
|
|
|
$
|
0.85
|
|
|
$
|
0.85
|
|
|
$
|
0.85
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
1,800,000
|
|
|
|
1,800,000
|
|
|
|
1,800,000
|
|
|
|
1,800,000
|
|
|
|
7,200,000
|
|
Price per
MMBtue
|
|
$
|
0.87
|
|
|
$
|
0.76
|
|
|
$
|
0.76
|
|
|
$
|
0.76
|
|
|
$
|
0.79
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
swaps and collars are based on the NYMEX-West Texas Intermediate
monthly average futures price.
|
|
(b)
|
|
The index price for the natural gas
price swap is based on the Inside FERC-El Paso Permian
Basin first-of-the-month spot price.
|
|
(c)
|
|
Represents the index prices for the
natural gas price swaps and collars are based on the NYMEX-Henry
Hub last trading day futures price.
|
|
(d)
|
|
The basis differential between the
El Paso Permian delivery point and NYMEX Henry Hub delivery
point.
|
|
(e)
|
|
Prices represent weighted average
prices.
|
Interest rate derivative contracts at June 30,
2009. The Company has an interest rate swap which fixes
the LIBOR interest rate on $300 million of the
Companys bank debt at 1.90 percent for three years,
commencing in May of 2009. For this portion of the
Companys bank debt, the all-in interest rate will be
calculated by adding the fixed rate of 1.90 percent to a
margin that ranges from 2.00 percent to 3.00 percent
depending on the amount of bank debt outstanding.
The Companys reported oil and natural gas revenue and
average oil and natural gas prices includes the effects of oil
quality and Btu content, gathering and transportation costs,
natural gas processing and shrinkage, and the net effect of the
commodity hedges that qualified for cash flow hedge accounting.
The following table summarizes the gains and losses reported in
earnings related to the commodity and interest rate derivative
instruments and the net change
F-26
in accumulated other comprehensive income (AOCI) for
the three and six months ended June 30, 2009 and 2008 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Decrease in oil and natural gas revenue from derivative
activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments on cash flow hedges in oil sales
|
|
$
|
|
|
|
$
|
(13,367
|
)
|
|
$
|
|
|
|
$
|
(20,573
|
)
|
Dedesignated cash flow hedges reclassified from AOCI in natural
gas sales
|
|
|
|
|
|
|
74
|
|
|
|
|
|
|
|
(222
|
)
|
|
|
|
|
|
|
Total decrease in oil and natural gas revenue from derivative
activity
|
|
$
|
|
|
|
$
|
(13,293
|
)
|
|
$
|
|
|
|
$
|
(20,795
|
)
|
|
|
|
|
|
|
Loss on derivatives not designated as hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
gain (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
(109,374
|
)
|
|
$
|
(90,055
|
)
|
|
$
|
(149,117
|
)
|
|
$
|
(103,247
|
)
|
Interest rate derivatives
|
|
|
3,427
|
|
|
|
|
|
|
|
1,000
|
|
|
|
|
|
Cash (payments) receipts on derivatives not designated as
hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
25,120
|
|
|
|
(12,401
|
)
|
|
|
62,244
|
|
|
|
(16,387
|
)
|
Interest rate derivatives
|
|
|
(779
|
)
|
|
|
|
|
|
|
(779
|
)
|
|
|
|
|
|
|
|
|
|
|
Total loss on derivatives not designated as hedges
|
|
$
|
(81,606
|
)
|
|
$
|
(102,456
|
)
|
|
$
|
(86,652
|
)
|
|
$
|
(119,634
|
)
|
|
|
|
|
|
|
Gain from ineffective portion of cash flow hedges
|
|
$
|
|
|
|
$
|
356
|
|
|
$
|
|
|
|
$
|
920
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
loss of cash flow hedges
|
|
$
|
|
|
|
$
|
(25,903
|
)
|
|
$
|
|
|
|
$
|
(32,510
|
)
|
Reclassification adjustment of losses to earnings
|
|
|
|
|
|
|
13,367
|
|
|
|
|
|
|
|
20,573
|
|
|
|
|
|
|
|
Net change, before income taxes
|
|
|
|
|
|
|
(12,536
|
)
|
|
|
|
|
|
|
(11,937
|
)
|
Income tax effect
|
|
|
|
|
|
|
4,899
|
|
|
|
|
|
|
|
4,665
|
|
|
|
|
|
|
|
Net change, net of income taxes
|
|
$
|
|
|
|
$
|
(7,637
|
)
|
|
$
|
|
|
|
$
|
(7,272
|
)
|
|
|
|
|
|
|
Dedesignated cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustment of (gains) losses to earnings
|
|
$
|
|
|
|
$
|
(74
|
)
|
|
$
|
|
|
|
$
|
222
|
|
Income tax effect
|
|
|
|
|
|
|
29
|
|
|
|
|
|
|
|
(87
|
)
|
|
|
|
|
|
|
Net change, net of income taxes
|
|
$
|
|
|
|
$
|
(45
|
)
|
|
$
|
|
|
|
$
|
135
|
|
|
|
The Companys debt consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Credit facility
|
|
$
|
660,000
|
|
|
$
|
630,000
|
|
Less: current portion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
660,000
|
|
|
$
|
630,000
|
|
|
|
Credit facility. The Companys credit facility,
as amended, has a maturity date of July 31, 2013 (the
Credit Facility). At June 30, 2009, the Company
had letters of credit outstanding under the Credit
F-27
Facility of approximately $25,000 and its availability to borrow
additional funds was approximately $300 million. In April
2009, the lenders reaffirmed the Companys
$960 million borrowing base under the Credit Facility until
the next scheduled borrowing base redetermination in October
2009. Between scheduled borrowing base redeterminations, the
Company and, if requested by
662/3 percent
of the lenders, the lenders, may each request one special
redetermination.
Advances on the Credit Facility bear interest, at the
Companys option, based on (i) the prime rate of
JPMorgan Chase Bank (JPM Prime Rate)
(3.25 percent at June 30, 2009) or (ii) a
Eurodollar rate (substantially equal to the London Interbank
Offered Rate). At June 30, 2009, the interest rates of
Eurodollar rate advances and JPM Prime Rate advances vary, with
interest margins ranging from 200 to 300 basis points and
112.5 to 212.5 basis points, respectively, per annum
depending on the debt balance outstanding. At June 30,
2009, the Company pays commitment fees on the unused portion of
the available borrowing base of 50 basis points per annum.
The Credit Facility also includes a
same-day
advance facility under which the Company may borrow funds from
the administrative agent. Same day advances cannot exceed
$25 million and the maturity dates cannot exceed fourteen
days. The interest rate on this facility is the JPM Prime Rate
plus the applicable interest margin.
The Companys obligations under the Credit Facility are
secured by a first lien on substantially all of the
Companys oil and natural gas properties. In addition, all
of the Companys subsidiaries are guarantors and all
general partner, limited partner and membership interests in the
Companys subsidiaries owned by the Company have been
pledged to secure borrowings under the Credit Facility. The
credit agreement contains various restrictive covenants and
compliance requirements which include (a) maintenance of
certain financial ratios, including (i) a quarterly ratio
of total debt to consolidated earnings before interest expense,
income taxes, depletion, depreciation, and amortization,
exploration expense and other noncash income and expenses to be
no greater than 4.0 to 1.0, and (ii) a ratio of current
assets to current liabilities, excluding noncash assets and
liabilities related to financial derivatives and asset
retirement obligations and including the unfunded amounts under
the Credit Facility, to be no less than 1.0 to 1.0;
(b) limits on the incurrence of additional indebtedness and
certain types of liens; (c) restrictions as to mergers,
combinations and dispositions of assets; and
(d) restrictions on the payment of cash dividends. At
June 30, 2009, the Company was in compliance with its debt
covenants under the Credit Facility.
Principal maturities of debt. Principal maturities
of debt outstanding at June 30, 2009 are as follows (in
thousands):
|
|
|
|
|
Remaining 2009
|
|
$
|
|
|
2010
|
|
|
|
|
2011
|
|
|
|
|
2012
|
|
|
|
|
2013
|
|
|
660,000
|
|
|
|
|
|
|
Total
|
|
$
|
660,000
|
|
|
|
F-28
Interest expense. The following amounts have been
incurred and charged to interest expense for the three and six
months ended June 30, 2009 and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Cash payments for interest
|
|
$
|
3,457
|
|
|
$
|
3,982
|
|
|
$
|
6,929
|
|
|
$
|
10,758
|
|
Amortization of original issue discount
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
50
|
|
Amortization of deferred loan origination costs
|
|
|
857
|
|
|
|
314
|
|
|
|
1,713
|
|
|
|
626
|
|
Write-off of deferred loan origination costs and original issue
discount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net changes in accruals
|
|
|
1,889
|
|
|
|
(71
|
)
|
|
|
1,946
|
|
|
|
(1,094
|
)
|
|
|
|
|
|
|
Interest costs incurred
|
|
|
6,203
|
|
|
|
4,250
|
|
|
|
10,588
|
|
|
|
10,340
|
|
Less: capitalized interest
|
|
|
(3
|
)
|
|
|
(365
|
)
|
|
|
(18
|
)
|
|
|
(840
|
)
|
|
|
|
|
|
|
Total interest expense
|
|
$
|
6,200
|
|
|
$
|
3,885
|
|
|
$
|
10,570
|
|
|
$
|
9,500
|
|
|
|
|
|
Note K.
|
Commitments
and contingencies
|
Severance agreements. The Company has entered into
severance and change of control agreements with all of its
officers. The current annual salaries for the Companys
officers covered under such agreements total approximately
$1.9 million.
Indemnifications. The Company has agreed to
indemnify its directors and officers, with respect to claims and
damages arising from certain acts or omissions taken in such
capacity.
Legal actions. The Company is a party to proceedings
and claims incidental to its business. While many of these
matters involve inherent uncertainty, the Company believes that
the amount of the liability, if any, ultimately incurred with
respect to any such proceedings or claims will not have a
material adverse effect on the Companys consolidated
financial position as a whole or on its liquidity, capital
resources or future results of operations. The Company will
continue to evaluate proceedings and claims involving the
Company on a
quarter-by-quarter
basis and will establish and adjust any reserves as appropriate
to reflect its assessment of the then current status of the
matters.
Acquisition commitments. In connection with the
acquisition of the Henry Entities, the Company agreed to pay
certain employees, who were formerly employed by the Henry
Entities, bonuses of approximately $11.0 million in the
aggregate at each of the first and second anniversaries of the
closing of the acquisition, respectively. Except as described
below, these employees must remain employed with the Company to
receive the bonus. A former Henry Entities employee who is
otherwise entitled to a full bonus will receive the full bonus
(i) if the Company terminates the employee without cause,
(ii) upon the death or disability of such employee or
(iii) upon a change in control of the Company. If any such
employee resigns or is terminated for cause, the employee will
not receive the bonus and, subject to certain conditions, the
Company will be required to reimburse the sellers in the
acquisition of the Henry Entities 65 percent of the bonus
amount not paid to the employee. The Company will reflect the
bonus amounts to be paid to these employees as a period cost,
which will be included in the Companys results of
operations over the period earned. Amounts that ultimately are
determined to be paid to the sellers will be treated as a
contingent purchase price and reflected as an
adjustment to the purchase price. During the three and six
months ended June 30, 2009, the Company recognized
$2.8 million and $5.3 million, respectively, of this
obligation in its results of operations.
F-29
Daywork commitments. The Company periodically enters
into contractual arrangements under which the Company is
committed to expend funds to drill wells in the future,
including agreements to secure drilling rig services, which
require the Company to make future minimum payments to the rig
operators. The Company records drilling commitments in the
periods in which well capital is incurred or rig services are
provided. The following table summarizes the Companys
future drilling commitments at June 30, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by period
|
|
|
|
|
|
|
Less than
|
|
|
1-3
|
|
|
3-5
|
|
|
More than
|
|
|
|
Total
|
|
|
1 year
|
|
|
years
|
|
|
years
|
|
|
5 years
|
|
|
|
|
Daywork drilling contracts
|
|
$
|
299
|
|
|
$
|
299
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Daywork drilling contracts with related
partiesa
|
|
|
1,000
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daywork drilling contracts assumed in the Henry Properties
acquisitionb
|
|
|
1,629
|
|
|
|
1,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual drilling commitments
|
|
$
|
2,928
|
|
|
$
|
2,928
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
(a)
|
|
Consists of daywork drilling
contracts with Silver Oak Drilling, LLC, an affiliate of Chase
Oil Corporation.
|
|
|
|
(b)
|
|
A major oil and gas company which
owns an interest in the wells being drilled and the Company are
parties to these contracts. Only the Companys 25% share of
the contract obligation has been reflected above.
|
Operating leases. The Company leases vehicles,
equipment and office facilities under non-cancellable operating
leases. Lease payments associated with these operating leases
for the three months ended June 30, 2009 and 2008 were
approximately $582,000 and $116,000, respectively, and
$1,253,000 and $280,000 for the six months ended June 30,
2009 and 2008, respectively. Future minimum lease commitments
under non-cancellable operating leases at June 30, 2009 are
as follows (in thousands):
|
|
|
|
|
Remaining 2009
|
|
$
|
523
|
|
2010
|
|
|
1,077
|
|
2011
|
|
|
1,083
|
|
2012
|
|
|
1,077
|
|
2013
|
|
|
1,084
|
|
Thereafter
|
|
|
3,261
|
|
|
|
|
|
|
Total
|
|
$
|
8,105
|
|
|
|
The Company accounts for income taxes in accordance with the
provisions of SFAS No. 109, Accounting for Income
Taxes. The Company and its subsidiaries file federal
corporate income tax returns on a consolidated basis. The tax
returns and the amount of taxable income or loss are subject to
examination by federal and state taxing authorities. In
determining the interim period income tax provision, the Company
utilizes an estimated annual effective tax rate.
The Company adopted the provisions of FASB Interpretation
No. 48, Accounting for Uncertainty in Income Taxes,
an interpretation of FASB Statement No. 109,
Accounting for Income Taxes, on January 1, 2007. At
the time of adoption and at June 30, 2009, the Company did
not have any significant uncertain tax positions requiring
recognition in the financial statements. The tax years 2004
through 2008 remain subject to examination by major tax
jurisdictions.
F-30
The FASB issued
FIN No. 48-1,
Definition of Settlement in FASB Interpretation No. 48
(FIN No. 48-1),
to clarify when a tax position is effectively settled.
FIN No. 48-1
provides guidance in determining the proper timing for
recognizing tax benefits and applying the new information
relevant to the technical merits of a tax position obtained
during a tax authority examination.
FIN No. 48-1
provides criteria to determine whether a tax position is
effectively settled after completion of a tax authority
examination, even if the potential legal obligation remains
under the statute of limitations. The Companys adoption of
this pronouncement did not have a significant effect on its
consolidated financial statements.
Income tax provision. The Companys income tax
provision and amounts separately allocated were attributable to
the following items for the three and six months ended
June 30, 2009 and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Income (loss) from operations
|
|
$
|
(25,691
|
)
|
|
$
|
(9,169
|
)
|
|
$
|
(33,797
|
)
|
|
$
|
5,199
|
|
Changes in stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred hedge losses
|
|
|
|
|
|
|
(10,123
|
)
|
|
|
|
|
|
|
(12,705
|
)
|
Net settlement losses included in earnings
|
|
|
|
|
|
|
5,195
|
|
|
|
|
|
|
|
8,127
|
|
Tax benefits related to stock-based compensation
|
|
|
(2,188
|
)
|
|
|
(1,553
|
)
|
|
|
(2,992
|
)
|
|
|
(2,146
|
)
|
|
|
|
|
|
|
|
|
$
|
(27,879
|
)
|
|
$
|
(15,650
|
)
|
|
$
|
(36,789
|
)
|
|
$
|
(1,525
|
)
|
|
|
The Companys income tax provision (benefit) attributable
to income (loss) from operations consisted of the following for
the three and six months ended June 30, 2009 and 2008 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
$
|
2,856
|
|
|
$
|
523
|
|
|
$
|
5,294
|
|
|
$
|
585
|
|
U.S. state and local
|
|
|
381
|
|
|
|
98
|
|
|
|
708
|
|
|
|
110
|
|
|
|
|
|
|
|
|
|
|
3,237
|
|
|
|
621
|
|
|
|
6,002
|
|
|
|
695
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
|
(25,518
|
)
|
|
|
(8,201
|
)
|
|
|
(35,103
|
)
|
|
|
3,790
|
|
U.S. state and local
|
|
|
(3,410
|
)
|
|
|
(1,589
|
)
|
|
|
(4,696
|
)
|
|
|
714
|
|
|
|
|
|
|
|
|
|
|
(28,928
|
)
|
|
|
(9,790
|
)
|
|
|
(39,799
|
)
|
|
|
4,504
|
|
|
|
|
|
|
|
|
|
$
|
(25,691
|
)
|
|
$
|
(9,169
|
)
|
|
$
|
(33,797
|
)
|
|
$
|
5,199
|
|
|
|
F-31
The reconciliation between the tax expense computed by
multiplying pretax income (loss) by the U.S. federal
statutory rate and the reported amounts of income tax expense
(benefit) is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Income (loss) at U.S. federal statutory rate
|
|
$
|
(20,618
|
)
|
|
$
|
(8,256
|
)
|
|
$
|
(28,084
|
)
|
|
$
|
4,600
|
|
State income taxes (net of federal tax effect)
|
|
|
(1,969
|
)
|
|
|
(968
|
)
|
|
|
(2,592
|
)
|
|
|
537
|
|
Nondeductible expense & other
|
|
|
(3,104
|
)
|
|
|
55
|
|
|
|
(3,121
|
)
|
|
|
62
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
|
$
|
(25,691
|
)
|
|
$
|
(9,169
|
)
|
|
$
|
(33,797
|
)
|
|
$
|
5,199
|
|
|
|
|
|
Note M.
|
Related party
transactions
|
Consulting Agreement. On June 30, 2009, Steven
L. Beal, the Companys President and Chief Operating
Officer, retired from such positions. Mr. Beal was recently
re-elected to the Companys Board of Directors and is
continuing to serve as a member of the Companys Board of
Directors. On June 9, 2009, the Company entered into a
consulting agreement (the Consulting Agreement )
with Mr. Beal, under which Mr. Beal began serving as a
consultant to the Company on July 1, 2009. Either the
Company or Mr. Beal may terminate the consulting
relationship at any time by giving ninety days written notice to
the other party; however, the Company may terminate the
relationship immediately for cause. During the term of the
consulting relationship, Mr. Beal will receive a consulting
fee of $20,000 per month and a monthly reimbursement for his
medical and dental coverage costs. If Mr. Beal dies during
the term of the Consulting Agreement, his estate will receive a
$60,000 lump sum payment.
Chase Group transactions. The Company incurred
charges from Mack Energy Corporation (MEC), an
affiliate of Chase Oil Corporation (Chase Oil), of
approximately $0.4 million and $0.3 million for the
three months ended June 30, 2009 and 2008, respectively,
and $0.7 million and $1.5 million for the six months
ended June 30, 2009 and 2008, respectively, for services
rendered in the ordinary course of business.
The Company had $112,000 in outstanding receivables due from MEC
at June 30, 2009 and no outstanding receivables due from
MEC at December 31, 2008. The Company had $49,000 in
outstanding payables to MEC at June 30, 2009 and no
outstanding payables to MEC at December 31, 2008.
Saltwater disposal services agreement. Among the
assets the Company acquired from Chase Oil is an undivided
interest in a saltwater gathering and disposal system, which is
owned and maintained under a written agreement among the Company
and Chase Oil and certain of its affiliates, and under which the
Company as operator gathers and disposes of produced water. The
system is owned jointly by the Company and Chase Oil and its
affiliates in undivided ownership percentages, which are
annually redetermined as of January 1 on the basis of each
partys percentage contribution of the total volume of
produced water disposed of through the system during the prior
calendar year. At January 1, 2009, the Company owned 95.4%
of the system and Chase Oil and its affiliates owned 4.6%.
Other related party transactions. The Company also
has engaged in transactions with certain other affiliates of
Chase Oil, Caza Energy LLC (Caza) and certain other
parties thereto
F-32
(collectively the Chase Group), including a drilling
contractor, an oilfield services company, a supply company, a
drilling fluids supply company, a pipe and tubing supplier, a
fixed base operator of aircraft services and a software company.
The Company incurred charges from these related party vendors of
approximately $6.2 million and $5.7 million for the
three months ended June 30, 2009 and 2008, respectively,
and $12.6 million and $13.1 million for the six months
ended June 30, 2009 and 2008, respectively.
The Company had outstanding amounts payable to these related
party vendors identified above of approximately
$1.0 million and $21,000 at June 30, 2009 and
December 31, 2008, respectively, which are reflected in
accounts payablerelated parties in the accompanying
consolidated balance sheets.
Overriding royalty and royalty interests. Certain
members of the Chase Group own overriding royalty interests in
certain of the Chase Group properties. The amount paid
attributable to such interests was approximately $258,000 and
$816,000 for the three months ended June 30, 2009 and 2008,
respectively, and $499,000 and $1,600,000 for the six months
ended June 30, 2009 and 2008, respectively. The Company
owed these owners royalty payments of approximately $132,000 and
$146,000 at June 30, 2009 and December 31, 2008,
respectively.
Royalties are paid on certain properties located in Andrews
County, Texas to a partnership of which one of the
Companys directors is the general partner and owner of a
3.5% partnership interest. The Company paid this partnership
approximately $30,000 and $81,000 for the three months ended
June 30, 2009 and 2008, respectively, and $56,000 and
$164,000 for the six months ended June 30, 2009 and 2008,
respectively. The Company owed this partnership royalty payments
of approximately $13,000 at June 30, 2009 and
December 31, 2008.
In April 2005, the Company acquired certain working interests in
46,861 gross (26,908 net) acres located in Culberson
County, Texas from an entity partially owned by a person who
became an executive officer of the Company immediately following
such acquisition. In connection with this acquisition, such
entity retained a 2% overriding royalty interest in the acquired
properties, which overriding royalty interest later became owned
equally by such officer and a non-officer employee of the
Company. During the three and six months ended June 30,
2009 and 2008, no payments were made related to this overriding
royalty interest. Effective March 31, 2008, the executive
officer involved in this matter resigned from the Company.
Working interests owned by employees. As part of the
Henry Properties acquisition, the Company purchased oil and
natural gas properties in which certain employees owned
interests. The Company distributed revenues to these employees
totaling approximately $32,000 and $62,000 for the three and six
months ended June 30, 2009, respectively, and received
joint interest payments from these employees of approximately
$245,000 and $884,000 for the three and six months ended
June 30, 2009, respectively. At June 30, 2009 and
December 31, 2008, the Company was owed by these employees
approximately $63,000 and $300,000, respectively, which is
reflected in accounts receivablerelated parties.
|
|
Note N.
|
Net income
(loss) per share
|
Basic net income (loss) per share is computed by dividing net
income (loss) applicable to common shareholders by the weighted
average number of common shares treated as outstanding for the
period. All capital options were exercised prior to
March 31, 2008.
F-33
The computation of diluted income (loss) per share reflects the
potential dilution that could occur if securities or other
contracts to issue common stock that are dilutive to income
(loss) were exercised or converted into common stock or resulted
in the issuance of common stock that would then share in the
earnings of the Company. These amounts include unexercised stock
options and restricted stock (as issued under the Plan and
described in Note G). Potentially dilutive effects are
calculated using the treasury stock method.
The following table is a reconciliation of the basic weighted
average common shares outstanding to diluted weighted average
common shares outstanding (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
|
June 30
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
84,799
|
|
|
|
75,665
|
|
|
|
84,665
|
|
|
|
75,569
|
|
Dilutive capital options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
Dilutive common stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,206
|
|
Dilutive restricted stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
247
|
|
|
|
|
|
|
|
Diluted
|
|
|
84,799
|
|
|
|
75,665
|
|
|
|
84,665
|
|
|
|
77,034
|
|
|
|
For the three and six months ended June 30, 2009, the
computation of diluted net loss per share was anti-dilutive due
to the net loss reported by the Company; therefore, the amounts
reported for basic and diluted net loss per share were the same.
For the three and six months ended June 30, 2009,
492,810 shares of restricted stock, respectively, and
2,403,336 stock options, respectively, were not included in the
computation of diluted loss per share, as inclusion of these
items would be anti-dilutive.
For the three months ended June 30, 2008, the computation
of diluted net loss per share was anti-dilutive due to the net
loss reported by the Company; therefore, the amounts reported
for basic and diluted net loss per share were the same. For the
three and six months ended June 30, 2008, 379,794 and
24,914 shares of restricted stock, respectively, and
3,043,971 and 305,278 stock options, respectively, were not
included in the computation of diluted loss per share, as
inclusion of these items would be anti-dilutive.
|
|
Note O.
|
Other current
liabilities
|
The following table provides the components of the
Companys other current liabilities at June 30, 2009
and December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Other current liabilities:
|
|
|
|
|
|
|
|
|
Accrued production costs
|
|
$
|
18,229
|
|
|
$
|
15,489
|
|
Payroll related matters
|
|
|
11,843
|
|
|
|
11,290
|
|
Accrued interest
|
|
|
2,299
|
|
|
|
353
|
|
Asset retirement obligations
|
|
|
2,706
|
|
|
|
2,611
|
|
Other
|
|
|
3,072
|
|
|
|
8,314
|
|
|
|
|
|
|
|
Other current liabilities
|
|
$
|
38,149
|
|
|
$
|
38,057
|
|
|
|
F-34
|
|
Note P.
|
Subsidiary
guarantors
|
All of the Companys wholly-owned subsidiaries have fully
and unconditionally guaranteed the Credit Facility of the
Company (see Note J). In accordance with practices accepted
by the SEC, the Company has prepared Consolidating Condensed
Financial Statements in order to quantify the assets and results
of operations of such subsidiaries as subsidiary guarantors. The
following Consolidating Condensed Balance Sheets at
June 30, 2009 and December 31, 2008, and Consolidating
Statements of Operations for the three and six months ended
June 30, 2009 and 2008 and Consolidating Condensed
Statements of Cash Flows for the six months ended June 30,
2009 and 2008, present financial information for Concho
Resources Inc. as the Parent on a stand-alone basis (carrying
any investments in subsidiaries under the equity method),
financial information for the subsidiary guarantors on a
stand-alone basis (carrying any investment in non-guarantor
subsidiaries under the equity method), and the consolidation and
elimination entries necessary to arrive at the information for
the Company on a consolidated basis. All current and deferred
taxes are recorded on Concho Resources Inc., as the subsidiaries
are
flow-through
entities for tax purposes. The subsidiary guarantors are not
restricted from making distributions to the Company.
Consolidating
condensed balance sheet
June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Assets
|
Accounts receivablerelated parties
|
|
$
|
1,992,996
|
|
|
$
|
1,641,913
|
|
|
$
|
(3,634,735
|
)
|
|
$
|
174
|
|
Other current assets
|
|
|
34,085
|
|
|
|
133,020
|
|
|
|
|
|
|
|
167,105
|
|
Total oil and natural gas properties, net
|
|
|
|
|
|
|
2,472,023
|
|
|
|
|
|
|
|
2,472,023
|
|
Other property and equipment, net
|
|
|
|
|
|
|
15,143
|
|
|
|
|
|
|
|
15,143
|
|
Investment in subsidiaries
|
|
|
742,592
|
|
|
|
|
|
|
|
(742,592
|
)
|
|
|
|
|
Total other long-term assets
|
|
|
45,426
|
|
|
|
64,928
|
|
|
|
|
|
|
|
110,354
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,815,099
|
|
|
$
|
4,327,027
|
|
|
$
|
(4,377,327
|
)
|
|
$
|
2,764,799
|
|
|
|
|
|
|
|
|
Liabilities and equity
|
Accounts payablerelated parties
|
|
$
|
264,149
|
|
|
$
|
3,371,938
|
|
|
$
|
(3,634,735
|
)
|
|
$
|
1,352
|
|
Other current liabilities
|
|
|
21,234
|
|
|
|
196,845
|
|
|
|
|
|
|
|
218,079
|
|
Other long-term liabilities
|
|
|
580,161
|
|
|
|
15,652
|
|
|
|
|
|
|
|
595,813
|
|
Long-term debt
|
|
|
660,000
|
|
|
|
|
|
|
|
|
|
|
|
660,000
|
|
Equity
|
|
|
1,289,555
|
|
|
|
742,592
|
|
|
|
(742,592
|
)
|
|
|
1,289,555
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
2,815,099
|
|
|
$
|
4,327,027
|
|
|
$
|
(4,377,327
|
)
|
|
$
|
2,764,799
|
|
|
|
F-35
Consolidating
condensed balance sheet
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Assets
|
Accounts receivablerelated parties
|
|
$
|
2,500,186
|
|
|
$
|
1,432,829
|
|
|
$
|
(3,932,701
|
)
|
|
$
|
314
|
|
Other current assets
|
|
|
120,406
|
|
|
|
158,063
|
|
|
|
|
|
|
|
278,469
|
|
Total oil and natural gas properties, net
|
|
|
|
|
|
|
2,386,584
|
|
|
|
|
|
|
|
2,386,584
|
|
Other property and equipment, net
|
|
|
|
|
|
|
14,820
|
|
|
|
|
|
|
|
14,820
|
|
Investment in subsidiaries
|
|
|
734,969
|
|
|
|
|
|
|
|
(734,969
|
)
|
|
|
|
|
Total other long-term assets
|
|
|
73,538
|
|
|
|
61,478
|
|
|
|
|
|
|
|
135,016
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,429,099
|
|
|
$
|
4,053,774
|
|
|
$
|
(4,667,670
|
)
|
|
$
|
2,815,203
|
|
|
|
|
|
|
|
|
Liabilities and equity
|
Accounts payablerelated parties
|
|
$
|
860,758
|
|
|
$
|
3,072,255
|
|
|
$
|
(3,932,701
|
)
|
|
$
|
312
|
|
Other current liabilities
|
|
|
39,424
|
|
|
|
231,082
|
|
|
|
|
|
|
|
270,506
|
|
Other long-term liabilities
|
|
|
573,763
|
|
|
|
15,468
|
|
|
|
|
|
|
|
589,231
|
|
Long-term debt
|
|
|
630,000
|
|
|
|
|
|
|
|
|
|
|
|
630,000
|
|
Equity
|
|
|
1,325,154
|
|
|
|
734,969
|
|
|
|
(734,969
|
)
|
|
|
1,325,154
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
3,429,099
|
|
|
$
|
4,053,774
|
|
|
$
|
(4,667,670
|
)
|
|
$
|
2,815,203
|
|
|
|
Consolidating
condensed statement of operations
For the three months ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Total operating revenues
|
|
$
|
|
|
|
$
|
127,332
|
|
|
$
|
|
|
|
$
|
127,332
|
|
Total operating costs and expenses
|
|
|
(72,075
|
)
|
|
|
(108,146
|
)
|
|
|
|
|
|
|
(180,221
|
)
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(72,075
|
)
|
|
|
19,186
|
|
|
|
|
|
|
|
(52,889
|
)
|
Interest expense
|
|
|
(6,200
|
)
|
|
|
|
|
|
|
|
|
|
|
(6,200
|
)
|
Other, net
|
|
|
19,366
|
|
|
|
180
|
|
|
|
(19,366
|
)
|
|
|
180
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(58,909
|
)
|
|
|
19,366
|
|
|
|
(19,366
|
)
|
|
|
(58,909
|
)
|
Income tax benefit
|
|
|
25,691
|
|
|
|
|
|
|
|
|
|
|
|
25,691
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(33,218
|
)
|
|
$
|
19,366
|
|
|
$
|
(19,366
|
)
|
|
$
|
(33,218
|
)
|
|
|
F-36
Consolidating
condensed statement of operations
For the three months ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Total operating revenues
|
|
$
|
(13,293
|
)
|
|
$
|
150,676
|
|
|
$
|
|
|
|
$
|
137,383
|
|
Total operating costs and expenses
|
|
|
(71
|
)
|
|
|
(157,327
|
)
|
|
|
|
|
|
|
(157,398
|
)
|
|
|
|
|
|
|
Loss from operations
|
|
|
(13,364
|
)
|
|
|
(6,651
|
)
|
|
|
|
|
|
|
(20,015
|
)
|
Interest expense
|
|
|
(3,885
|
)
|
|
|
|
|
|
|
|
|
|
|
(3,885
|
)
|
Other, net
|
|
|
(6,340
|
)
|
|
|
311
|
|
|
|
6,340
|
|
|
|
311
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(23,589
|
)
|
|
|
(6,340
|
)
|
|
|
6,340
|
|
|
|
(23,589
|
)
|
Income tax benefit
|
|
|
9,169
|
|
|
|
|
|
|
|
|
|
|
|
9,169
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(14,420
|
)
|
|
$
|
(6,340
|
)
|
|
$
|
6,340
|
|
|
$
|
(14,420
|
)
|
|
|
Consolidating
condensed statement of operations
For the six months ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Total operating revenues
|
|
$
|
|
|
|
$
|
213,334
|
|
|
$
|
|
|
|
$
|
213,334
|
|
Total operating costs and expenses
|
|
|
(77,293
|
)
|
|
|
(205,563
|
)
|
|
|
|
|
|
|
(282,856
|
)
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(77,293
|
)
|
|
|
7,771
|
|
|
|
|
|
|
|
(69,522
|
)
|
Interest expense
|
|
|
(10,570
|
)
|
|
|
|
|
|
|
|
|
|
|
(10,570
|
)
|
Other, net
|
|
|
7,623
|
|
|
|
(148
|
)
|
|
|
(7,623
|
)
|
|
|
(148
|
)
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(80,240
|
)
|
|
|
7,623
|
|
|
|
(7,623
|
)
|
|
|
(80,240
|
)
|
Income tax benefit
|
|
|
33,797
|
|
|
|
|
|
|
|
|
|
|
|
33,797
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(46,443
|
)
|
|
$
|
7,623
|
|
|
$
|
(7,623
|
)
|
|
$
|
(46,443
|
)
|
|
|
Consolidating
condensed statement of operations
For the six months ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Total operating revenues
|
|
$
|
(20,795
|
)
|
|
$
|
264,889
|
|
|
$
|
|
|
|
$
|
244,094
|
|
Total operating costs and expenses
|
|
|
(144
|
)
|
|
|
(222,637
|
)
|
|
|
|
|
|
|
(222,781
|
)
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(20,939
|
)
|
|
|
42,252
|
|
|
|
|
|
|
|
21,313
|
|
Interest expense
|
|
|
(9,500
|
)
|
|
|
|
|
|
|
|
|
|
|
(9,500
|
)
|
Other, net
|
|
|
43,583
|
|
|
|
1,331
|
|
|
|
(43,583
|
)
|
|
|
1,331
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
13,144
|
|
|
|
43,583
|
|
|
|
(43,583
|
)
|
|
|
13,144
|
|
Income tax expense
|
|
|
(5,199
|
)
|
|
|
|
|
|
|
|
|
|
|
(5,199
|
)
|
|
|
|
|
|
|
Net income
|
|
$
|
7,945
|
|
|
$
|
43,583
|
|
|
$
|
(43,583
|
)
|
|
$
|
7,945
|
|
|
|
F-37
Consolidating
condensed statement of cash flows
For the six months ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(93,214
|
)
|
|
$
|
211,446
|
|
|
$
|
|
|
|
$
|
118,232
|
|
Net cash flows provided by (used in) investing activities
|
|
|
56,534
|
|
|
|
(219,362
|
)
|
|
|
|
|
|
|
(162,828
|
)
|
Net cash flows provided by (used in) financing activities
|
|
|
36,731
|
|
|
|
(6,806
|
)
|
|
|
|
|
|
|
29,925
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
51
|
|
|
|
(14,722
|
)
|
|
|
|
|
|
|
(14,671
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
|
|
|
|
17,752
|
|
|
|
|
|
|
|
17,752
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
51
|
|
|
$
|
3,030
|
|
|
$
|
|
|
|
$
|
3,081
|
|
|
|
Consolidating
condensed statement of cash flows
For the six months ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Net cash flows provided by operating activities
|
|
$
|
39,505
|
|
|
$
|
123,443
|
|
|
$
|
|
|
|
$
|
162,948
|
|
Net cash flows used in investing activities
|
|
|
(16,387
|
)
|
|
|
(125,740
|
)
|
|
|
|
|
|
|
(142,127
|
)
|
Net cash flows provided by (used in) financing activities
|
|
|
(22,774
|
)
|
|
|
3,245
|
|
|
|
|
|
|
|
(19,529
|
)
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
344
|
|
|
|
948
|
|
|
|
|
|
|
|
1,292
|
|
Cash and cash equivalents at beginning of period
|
|
|
107
|
|
|
|
30,317
|
|
|
|
|
|
|
|
30,424
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
451
|
|
|
$
|
31,265
|
|
|
$
|
|
|
|
$
|
31,716
|
|
|
|
F-38
|
|
Note Q.
|
Subsequent
events
|
The Company has evaluated subsequent events through
August 6, 2009, which was the date these financial
statements were issued.
|
|
Note R.
|
Supplementary
information
|
Capitalized costs (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Oil and natural gas properties:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
2,608,138
|
|
|
$
|
2,316,330
|
|
Unproved
|
|
|
277,137
|
|
|
|
377,244
|
|
Less: accumulated depletion
|
|
|
(413,252
|
)
|
|
|
(306,990
|
)
|
|
|
|
|
|
|
Net capitalized costs for oil and natural gas properties
|
|
$
|
2,472,023
|
|
|
$
|
2,386,584
|
|
|
|
Costs incurred for oil and natural gas producing
activitiesa
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Property acquisition
costs:b
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
(68
|
)
|
|
$
|
(104
|
)
|
|
$
|
(1,008
|
)
|
|
$
|
1
|
|
Unproved
|
|
|
3,361
|
|
|
|
587
|
|
|
|
4,582
|
|
|
|
1,349
|
|
Exploration
|
|
|
61,131
|
|
|
|
21,136
|
|
|
|
84,940
|
|
|
|
50,701
|
|
Development
|
|
|
31,450
|
|
|
|
46,365
|
|
|
|
115,229
|
|
|
|
71,242
|
|
|
|
|
|
|
|
Total costs incurred for oil and natural gas properties
|
|
$
|
95,874
|
|
|
$
|
67,984
|
|
|
$
|
203,743
|
|
|
$
|
123,293
|
|
|
|
|
|
|
(a)
|
|
The costs incurred for oil and
natural gas producing activities includes the following amounts
of asset retirement obligations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
Proved property acquisition costs
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Exploration costs
|
|
|
52
|
|
|
|
168
|
|
|
|
220
|
|
|
|
194
|
|
Development costs
|
|
|
(3,878
|
)
|
|
|
1,245
|
|
|
|
(2,727
|
)
|
|
|
443
|
|
|
|
|
|
|
|
Total
|
|
$
|
(3,826
|
)
|
|
$
|
1,413
|
|
|
$
|
(2,507
|
)
|
|
$
|
637
|
|
|
|
|
|
|
(b)
|
|
During the three and six months
ended June 30, 2009, the Company adjusted the purchase
price allocation related to the acquisition of the Henry
Properties. This adjustment reduced the proved acquisition costs
by $80,000 and $1,020,000 during the three and six months ended
June 30, 2009, respectively, while the unproved acquisition
costs were decreased by $298,000 and increased by $293,000
during the three and six months ended June 30, 2009,
respectively.
|
F-39
Report of
independent registered public accounting firm
Board of Directors and Stockholders
Concho Resources Inc.
We have audited the accompanying consolidated balance sheets of
Concho Resources Inc. (a Delaware corporation) and subsidiaries
as of December 31, 2008 and 2007, and the related
consolidated statements of operations, stockholders equity
and cash flows for each of the three years in the period ended
December 31, 2008. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit also includes examining,
on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing
the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Concho Resources Inc. and subsidiaries as of
December 31, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2008, in conformity with
accounting principles generally accepted in the United States of
America.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States),
Concho Resources Inc.s internal control over financial
reporting as of December 31, 2008 (not included herein),
based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO) and
our report dated February 27, 2009 expressed an unqualified
opinion thereon.
February 27, 2009 (except for the subsidiary guarantor
disclosure in Note Q, as to which the date is
September 9, 2009)
Tulsa, Oklahoma
F-40
Concho Resources
Inc.
Consolidated balance sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
(in thousands, except share and per share data)
|
|
2008
|
|
|
2007
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
17,752
|
|
|
$
|
30,424
|
|
Accounts receivable, net of allowance for doubtful accounts:
|
|
|
|
|
|
|
|
|
Oil and gas
|
|
|
48,793
|
|
|
|
36,735
|
|
Joint operations and other
|
|
|
92,833
|
|
|
|
21,183
|
|
Related parties
|
|
|
314
|
|
|
|
|
|
Derivative instruments
|
|
|
113,149
|
|
|
|
1,866
|
|
Deferred income taxes
|
|
|
|
|
|
|
13,502
|
|
Prepaid costs and other
|
|
|
5,942
|
|
|
|
4,273
|
|
|
|
|
|
|
|
Total current assets
|
|
|
278,783
|
|
|
|
107,983
|
|
|
|
|
|
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
Oil and gas properties, successful efforts method
|
|
|
2,693,574
|
|
|
|
1,555,018
|
|
Accumulated depletion and depreciation
|
|
|
(306,990
|
)
|
|
|
(167,109
|
)
|
|
|
|
|
|
|
Total oil and gas properties, net
|
|
|
2,386,584
|
|
|
|
1,387,909
|
|
Other property and equipment, net
|
|
|
14,820
|
|
|
|
7,085
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
2,401,404
|
|
|
|
1,394,994
|
|
|
|
|
|
|
|
Deferred loan costs, net
|
|
|
15,701
|
|
|
|
3,426
|
|
Inventory
|
|
|
19,956
|
|
|
|
1,459
|
|
Intangible asset, netoperating rights
|
|
|
37,768
|
|
|
|
|
|
Noncurrent derivative instruments
|
|
|
61,157
|
|
|
|
|
|
Other assets
|
|
|
434
|
|
|
|
367
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,815,203
|
|
|
$
|
1,508,229
|
|
|
|
|
|
|
|
Liabilities and stockholders equity
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
7,462
|
|
|
$
|
14,222
|
|
Related parties
|
|
|
312
|
|
|
|
2,119
|
|
Other current liabilities:
|
|
|
|
|
|
|
|
|
Bank overdrafts
|
|
|
9,434
|
|
|
|
5,651
|
|
Revenue payable
|
|
|
22,286
|
|
|
|
14,494
|
|
Accrued and prepaid drilling costs
|
|
|
154,196
|
|
|
|
39,276
|
|
Derivative instruments
|
|
|
1,866
|
|
|
|
36,414
|
|
Deferred income taxes
|
|
|
37,205
|
|
|
|
|
|
Current portion of long-term debt
|
|
|
|
|
|
|
2,000
|
|
Other current liabilities
|
|
|
38,057
|
|
|
|
14,466
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
270,818
|
|
|
|
128,642
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
630,000
|
|
|
|
325,404
|
|
Noncurrent derivative instruments
|
|
|
|
|
|
|
10,517
|
|
Deferred income taxes
|
|
|
573,763
|
|
|
|
259,070
|
|
Asset retirement obligations and other long-term liabilities
|
|
|
15,468
|
|
|
|
9,198
|
|
Commitments and contingencies (Note K)
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value; 10,000,000 shares
authorized; none issued and outstanding at December 31,
2008 and 2007
|
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; 300,000,000 shares
authorized; 84,828,824 and 75,832,310 shares issued at
December 31, 2008 and 2007, respectively
|
|
|
85
|
|
|
|
76
|
|
Additional paid-in capital
|
|
|
1,009,025
|
|
|
|
752,380
|
|
Notes receivable from employees
|
|
|
|
|
|
|
(330
|
)
|
Retained earnings
|
|
|
316,169
|
|
|
|
37,467
|
|
Accumulated other comprehensive loss
|
|
|
|
|
|
|
(14,195
|
)
|
Treasury stock, at cost; 3,142 and no shares at
December 31, 2008 and 2007, respectively
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,325,154
|
|
|
|
775,398
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
2,815,203
|
|
|
$
|
1,508,229
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-41
Concho Resources
Inc.
Consolidated statements of operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
(in thousands, except per share
amounts)
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
390,945
|
|
|
$
|
195,596
|
|
|
$
|
131,773
|
|
Natural gas sales
|
|
|
142,844
|
|
|
|
98,737
|
|
|
|
66,517
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
533,789
|
|
|
|
294,333
|
|
|
|
198,290
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
91,234
|
|
|
|
54,267
|
|
|
|
37,822
|
|
Exploration and abandonments
|
|
|
38,468
|
|
|
|
29,098
|
|
|
|
5,612
|
|
Depreciation, depletion and amortization
|
|
|
123,912
|
|
|
|
76,779
|
|
|
|
60,722
|
|
Accretion of discount on asset retirement obligations
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
Impairments of long-lived assets
|
|
|
18,417
|
|
|
|
7,267
|
|
|
|
9,891
|
|
General and administrative (including non-cash stock-based
compensation of $5,223, $3,841 and $9,144 for the years ended
December 31, 2008, 2007 and 2006, respectively)
|
|
|
40,776
|
|
|
|
25,177
|
|
|
|
21,721
|
|
Bad debt expense
|
|
|
2,905
|
|
|
|
|
|
|
|
|
|
Contract drilling feesstacked rigs
|
|
|
|
|
|
|
4,269
|
|
|
|
|
|
Ineffective portion of cash flow hedges
|
|
|
(1,336
|
)
|
|
|
821
|
|
|
|
(1,193
|
)
|
(Gain) loss on derivatives not designated as hedges
|
|
|
(249,870
|
)
|
|
|
20,274
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
65,395
|
|
|
|
218,396
|
|
|
|
134,862
|
|
|
|
|
|
|
|
Income from operations
|
|
|
468,394
|
|
|
|
75,937
|
|
|
|
63,428
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(29,039
|
)
|
|
|
(36,042
|
)
|
|
|
(30,567
|
)
|
Other, net
|
|
|
1,432
|
|
|
|
1,484
|
|
|
|
1,186
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(27,607
|
)
|
|
|
(34,558
|
)
|
|
|
(29,381
|
)
|
|
|
|
|
|
|
Income before income taxes
|
|
|
440,787
|
|
|
|
41,379
|
|
|
|
34,047
|
|
Income tax expense
|
|
|
(162,085
|
)
|
|
|
(16,019
|
)
|
|
|
(14,379
|
)
|
|
|
|
|
|
|
Net income
|
|
|
278,702
|
|
|
|
25,360
|
|
|
|
19,668
|
|
Preferred stock dividends
|
|
|
|
|
|
|
(45
|
)
|
|
|
(1,244
|
)
|
Effect of induced conversion of preferred stock
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
|
|
|
|
Net income applicable to common shareholders
|
|
$
|
278,702
|
|
|
$
|
25,315
|
|
|
$
|
30,025
|
|
|
|
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
3.52
|
|
|
$
|
0.39
|
|
|
$
|
0.63
|
|
|
|
|
|
|
|
Weighted average shares used in basic earnings per share
|
|
|
79,206
|
|
|
|
64,316
|
|
|
|
47,287
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
3.46
|
|
|
$
|
0.38
|
|
|
$
|
0.59
|
|
|
|
|
|
|
|
Weighted average shares used in diluted earnings per share
|
|
|
80,587
|
|
|
|
66,309
|
|
|
|
50,729
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
receivable
|
|
|
Retained
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
6% Series A
|
|
|
|
|
|
|
|
|
Additional
|
|
|
from
|
|
|
earnings
|
|
|
other
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
preferred stock
|
|
|
Common stock
|
|
|
paid-in
|
|
|
officers and
|
|
|
(accumulated
|
|
|
comprehensive
|
|
|
Treasury stock
|
|
|
stockholders
|
|
(in thousands)
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
capital
|
|
|
employees
|
|
|
deficit)
|
|
|
income (loss)
|
|
|
Shares
|
|
|
Amount
|
|
|
equity
|
|
|
|
|
Balance at December 31, 2005
|
|
|
12,959
|
|
|
$
|
130
|
|
|
|
8,142
|
|
|
$
|
8
|
|
|
$
|
135,876
|
|
|
$
|
(9,012
|
)
|
|
$
|
(6,272
|
)
|
|
$
|
(11,060
|
)
|
|
|
|
|
|
$
|
|
|
|
$
|
109,670
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,668
|
|
Deferred hedge gains, net of tax of $4,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,736
|
|
|
|
|
|
|
|
|
|
|
|
7,736
|
|
Net settlement losses included in earnings, net of taxes of
$2,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,738
|
|
|
|
|
|
|
|
|
|
|
|
3,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,142
|
|
Issuance of subscribed units
|
|
|
4,518
|
|
|
|
45
|
|
|
|
2,259
|
|
|
|
2
|
|
|
|
45,329
|
|
|
|
(3,158
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,218
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
578
|
|
|
|
1
|
|
|
|
577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
578
|
|
Conversion of preferred stock
|
|
|
(17,477
|
)
|
|
|
(175
|
)
|
|
|
13,106
|
|
|
|
13
|
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock for acquisition
|
|
|
|
|
|
|
|
|
|
|
34,795
|
|
|
|
35
|
|
|
|
384,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
384,336
|
|
Stock-based compensation for restricted stock
|
|
|
|
|
|
|
|
|
|
|
214
|
|
|
|
|
|
|
|
1,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,044
|
|
Cancellation of restricted stock
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,125
|
|
Stock-based compensation on issuance of units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
975
|
|
Accrued interestofficer and employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(688
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(688
|
)
|
6% Series A preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,244
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,244
|
)
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
59,093
|
|
|
|
59
|
|
|
|
575,389
|
|
|
|
(12,858
|
)
|
|
|
12,152
|
|
|
|
414
|
|
|
|
|
|
|
|
|
|
|
|
575,156
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,360
|
|
Deferred hedge losses, net of taxes of $13,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,579
|
)
|
|
|
|
|
|
|
|
|
|
|
(20,579
|
)
|
Net settlement losses included in earnings, net of taxes of
$3,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,970
|
|
|
|
|
|
|
|
|
|
|
|
5,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,751
|
|
Stock-based compensation for restricted stock
|
|
|
|
|
|
|
|
|
|
|
138
|
|
|
|
|
|
|
|
1,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,378
|
|
Cancellation of restricted stock
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,463
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,463
|
|
Amendment of certain outstanding stock options due to 409A
modification
|
|
|
|
|
|
|
|
|
|
|
83
|
|
|
|
|
|
|
|
(192
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(192
|
)
|
Issuance of common stock for acquisition obligation
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
650
|
|
Net proceeds from initial public equity offering
|
|
|
|
|
|
|
|
|
|
|
16,466
|
|
|
|
17
|
|
|
|
172,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172,709
|
|
Proceeds from notes receivableofficers and employees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,830
|
|
Accrued interestofficer and employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(302
|
)
|
6% Series A preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
75,832
|
|
|
|
76
|
|
|
|
752,380
|
|
|
|
(330
|
)
|
|
|
37,467
|
|
|
|
(14,195
|
)
|
|
|
|
|
|
|
|
|
|
|
775,398
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278,702
|
|
Deferred hedge losses, net of taxes of $3,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,864
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,864
|
)
|
Net settlement losses included in earnings, net of taxes of
$12,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,059
|
|
|
|
|
|
|
|
|
|
|
|
19,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
292,897
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
8,303
|
|
|
|
8
|
|
|
|
242,418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
242,426
|
|
Stock options exercised
|
|
|
|
|
|
|
|
|
|
|
612
|
|
|
|
1
|
|
|
|
5,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,391
|
|
Stock-based compensation for restricted stock
|
|
|
|
|
|
|
|
|
|
|
128
|
|
|
|
|
|
|
|
2,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,122
|
|
Cancellation of restricted stock
|
|
|
|
|
|
|
|
|
|
|
(46
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,101
|
|
Excess tax benefits related to stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,614
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,614
|
|
Proceeds from notes receivableemployees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
333
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
333
|
|
Accrued interestemployee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
(125
|
)
|
|
|
(125
|
)
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
|
|
|
$
|
|
|
|
|
84,829
|
|
|
$
|
85
|
|
|
$
|
1,009,025
|
|
|
$
|
|
|
|
$
|
316,169
|
|
|
$
|
|
|
|
|
3
|
|
|
$
|
(125
|
)
|
|
$
|
1,325,154
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
(in thousands)
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
278,702
|
|
|
$
|
25,360
|
|
|
$
|
19,668
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
123,912
|
|
|
|
76,779
|
|
|
|
60,722
|
|
Impairments of long-lived assets
|
|
|
18,417
|
|
|
|
7,267
|
|
|
|
9,891
|
|
Accretion of discount on asset retirement obligations
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
Exploration expense, including dry holes
|
|
|
35,328
|
|
|
|
25,009
|
|
|
|
3,387
|
|
Non-cash compensation expense
|
|
|
5,223
|
|
|
|
3,841
|
|
|
|
9,144
|
|
Deferred income taxes
|
|
|
153,484
|
|
|
|
13,716
|
|
|
|
12,618
|
|
Gain on sale of assets
|
|
|
(777
|
)
|
|
|
(368
|
)
|
|
|
(3
|
)
|
Ineffective portion of cash flow hedges
|
|
|
(1,336
|
)
|
|
|
821
|
|
|
|
(1,193
|
)
|
(Gain) loss on derivatives not designated as hedges
|
|
|
(249,870
|
)
|
|
|
20,274
|
|
|
|
|
|
Dedesignated cash flow hedges reclassified from accumulated
other comprehensive income (loss)
|
|
|
696
|
|
|
|
(1,103
|
)
|
|
|
|
|
Other non-cash items
|
|
|
6,517
|
|
|
|
3,376
|
|
|
|
1,150
|
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
42,514
|
|
|
|
(5,759
|
)
|
|
|
(27,683
|
)
|
Prepaid costs and other
|
|
|
(5,542
|
)
|
|
|
(169
|
)
|
|
|
(2,162
|
)
|
Inventory
|
|
|
(16,819
|
)
|
|
|
(150
|
)
|
|
|
(291
|
)
|
Accounts payable
|
|
|
(25,234
|
)
|
|
|
(3,493
|
)
|
|
|
13,853
|
|
Revenue payable
|
|
|
7,074
|
|
|
|
4,593
|
|
|
|
2,372
|
|
Other current liabilities
|
|
|
18,219
|
|
|
|
(669
|
)
|
|
|
10,421
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
391,397
|
|
|
|
169,769
|
|
|
|
112,181
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures on oil and gas properties
|
|
|
(347,702
|
)
|
|
|
(162,378
|
)
|
|
|
(182,389
|
)
|
Acquisition of oil and gas properties, businesses and other
assets
|
|
|
(584,220
|
)
|
|
|
(255
|
)
|
|
|
(413,229
|
)
|
Additions to other property and equipment
|
|
|
(8,808
|
)
|
|
|
(2,813
|
)
|
|
|
(1,234
|
)
|
Proceeds from the sale of oil and gas properties and other assets
|
|
|
1,034
|
|
|
|
3,278
|
|
|
|
|
|
Settlements received (paid) on derivatives not designated as
hedges
|
|
|
(6,354
|
)
|
|
|
1,815
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(946,050
|
)
|
|
|
(160,353
|
)
|
|
|
(596,852
|
)
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
767,800
|
|
|
|
300,200
|
|
|
|
664,993
|
|
Payments of long-term debt
|
|
|
(465,700
|
)
|
|
|
(468,800
|
)
|
|
|
(241,493
|
)
|
Exercise of stock options
|
|
|
5,391
|
|
|
|
|
|
|
|
|
|
Excess tax benefit from stock-based compensation
|
|
|
3,614
|
|
|
|
|
|
|
|
|
|
Net proceeds from issuance of common stock
|
|
|
242,426
|
|
|
|
172,709
|
|
|
|
61,178
|
|
Payments of preferred stock dividends
|
|
|
|
|
|
|
(132
|
)
|
|
|
(2,567
|
)
|
Proceeds from repayment of officer and employee notes
|
|
|
333
|
|
|
|
12,830
|
|
|
|
|
|
Payments for loan origination costs
|
|
|
(15,541
|
)
|
|
|
(2,572
|
)
|
|
|
(5,500
|
)
|
Purchase of treasury stock
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
Bank overdrafts
|
|
|
3,783
|
|
|
|
5,651
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
541,981
|
|
|
|
19,886
|
|
|
|
476,611
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(12,672
|
)
|
|
|
29,302
|
|
|
|
(8,060
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
30,424
|
|
|
|
1,122
|
|
|
|
9,182
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
17,752
|
|
|
$
|
30,424
|
|
|
$
|
1,122
|
|
|
|
|
|
|
|
Supplemental cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $1,233, $2,647 and
$2,129 capitalized interest
|
|
$
|
27,747
|
|
|
$
|
41,036
|
|
|
$
|
23,882
|
|
Cash paid for income taxes
|
|
$
|
11,304
|
|
|
$
|
2,050
|
|
|
$
|
1,725
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock in acquisition of oil and gas
properties and other assets
|
|
$
|
|
|
|
$
|
650
|
|
|
$
|
384,336
|
|
Deferred tax effect of acquired oil and gas properties
|
|
$
|
206,497
|
|
|
$
|
(444
|
)
|
|
$
|
227,735
|
|
Issuance of notes receivable in connection with capital options
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3,158
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-44
|
|
Note A.
|
Organization
and nature of operations
|
Concho Resources Inc. (Resources) is a Delaware
corporation formed by Concho Equity Holdings Corp.
(CEHC) on February 22, 2006, for purposes of
effecting the combination of CEHC, Chase Oil Corporation, Caza
Energy LLC (Caza) and certain other parties thereto
(collectively with Chase Oil Corporation and Caza, the
Chase Group). Pursuant to the Combination Agreement
dated February 24, 2006, Resources acquired working
interests in oil and natural gas properties in Southeast New
Mexico from the Chase Group (the Chase Group
Properties) and issued shares of Resources common stock to
certain stockholders of CEHC in exchange for their capital stock
of CEHC. CEHC is a Delaware corporation formed on April 21,
2004 by certain members of Resources management team and
private equity investors. CEHC commenced substantial oil and gas
operations in December 2004 upon its acquisition of oil and gas
properties located in Southeast New Mexico and West Texas. The
combination transaction described above (the
Combination) was accounted for as an acquisition by
CEHC of the Chase Group Properties and a simultaneous
reorganization of Resources such that CEHC is now a wholly-owned
subsidiary of Resources. Prior to the Combination, Resources had
no assets, operations or net equity. Upon the closing of the
Combination, the executive officers of CEHC became the executive
officers of Resources. Resources and its wholly-owned
subsidiaries are collectively referred to herein as the
Company.
In the Combination, CEHCs shareholders received
23,767,691 shares of common stock of the Company in
exchange for their preferred and common shares of CEHC,
excluding eighteen holders owning an aggregate of
254,621 shares of CEHC 6% Series A Preferred Stock and
127,313 shares of CEHC common stock, as discussed in
Note F. In addition, the Chase Group transferred the Chase
Group Properties to the Company in exchange for cash in the
aggregate amount of approximately $409 million and
34,794,638 shares of the Companys common stock. In
connection with the Companys initial public offering and
secondary public offering (see Note F), the Chase Group
sold a total of 18,638,014 shares of the Companys
common stock. At December 31, 2008 and December 31,
2007, the Chase Group owned approximately 9 percent and
21 percent, respectively, of the total outstanding common
stock of the Company.
The Companys principal business is the acquisition,
development, exploitation and exploration of oil and gas
properties in the Permian Basin region of Southeast New Mexico
and West Texas.
|
|
Note B.
|
Summary of
significant accounting policies
|
Principles of consolidation. The consolidated
financial statements of the Company include the accounts of the
Company and its wholly-owned subsidiaries, including CEHC. All
material intercompany balances and transactions have been
eliminated.
Use of estimates in the preparation of financial
statements. Preparation of financial statements in
conformity with generally accepted accounting principles in the
United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting
F-45
periods. Actual results could differ from these estimates.
Depletion of oil and gas properties are determined using
estimates of proved oil and gas reserves. There are numerous
uncertainties inherent in the estimation of quantities of proved
reserves and in the projection of future rates of production and
the timing of development expenditures. Similarly, evaluations
for impairment of proved and unproved oil and gas properties are
subject to numerous uncertainties including, among others,
estimates of future recoverable reserves and commodity price
outlooks. Other significant estimates include, but are not
limited to, the asset retirement obligations, fair value of
derivative financial instruments, purchase price allocations for
business and oil and gas property acquisitions and fair value of
stock-based compensation.
Cash equivalents. The Company considers all cash on
hand, depository accounts held by banks, money market accounts
and investments with an original maturity of three months or
less to be cash equivalents. The Companys cash and cash
equivalents are held in a few financial institutions in amounts
that exceed the insurance limits of the Federal Deposit
Insurance Corporation. However, management believes that the
Companys counterparty risks are minimal based on the
reputation and history of the institutions selected.
Accounts receivable. The Company sells oil and gas
to various customers and participates with other parties in the
drilling, completion and operation of oil and gas wells. Joint
interest and oil and gas sales receivables related to these
operations are generally unsecured. The Company determines joint
interest operations accounts receivable allowances based on
managements assessment of the creditworthiness of the
joint interest owners and the Companys ability to realize
the receivables through netting of anticipated future production
revenues. Receivables are considered past due if full payment is
not received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been exhausted.
The Company had an allowance for doubtful accounts of
approximately $2.9 million and none at December 31,
2008 and 2007, respectively, and the Company did not write off
any receivables against the allowance for doubtful accounts in
2008, 2007 or 2006.
Assets held for sale. The Company capitalizes the
costs of acquiring oil and gas leaseholds held for resale,
including lease bonuses and any advance rentals required at the
time of assignment of the lease to the Company. Advance rentals
paid after assignment are charged to expense as carrying costs
in the period incurred. Costs of oil and gas leases held for
resale are valued at lower of cost or net realizable value and
included in current assets since they could be sold within one
year, although the holding period of individual leases may be in
excess of one year. The cost of oil and gas leases sold is
determined on a specific identification basis.
Inventory. Inventory consists primarily of tubular
goods that the Company plans to utilize in its ongoing
exploration and development activities and is carried at the
lower of cost or market value, on a weighted average cost basis.
Deferred loan costs. Deferred loan costs are stated
at cost, net of amortization, which is computed using the
effective interest and straight-line methods. The Company had
deferred loan costs of $15.7 million and $3.4 million,
net of accumulated amortization of $3.3 million and
$3.6 million, at December 31, 2008 and
December 31, 2007, respectively.
F-46
Future amortization expense of deferred loan costs at
December 31, 2008 is as follows (in thousands):
|
|
|
|
|
2009
|
|
$
|
3,426
|
|
2010
|
|
|
3,426
|
|
2011
|
|
|
3,426
|
|
2012
|
|
|
3,426
|
|
2013
|
|
|
1,997
|
|
|
|
|
|
|
Total
|
|
$
|
15,701
|
|
|
|
Oil and gas properties. The Company utilizes the
successful efforts method of accounting for its oil and gas
properties under the provisions of Financial Accounting
Standards Board (FASB) Statement of Financial
Accounting Standards (SFAS) No. 19,
Financial Accounting and Reporting by Oil and Gas
Producing Companies. Under this method all costs
associated with productive wells and nonproductive development
wells are capitalized, while nonproductive exploration costs are
expensed. Capitalized acquisition costs relating to proved
properties are depleted using the
unit-of-production
method based on proved reserves. The depletion of capitalized
exploratory drilling and development costs is based on the
unit-of-production
method using proved developed reserves on a field basis.
The Company generally does not carry the costs of drilling an
exploratory well as an asset in its Consolidated Balance Sheets
for more than one year following the completion of drilling
unless the exploratory well finds oil and gas reserves in an
area requiring a major capital expenditure and both of the
following conditions are met:
(i) The well has found a sufficient quantity of reserves to
justify its completion as a producing well.
(ii) The Company is making sufficient progress assessing
the reserves and the economic and operating viability of the
project.
Due to the capital intensive nature and the geographical
location of certain projects, it may take the Company longer
than one year to evaluate the future potential of the
exploration well and economics associated with making a
determination on its commercial viability. In these instances,
the projects feasibility is not contingent upon price
improvements or advances in technology, but rather the
Companys ongoing efforts and expenditures related to
accurately predicting the hydrocarbon recoverability based on
well information, gaining access to other companies
production, transportation or processing facilities
and/or
getting partner approval to drill additional appraisal wells.
These activities are ongoing and being pursued constantly.
Consequently, the Companys assessment of suspended
exploratory well costs is continuous until a decision can be
made that the well has found proved reserves or is noncommercial
and is charged to exploration and abandonments expense. See
Note C for additional information regarding the
Companys suspended exploratory well costs.
Proceeds from the sales of individual properties and the
capitalized costs of individual properties sold or abandoned are
credited and charged, respectively, to accumulated depletion.
Generally, no gain or loss is recognized until the entire
amortization base is sold. However, gain or loss is recognized
from the sale of less than an entire amortization base if the
disposition is significant enough to materially impact the
depletion rate of the remaining properties in the amortization
base. Ordinary maintenance and repair costs are expensed as
incurred.
F-47
Costs of significant nonproducing properties, wells in the
process of being drilled and development projects are excluded
from depletion until such time as the related project is
developed and proved reserves are established or impairment is
determined. The Company capitalizes interest, if debt is
outstanding, on expenditures for significant development
projects until such projects are ready for their intended use.
At December 31, 2008 and 2007 the Company had excluded
$27.8 million and $19.0 million, respectively, of
capitalized costs from depletion and had capitalized interest of
$1.2 million, $2.6 million and $2.1 million,
during 2008, 2007 and 2006, respectively.
In accordance with SFAS No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets, the
Company reviews its long-lived assets to be held and used,
including proved oil and gas properties, whenever events or
circumstances indicate that the carrying value of those assets
may not be recoverable. An impairment loss is indicated if the
sum of the expected future cash flows is less than the carrying
amount of the assets. In this circumstance, the Company
recognizes an impairment loss for the amount by which the
carrying amount of the asset exceeds the estimated fair value of
the asset. The Company reviews its oil and gas properties by
amortization base or by individual well for those wells not
constituting part of an amortization base. For each property
determined to be impaired, an impairment loss equal to the
difference between the carrying value of the properties and the
estimated fair value (discounted future cash flows) of the
properties would be recognized at that time. Estimating future
cash flows involves the use of judgments, including estimation
of the proved and unproved oil and gas reserve quantities,
timing of development and production, expected future commodity
prices, capital expenditures and production costs. The Company
recognized impairment expense of $18.4 million,
$7.3 million and $9.9 million during the years ended
December 31, 2008, 2007 and 2006, respectively, related to
its proved oil and gas properties.
Unproved oil and gas properties are each periodically assessed
for impairment by considering future drilling plans, the results
of exploration activities, commodity price outlooks, planned
future sales or expiration of all or a portion of such projects.
During the years ended December 31, 2008, 2007 and 2006,
the Company recognized expense of $31.6 million,
$3.1 million and $0.2 million, respectively, related
to abandoned prospects, which is included in exploration and
abandonments in the accompanying consolidated statements of
operations.
Other property and equipment. Other capital assets
include buildings, vehicles, computer equipment and software,
telecommunications equipment, leasehold improvements and
furniture and fixtures. These items are recorded at cost and are
depreciated using the straight-line method based on expected
lives of the individual assets or group of assets ranging from
two to 15 years.
Intangible assets. The Company has capitalized
certain operating rights acquired in an acquisition, see
Note D. The gross operating rights of approximately
$38.4 million, which have no residual value, are amortized
over the estimated economic life of approximately 25 years.
Impairment will be assessed if indicators of potential
impairment exist or when there is a material change in the
remaining useful economic life. Amortization expense for the
year ended
F-48
December 31, 2008 was approximately $0.6 million. The
following table reflects the estimated aggregate amortization
expense for each of the periods presented below (in thousands):
|
|
|
|
|
2009
|
|
$
|
1,536
|
|
2010
|
|
|
1,536
|
|
2011
|
|
|
1,536
|
|
2012
|
|
|
1,536
|
|
2013
|
|
|
1,536
|
|
Thereafter
|
|
|
30,088
|
|
|
|
|
|
|
Total
|
|
$
|
37,768
|
|
|
|
Environmental. The Company is subject to extensive
Federal, state and local environmental laws and regulations.
These laws, which are often changing, regulate the discharge of
materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites.
Environmental expenditures are expensed. Expenditures that
relate to an existing condition caused by past operations and
that have no future economic benefits are expensed. Liabilities
for expenditures of a noncapital nature are recorded when
environmental assessment
and/or
remediation is probable and the costs can be reasonably
estimated. Such liabilities are generally undiscounted unless
the timing of cash payments is fixed and readily determinable.
Management believes no material liabilities of this nature
existed at December 31, 2008 or 2007.
Oil and gas sales and imbalances. Oil and gas
revenues are recorded at the time of delivery of such products
to pipelines for the account of the purchaser or at the time of
physical transfer of such products to the purchaser. The Company
follows the sales method of accounting for oil and gas sales,
recognizing revenues based on the Companys share of actual
proceeds from the oil and gas sold to purchasers. Oil and gas
imbalances are generated on properties for which two or more
owners have the right to take production in-kind
and, in doing so, take more or less than their respective
entitled percentage. Imbalances are tracked by well, but the
Company does not record any receivable from or payable to the
other owners unless the imbalance has reached a level at which
it exceeds the remaining reserves in the respective well. If
reserves are insufficient to offset the imbalance and the
Company is in an overtake position, a liability is recorded for
the amount of shortfall in reserves valued at a contract price
or the market price in effect at the time the imbalance is
generated. If the Company is in an undertake position, a
receivable is recorded for an amount that is reasonably expected
to be received, not to exceed the current market value of such
imbalance.
The following table reflects the Companys gas imbalance
positions at December 31, 2008 and 2007 as well as amounts
reflected in oil and gas production expense for the years ended
December 31, 2008 and 2007 ($ in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Gas imbalance liability (included in asset retirement
obligations and other long-term liabilities)
|
|
$
|
472
|
|
|
$
|
621
|
|
Overtake position (Mcf)
|
|
|
85,698
|
|
|
|
96,215
|
|
Gas imbalance receivable (included in other assets)
|
|
$
|
406
|
|
|
$
|
367
|
|
Undertake position (Mcf)
|
|
|
90,321
|
|
|
|
81,569
|
|
|
|
F-49
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Value of net undertake arising during the year (reducing oil and
gas production expense)
|
|
$
|
189
|
|
|
$
|
14
|
|
Net undertake position arising during the year (Mcf)
|
|
|
19,269
|
|
|
|
4,264
|
|
|
|
Derivative instruments and hedging. The Company
applies the provisions of SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities, as amended. This statement requires the
recognition of all derivative instruments as either assets or
liabilities measured at fair value. The Company netted the fair
value of derivative instruments by counterparty in the
accompanying consolidated balance sheets where the right of
offset exists as permitted by FASB Interpretation
(FIN) No. 39, Offsetting of Amounts
Related to Certain Contracts.
Under the provisions of SFAS No. 133, the Company may
designate a derivative instrument as hedging the exposure to
changes in the fair value of an asset or a liability or an
identified portion thereof that is attributable to a particular
risk (a fair value hedge) or as hedging the exposure
to variability in expected future cash flows that are
attributable to a particular risk (a cash flow
hedge). Special accounting for qualifying hedges allows
the effective portion of a derivative instruments gains
and losses to offset related results on the hedged item in the
statement of operations and requires that a company formally
document, designate and assess the effectiveness of the
transactions that receive hedge accounting treatment. Both at
the inception of a hedge and on an ongoing basis, a hedge must
be expected to be highly effective in achieving offsetting
changes in fair value or cash flows attributable to the
underlying risk being hedged. If the Company determines that a
derivative instrument is no longer highly effective as a hedge,
it discontinues hedge accounting prospectively and future
changes in the fair value of the derivative are recognized in
current earnings. The amount already reflected in accumulated
other comprehensive (loss) income (AOCI) remains
there until the hedged item affects earnings or it is probable
that the hedged item will not occur by the end of the originally
specified time period or within two months thereafter. The
Company assesses and measures hedge effectiveness at the end of
each quarter.
In accordance with SFAS No. 133, changes in the fair
value of derivative instruments that are fair value hedges are
offset against changes in the fair value of the hedged assets,
liabilities or firm commitments, through earnings. Effective
changes in the fair value of derivative instruments that are
cash flow hedges are recognized in AOCI and reclassified into
earnings in the period in which the hedged item affects
earnings. Ineffective portions of a derivative instruments
change in fair value are immediately recognized in earnings.
Derivative instruments that do not qualify, or cease to qualify,
as hedges must be adjusted to fair value and the adjustments are
recorded through net income.
Asset retirement obligations. The Company accounts
for the obligations in accordance with SFAS No. 143,
Asset Retirement Obligations. SFAS No. 143
requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of
the related long-lived asset. Subsequently, the asset retirement
cost included in the carrying amount of the related asset is
allocated to expense through depreciation of the asset. Changes
in the liability due to passage of time are recognized as an
increase in the carrying amount of the liability and as
corresponding accretion expense.
F-50
Treasury stock. Treasury stock purchases are
recorded at cost. Upon reissuance, the cost of treasury shares
held is reduced by the average purchase price per share of the
aggregate treasury shares held.
General and administrative expense. The Company
receives fees for the operation of jointly owned oil and gas
properties and records such reimbursements as reductions of
general and administrative expense. Such fees totaled
approximately $4.9 million, $1.1 million and
$0.8 million for the years ended December 31, 2008,
2007 and 2006, respectively.
Stock-based compensation. The Company applies the
provisions of SFAS No. 123R, Share Based
Payment, to transactions in which the Company exchanges
its equity instruments for employee services, and transactions
in which the Company incurs liabilities that are based on the
fair value of the Companys equity instruments or that may
be settled by the issuance of those equity instruments in
exchange for employee services. The cost of employee services
received in exchange for equity instruments, including employee
stock options, is measured based on the grant-date fair value of
those instruments. That cost is recognized as compensation
expense over the requisite service period (generally the vesting
period). Generally, no compensation cost is recognized for
equity instruments that do not vest.
Income taxes. The Company accounts for income taxes
in accordance with the provisions of SFAS No. 109,
Accounting for Income Taxes. Under the asset and
liability method of SFAS No. 109, deferred tax assets
and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are
expected to be recovered or settled. Under
SFAS No. 109, the effect on deferred tax assets and
liabilities of a change in tax rate is recognized in income in
the period that includes the enactment date. A valuation
allowance is established to reduce deferred tax assets if it is
more likely than not that the related tax benefits will not be
realized.
The Company adopted the provisions of FIN No. 48,
Accounting for Uncertainty in Income Taxesan
interpretation of FASB Statement No. 109, on
January 1, 2007. FIN No. 48 clarifies the
accounting for uncertainty in income taxes recognized in an
enterprises financial statements in accordance with
SFAS No. 109 and prescribes a recognition threshold
and measurement process for financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return. FIN No. 48 also provides guidance on
derecognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition.
Reclassifications. Certain prior period amounts have
been reclassified to conform to the 2008 presentation. These
reclassifications had no impact on net income, total
stockholders equity or cash flows.
Recent accounting pronouncements. In February 2007,
the FASB issued SFAS No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities, Including
an Amendment of FASB Statement No. 115, which
became effective in 2008. SFAS No. 159 permits
entities to measure eligible financial assets, financial
liabilities and firm commitments at fair value, on an
instrument-by-instrument
basis, that are otherwise not permitted to be accounted for at
fair value under other generally accepted accounting principles.
The fair value measurement election is irrevocable and
subsequent changes in fair value must be recorded in earnings.
The Company adopted this statement January 1, 2008 and did
not elect the fair value option for any
F-51
of its eligible financial instruments or other items. As such,
the adoption had no impact on the consolidated financial
statements.
In April 2007, the FASB issued FASB Staff Position
FIN 39-1,
Amendment of FASB Interpretation No. 39
(FIN No. 39-1).
FIN No. 39-1
clarifies that a reporting entity that is party to a master
netting arrangement can offset fair value amounts recognized for
the right to reclaim cash collateral (a receivable) or the
obligation to return cash collateral (a payable) against fair
value amounts recognized for derivative instruments that have
been offset under the same master netting arrangement.
FIN No. 39-1
is effective for financial statements issued for fiscal years
beginning after November 15, 2007. Adoption of
FIN No. 39-1
has not had a material impact on the Companys consolidated
financial statements.
In June 2007, the FASB ratified a consensus opinion reached by
the Emerging Issues Task Force (EITF) on EITF Issue
06-11,
Accounting for Income Tax Benefits of Dividends on
Share-Based Payment Awards. EITF Issue
06-11
requires an employer to recognize tax benefits realized from
dividend or dividend equivalents paid to employees for certain
share-based payment awards as an increase to additional paid-in
capital and include such amounts in the pool of excess tax
benefits available to absorb future tax deficiencies on
share-based payment awards. If an entitys estimate of
forfeitures increases (or actual forfeitures exceed the
entitys estimates), or if an award is no longer expected
to vest, entities should reclassify the dividends or dividend
equivalents paid on that award from retained earnings to
compensation cost. However, the tax benefits from dividends that
are reclassified from additional paid-in capital to the income
statement are limited to the entitys pool of excess tax
benefits available to absorb tax deficiencies on the date of
reclassification. The consensus in EITF Issue
06-11 is
effective for fiscal years, and interim periods within those
fiscal years, beginning after December 15, 2007.
Retrospective application of EITF Issue
06-11 is not
permitted. Early adoption is permitted; however, the Company did
not adopt EITF Issue
06-11 until
the required effective date of January 1, 2008. The
adoption of EITF Issue
06-11 has
not had a significant effect on the Companys financial
statements since the Company historically has accounted for the
income tax benefits of dividends paid for share-based payment
awards in the manner described in the consensus.
In December 2007, the FASB issued SFAS No. 141
(revised 2007), Business Combinations
(SFAS No. 141(R)), which replaces FASB
Statement No. 141. SFAS No. 141(R) establishes
principles and requirements for how an acquirer recognizes and
measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any non-controlling interest
in the acquiree and the goodwill acquired.
SFAS No. 141(R) also establishes disclosure
requirements that will enable users to evaluate the nature and
financial effects of the business combination.
SFAS No. 141(R) is effective for acquisitions that
occur in an entitys fiscal year that begins after
December 15, 2008, which will be our fiscal year 2009. The
impact, if any, will depend on the nature and size of business
combinations the Company consummates after the effective date.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statementsan amendment of ARB No. 51.
SFAS No. 160 requires that accounting and reporting
for minority interests will be recharacterized as noncontrolling
interests and classified as a component of equity.
SFAS No. 160 also establishes reporting requirements
that provide sufficient disclosures that clearly identify and
distinguish between the interests of the parent and the
interests of the noncontrolling owners. SFAS No. 160
applies to all entities that prepare consolidated financial
statements, except
not-for-profit
organizations, but will affect
F-52
only those entities that have an outstanding noncontrolling
interest in one or more subsidiaries or that deconsolidate a
subsidiary. This statement is effective as of the beginning of
an entitys first fiscal year beginning after
December 15, 2008, which will be the Companys fiscal
year 2009. Based upon the Companys December 31, 2008
consolidated balance sheet, the statement would have no impact.
In December 2007, the SEC issued Staff Accounting Bulletin
(SAB) No. 110, Share-Based Payment
(SAB No. 110).
SAB No. 110 amends SAB No. 107,
Share-Based Payment, and allows for the continued
use, under certain circumstances, of the simplified method in
developing an estimate of the expected term on stock options
accounted for under SFAS No. 123R,
Share-Based Payment (revised 2004).
SAB No. 110 is effective for stock options granted
after December 31, 2007. The Company continued to use the
simplified method in developing an estimate of the expected term
on stock options granted in 2008. The Company does not have
sufficient historical exercise data to provide a reasonable
basis upon which to estimate expected term due to the limited
period of time the Companys shares of common stock have
been publicly traded.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities, which amends and expands the disclosure
requirements of SFAS No. 133 to provide an enhanced
understanding of an entitys use of derivative instruments,
how they are accounted for under SFAS No. 133 and
their effect on the entitys financial position, financial
performance and cash flows. The provisions of
SFAS No. 161 are effective as of January 1, 2009.
The Company is currently evaluating the impact on its
consolidated financial statements of adopting
SFAS No. 161.
In April 2008, the FASB issued FASB Staff Position
(FSP)
No. SFAS 142-3,
Determination of the Useful Life of Intangible Assets
(FSP
SFAS No. 142-3).
FSP
SFAS No. 142-3
amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under
SFAS No. 142, Goodwill and Other Intangible Assets
(SFAS No. 142). The intent of FSP
SFAS No. 142-3
is to improve the consistency between the useful life of a
recognized intangible asset under SFAS No. 142 and the
period of expected cash flows used to measure the fair value of
the asset under SFAS No. 141R and other applicable
accounting literature. FSP
SFAS No. 142-3
is effective for financial statements issued forfiscal
years beginning after December 15, 2008 and must be applied
prospectively to intangible assets acquired after the effective
date. The Company is currently evaluating the potential impact,
if any, of FSP
SFAS No. 142-3
on its financial statements.
In May 2008, the FASB issued SFAS No. 162,
The Hierarchy of Generally Accepted Accounting
Principles, which identifies the sources of accounting
principles and the framework for selecting the principles used
in the preparation of financial statements of nongovernmental
entities that are presented in conformity with generally
accepted accounting principles (GAAP) in the United
States of America. This statement is effective 60 days
following the SECs approval of the Public Company
Accounting Oversight Board amendments to AU Section 411,
The Meaning of Present Fairly in Conformity with
Generally Accepted Accounting Principles. The Company
does not expect the adoption of SFAS No. 162 to have
an impact on its consolidated financial statements.
In June 2008, the FASB issued Staff Position
No. EITF 03-6-1
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities,
(FSP
EITF 03-6-1)
which provides that unvested share-based payment awards that
contain non-forfeitable rights to dividends or dividend
equivalents (whether paid or unpaid) are participating
securities and,
F-53
therefore, need to be included in the earnings allocation in
computing earnings per share under the two class method. FSP
EITF 03-6-1
was effective for us on January 1, 2009 and all
prior-period EPS data (including any amounts related to interim
periods, summaries of earnings and selected financial data) will
be adjusted retroactively to conform to its provisions. Early
application of FSP
EITF 03-6-1
is not permitted. Although restricted stock awards meet this
definition, the Company does not expect the application of FSP
EITF 03-6-1
to have a significant impact on its reported earnings per share.
In October 2008, the FASB issued FSP
No. SFAS 157-3,
Determining the Fair Value of a Financial Asset When
the Market for That Asset is Not Active. FSP
No. SFAS 157-3
clarifies the application of SFAS No. 157 as it
relates to the valuation of financial assets in a market that is
not active for those financial assets. This FSP is effective
immediately and includes those periods for which financial
statements have not been issued. The Company currently does not
have any financial assets that are valued using inactive
markets, and as a result, the Company is not impacted by the
issuance of FSP
No. SFAS 157-3.
Recent developments in reserve reporting. The United
States Securities and Exchange Commission (SEC)
recently approved new disclosure rules that allow oil and
natural gas companies to more accurately report their assets in
terms of volumes and values that investors can understand and
use to make informed decisions. The new reporting requirement is
effective on December 15, 2009. The new disclosure
requirements include provisions that:
|
|
|
permit the use of new technologies to determine proved reserves
if those technologies have been demonstrated empirically to lead
to reliable conclusions about reserves volumes;
|
|
|
allow companies to disclose in SEC filed documents their
probable and possible reserves to investors (currently, the SEC
rules limit disclosure to only proved reserves);
|
|
|
require companies to report the independence and qualifications
of a reserves preparer or auditor;
|
|
|
file reports when a third party is relied upon to prepare
reserves estimates or conducts a reserves audit; and
|
|
|
report oil and gas reserves using an average price based upon
the prior
12-month
period rather than year-end prices.
|
The Company is currently evaluating the impact these new reserve
reporting requirements will have on its consolidated financial
statements.
|
|
Note C.
|
Exploratory
well costs
|
The Company capitalizes exploratory well costs until a
determination is made that the well has either found proved
reserves or that it is impaired. The capitalized exploratory
well costs are presented in unproved properties in the
Consolidated Balance Sheets. If the exploratory well is
determined to be impaired, the well costs are charged to expense.
F-54
The following table reflects the Companys capitalized
exploratory well activity during each of the years ended
December 31, 2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Beginning capitalized exploratory well costs
|
|
$
|
21,056
|
|
|
$
|
26,503
|
|
|
$
|
4,370
|
|
Additions to exploratory well costs pending the determination of
proved reserves
|
|
|
25,621
|
|
|
|
97,368
|
|
|
|
25,170
|
|
Reclassifications due to determination of proved reserves
|
|
|
(18,327
|
)
|
|
|
(95,869
|
)
|
|
|
(2,759
|
)
|
Exploratory well costs charged to expense
|
|
|
(2,797
|
)
|
|
|
(6,946
|
)
|
|
|
(278
|
)
|
|
|
|
|
|
|
Ending capitalized exploratory well costs
|
|
$
|
25,553
|
|
|
$
|
21,056
|
|
|
$
|
26,503
|
|
|
|
The following table provides an aging at December 31, 2008
and 2007 of capitalized exploratory well costs based on the date
the drilling was completed (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Wells in drilling progress
|
|
$
|
7,765
|
|
|
$
|
4,199
|
|
Capitalized exploratory well costs that have been capitalized
for a period of one year or less
|
|
|
17,788
|
|
|
|
16,857
|
|
Capitalized exploratory well costs that have been capitalized
for a period greater than one year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalized exploratory well costs
|
|
$
|
25,553
|
|
|
$
|
21,056
|
|
|
|
At December 31, 2008, the Company had 18 gross
exploratory wells either drilling or waiting on results from
completion. There are 4 wells in the New Mexico Permian
area, 9 wells in the Texas Permian area, 3 wells in
the Arkoma Basin in Arkansas and 2 wells in the Williston
Basin of North Dakota.
|
|
Note D.
|
Acquisition
and business combination
|
Henry Entities acquisition. On July 31, 2008,
the Company closed our acquisition of Henry Petroleum LP and
certain entities affiliated with Henry Petroleum LP (which we
refer to as Henry or the Henry Entities)
and additional non-operated interests in oil and gas properties
from persons affiliated with the Henry Entities. In August 2008
and September 2008, we acquired additional non-operated
interests in oil and gas properties from persons affiliated with
the Henry Entities. The assets acquired in the Henry Entities
acquisition are referred to as the Henry Properties.
The Company paid $584.1 million in cash for the Henry
Properties acquisition.
The cash paid for the Henry Properties acquisition was funded
with (i) borrowings under the Companys credit
facility, see Note J, and (ii) proceeds from a private
placement of approximately 8.3 million shares of the
Companys common stock, see Note F.
The Henry Properties acquisition is being accounted for using
the purchase method of accounting for business combinations.
Under the purchase method of accounting, the Company recorded
the Henry Properties assets and liabilities at fair value.
The purchase price of the acquired Henry Properties net
assets is based on the total value of the cash consideration.
The
F-55
initial purchase price allocation is preliminary and subject to
adjustment. Any future adjustments to the allocation of the
total purchase price are not anticipated to be material to the
Companys consolidated financial statements.
The following tables represent the preliminary allocation of the
total purchase price of the Henry Properties to the acquired
assets and liabilities of the Henry Properties and the
consideration paid for the Henry Properties. The allocation
represents the fair values assigned to each of the assets
acquired and liabilities assumed (in thousands):
|
|
|
|
|
Fair value of Henry Properties net assets:
|
|
|
|
|
Current assets, net of cash acquired of
$19,049a
|
|
$
|
86,321
|
|
Proved oil and gas properties
|
|
|
595,005
|
|
Unproved oil and gas properties
|
|
|
233,199
|
|
Other long-term assets
|
|
|
6,977
|
|
Intangible assetsoperating rights
|
|
|
38,409
|
|
|
|
|
|
|
Total assets acquired
|
|
|
959,911
|
|
|
|
|
|
|
Current liabilities
|
|
|
(113,729
|
)
|
Asset retirement obligations and other long-term liabilities
|
|
|
(7,529
|
)
|
Noncurrent derivative liabilities
|
|
|
(39,037
|
)
|
Deferred tax liability
|
|
|
(215,475
|
)
|
|
|
|
|
|
Total liabilities assumed
|
|
|
(375,770
|
)
|
|
|
|
|
|
Net purchase price
|
|
$
|
584,141
|
|
|
|
|
|
|
Consideration paid for Henry Properties net assets:
|
|
|
|
|
Cash consideration paid, net of cash acquired of $19,049
|
|
$
|
578,491
|
|
Acquisition
costsb
|
|
|
5,650
|
|
|
|
|
|
|
Total purchase price
|
|
$
|
584,141
|
|
|
|
|
|
|
(a)
|
|
Includes a deferred tax asset of
approximately $9.0 million.
|
|
(b)
|
|
Estimated acquisition costs include
legal and accounting fees, advisory fees and other
acquisition-related costs.
|
The following unaudited pro forma combined condensed financial
data for the years ended December 31, 2008 and 2007 was
derived from the historical financial statements of the Company
and Henry Properties giving effect to the acquisition as if it
had occurred on January 1 of each period. The unaudited pro
forma combined condensed financial data has been included for
comparative purposes only and is not necessarily indicative of
the results that might have occurred had the Henry Properties
acquisition taken place as of the dates indicated and is not
intended to be a projection of future results (in thousands,
except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Operating revenues
|
|
$
|
629,214
|
|
|
$
|
389,758
|
|
Net income (loss) applicable to common shareholders
|
|
$
|
257,540
|
|
|
$
|
(7,471
|
)
|
Earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
2.94
|
|
|
$
|
(0.10
|
)
|
Diluted
|
|
$
|
2.90
|
|
|
$
|
(0.10
|
)
|
|
|
F-56
Chase Group combination. On February 27, 2006,
the Company closed a Combination Agreement with the Chase Group
whereby ownership in oil and gas properties and non-producing
leasehold acreage in Southeast New Mexico (the Chase Group
Properties) were combined with the properties previously
owned by CEHC. The Chase Group received cash in the aggregate
amount of $409 million and 34,794,638 shares of
Resources common stock valued at $384 million for an
aggregate purchase price of $793 million including
transaction costs. The results of the Chase Group Properties
have been included in the consolidated financial statements
since that date.
|
|
Note E.
|
Asset
retirement obligations
|
The Companys asset retirement obligations represent the
estimated present value of the estimated cash flows the Company
will incur to plug, abandon and remediate its producing
properties at the end of their productive lives, in accordance
with applicable state laws. The Company does not provide for a
market risk premium associated with asset retirement obligations
because a reliable estimate cannot be determined. The Company
has no assets that are legally restricted for purposes of
settling asset retirement obligations.
The following table summarizes the Companys asset
retirement obligation transactions recorded in accordance with
the provisions of SFAS No. 143 during the years ended
December 31, 2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Asset retirement obligations, beginning of period
|
|
$
|
9,418
|
|
|
$
|
8,700
|
|
|
$
|
1,120
|
|
Liabilities incurred from new wells
|
|
|
1,197
|
|
|
|
471
|
|
|
|
1,288
|
|
Liabilities assumed in acquisitions
|
|
|
7,062
|
|
|
|
|
|
|
|
6,155
|
|
Accretion expense
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
|
|
|
|
(26
|
)
|
|
|
|
|
Revision of estimates
|
|
|
(1,757
|
)
|
|
|
(171
|
)
|
|
|
(150
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period
|
|
$
|
16,809
|
|
|
$
|
9,418
|
|
|
$
|
8,700
|
|
|
|
|
|
Note F.
|
Stockholders
equity and stock issued subject to limited recourse
notes
|
Common stock private placement. On June 5,
2008, the Company entered into a common stock purchase agreement
with certain unaffiliated third-party investors to sell certain
shares of the Companys common stock in a private placement
(the Private Placement) contemporaneous with the
closing of the Henry Properties acquisition. On July 31,
2008, the Company issued 8,302,894 shares of its common
stock at $30.11 per share. The Private Placement resulted in net
proceeds of approximately $242.4 million to the Company,
after payment of approximately $7.6 million for the fee
paid to the placement agent.
In connection with the Private Placement, the Company entered
into a registration rights agreement with the investors. On
October 24, 2008, pursuant to the registration rights
agreement, the Company filed a registration statement to
register the shares of common stock issued in the Private
Placement.
Initial public offering. On August 7, 2007, the
Company completed an initial public offering (the
IPO) of its common stock. The Company sold
13,332,851 shares of its common stock in
F-57
the IPO and certain shareholders, including its executive
officers and certain members of the Chase Group, sold
7,554,256 shares of the Companys common stock at
$11.50 per share. After deducting underwriting discounts of
approximately $9.6 million and offering expenses of
approximately $4.5 million, the Company received net
proceeds of approximately $139.2 million. In conjunction
with the IPO, the underwriters were granted an option to
purchase 3,133,066 additional shares of the Companys
common stock. The underwriters fully exercised this option and
purchased the additional shares on August 9, 2007. After
deducting underwriting discounts of approximately
$2.2 million, the Company received net proceeds of
approximately $33.8 million. The aggregate net proceeds of
approximately $173.0 million received by the Company at
closing on August 7, 2007 and August 9, 2007 were
utilized to reduce bank debt.
Secondary public offering. On December 19,
2007, the Company completed a secondary public offering of
11,845,000 shares of the Companys common stock, which
was sold by certain of the Companys stockholders,
including certain members of the Chase group. The Chase Group
sold 10,194,732 shares of the Companys common stock
in the aggregate and certain other stockholders of the Company
sold 1,650,268 shares of the Companys common stock in
the aggregate, including one of the Companys executive
officers who sold 45,000 shares of the Companys
common stock. Chase Oil Corporation granted the underwriters an
option to purchase up to 1,776,615 additional shares of the
Companys common stock to cover over-allotments, which was
fully exercised on December 19, 2007. The Company did not
receive any proceeds from the sale of the Companys common
stock in this secondary offering.
Treasury stock. On June 12, 2008, the
restrictions on certain restricted stock awards issued to five
of the Companys executive officers lapsed. Immediately
upon the lapse of restrictions, these executive officers became
liable for certain federal income taxes on the value of such
shares. In accordance with the Companys 2006 Stock
Incentive Plan and the applicable restricted stock award
agreements, four of such officers elected to deliver shares of
the Companys common stock to the Company to satisfy such
tax liability, and the Company acquired 3,142 shares to be
held as treasury stock in the approximate amount of $125,000.
Equity commitments. Pursuant to a stock purchase
agreement (the Stock Purchase Agreement) entered
into on August 13, 2004, CEHC obtained private equity
commitments totaling $202.5 million, comprised of equity
commitments from fourteen private investors (the Private
Investors) of approximately $188.9 million and equity
commitments from the five original officers (the
Officers) of the Company in the aggregate amount of
approximately $13.6 million. The original commitments were
subject to call by a vote of the board of directors over a four
year period beginning August 13, 2004 (the Take-Down
Period), with the first date on which capital was called
being August 13, 2004. Subsequent calls were made on
November 11, 2004, June 22, 2005, December 7,
2005 and February 10, 2006. The percentage of total
commitments called per capital call date was approximately
15.0 percent, 23.3 percent, 10.0 percent,
15.0 percent and 22.0 percent, respectively. In
conjunction with the exchange of CEHC common stock for Resources
common stock as of the date of the Combination, the remaining
14.7 percent of these private equity commitments was
terminated.
In addition to this arrangement between CEHC, the Private
Investors and the Officers, certain employees and other officers
of the Company entered into separate subscription agreements
with the Company. The officers and employees equity
purchases were paid for in a combination of cash and the
issuance of notes payable to the Company with recourse only to
any equity security of the Company held by the respective
officer or employee (the Purchase Notes). Based on
guidance contained in SFAS No. 123R, the agreements to
sell stock to the Companys
F-58
officers and employees subject to the Purchase Notes are
accounted for as the issuance of options (Bundled Capital
Options for the Officers and Capital Options
for employees) on the dates that the various subscription
agreements were signed and the purchase commitments were made.
Capital calls. From inception of CEHC through
February 23, 2006, the Private Investors purchased
16,113,170 Preferred Units for $161.1 million in cash; the
Companys officers purchased 2,240,083 CEHC common shares
and 938,303 Preferred Units for $3.6 million in cash and
Purchase Notes totaling $8.0 million, and certain employees
purchased 425,221 Preferred Units for $1.0 million in cash
and Purchase Notes totaling $3.8 million.
6% Series A preferred stock. Preferred
stock dividends were generally paid on the anniversary of date
of issuance of preferred stock as a part of the Preferred Units.
There were no dividend payments made during the year ended
December 31, 2008, because there was no outstanding
preferred stock. Preferred stock dividends of approximately
$132,000 and $2.6 million were paid during the years ended
December 31, 2007 and 2006, respectively. As discussed in
Note A and below, the majority of the CEHC preferred stock
was converted into Resources common stock in the Combination.
Final dividend payments on converted CEHC 6% Series A
Preferred Stock were made in March 2006.
Dividend payments continued to be made through April 16,
2007 to the eighteen employee shareholders that did not convert
their shares of CEHC preferred stock to Resources common stock
in the Combination. On April 16, 2007, these CEHC preferred
shares were exchanged for 190,972 shares of the
Companys common stock. These shares are reported as if
converted on the date of the Combination.
Purchase Notes. On April 23, 2007, the
Companys officers repaid their Purchase Notes in full,
including principal of $9.4 million and accrued interest of
$1.0 million in the aggregate. The agreements to sell stock
to the executive officers of the Company subject to Purchase
Notes were accounted for as the issuance of options. As such,
the repayment of the executive officer Purchase Notes represents
the full exercise of the options on the Bundled Capital Options
the officers held as well as the Capital Options of one certain
employee who was formerly an executive officer.
At December 31, 2008, all Purchase Notes from all employees
had been paid in full. As such, the repayment of the Purchase
Notes represent the full exercise of the options on the Capital
Options held by certain employees. At December 31, 2007,
the Company had Purchase Notes receivable from certain employees
of approximately $330,000 comprised of an aggregate principal
amounts of $288,000 and accrued interest of $42,000.
F-59
Stock issuances treated as Capital Options. The
following table summarizes the Bundled Capital Options activity
for the years ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted
|
|
|
|
bundled capital
|
|
|
average
|
|
|
|
options
|
|
|
exercise price
|
|
|
|
|
Outstanding at December 31, 2005
|
|
|
1,100,000
|
|
|
$
|
9.52
|
|
Bundled capital options granted
|
|
|
|
|
|
$
|
|
|
Cancelled/forfeited
|
|
|
(161,697
|
)
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
938,303
|
|
|
$
|
9.52
|
|
Bundled capital options exercised
|
|
|
(938,303
|
)
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
938,303
|
|
|
$
|
9.52
|
|
December 31, 2007
|
|
|
|
|
|
$
|
|
|
|
|
The following table summarizes the Capital Options activity for
the years ended December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted
|
|
|
|
capital
|
|
|
average
|
|
|
|
options
|
|
|
exercise price
|
|
|
|
|
Outstanding at December 31, 2005
|
|
|
482,500
|
|
|
$
|
9.74
|
|
$15 Capital Options granted
|
|
|
16,000
|
|
|
$
|
12.13
|
|
Cancelled/forfeited
|
|
|
(73,279
|
)
|
|
$
|
9.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
425,221
|
|
|
$
|
9.81
|
|
$10 Capital Options exercised
|
|
|
(270,828
|
)
|
|
$
|
8.97
|
|
$15 Capital Options exercised
|
|
|
(116,008
|
)
|
|
$
|
12.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
38,385
|
|
|
$
|
8.34
|
|
$10 Capital Options exercised
|
|
|
(38,385
|
)
|
|
$
|
8.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
425,221
|
|
|
$
|
9.81
|
|
December 31, 2007
|
|
|
38,385
|
|
|
$
|
8.34
|
|
December 31, 2008
|
|
|
|
|
|
$
|
|
|
|
|
F-60
The following table summarizes information about the
Companys vested Capital Options outstanding and
exercisable at December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital options
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
outstanding
|
|
|
average
|
|
|
average
|
|
|
|
|
|
|
|
|
|
vested and
|
|
|
remaining
|
|
|
exercise
|
|
|
Intrinsic
|
|
|
|
|
|
|
exercisable
|
|
|
contractual life
|
|
|
price
|
|
|
value
|
|
|
|
|
Vested capital options outstanding and exercisable at
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
10.00
|
|
|
|
38,385
|
|
|
|
2.52 years
|
|
|
$
|
8.34
|
|
|
$
|
562,000
|
|
|
|
The following table summarizes the stock-based compensation for
all Capital Options and is included in general and
administrative expense in the accompanying consolidated
statement of operations for the year ended December 31,
2006. There was no stock-based compensation for Capital Options
in 2008 and 2007.
|
|
|
|
|
Stock-based compensation expense from capital options
|
|
$
|
975,000
|
|
|
|
|
|
|
Bundled capital options:
|
|
|
|
|
Stock-based compensation expense
|
|
$
|
508,000
|
|
Options vesting during period
|
|
|
242,000
|
|
Weighted average grant date fair value per option
|
|
$
|
2.10
|
|
Capital options:
|
|
|
|
|
Stock-based compensation expense
|
|
$
|
467,000
|
|
Options vesting during period
|
|
|
119,799
|
|
Weighted average grant date fair value per option
|
|
$
|
3.90
|
|
|
|
Conversion of CEHC 6% Series A preferred stock and CEHC
common stock. On February 27, 2006, concurrent
with the closing of the Combination described in Note A,
the majority of the shares outstanding of CEHC preferred stock
and outstanding shares of CEHC common stock were converted to
shares of the Companys common stock, as described below.
Eighteen employee shareholders owning an aggregate of
254,621 shares of CEHC preferred stock and
127,313 shares of CEHC common stock did not convert their
shares to the Companys common stock at the date of the
Combination. On April 16, 2007, these remaining shares of
CEHC were exchanged for 318,285 shares of the
Companys common stock. These shares are reported as if
converted on the date of the Combination. In addition, CEHC made
a final dividend payment to these eighteen employee shareholders
on their CEHC preferred stock in the aggregate amount of
approximately $99,000 on April 16, 2007.
Also in conjunction with the Combination described in
Note A and the conversion of CEHC preferred stock into the
Companys common stock at the ratio of 0.75:1, the CEHC
Bundled Capital Options were converted into the Companys
Bundled Capital Options and CEHC Capital Options were converted
into the Companys Capital Options. The Companys
Capital Options are considered to be exercisable for
1.25 shares of the Companys common stock.
Common stock held in escrow. On February 27,
2006 the Company entered into an agreement with certain
stockholders of the Company in which certain of the
Companys shareholders placed 430,755 shares of
Resources common stock in an escrow account (the Escrow
Agreement). The Escrow Agreement provided that if, on or
before February 27, 2007 (the Initial
F-61
Period), the Company consummated one of two specified
transactions, the shares held in escrow would be released to the
Company for reissuance to Messrs. Leach, Beal, Copeland,
Kamradt and Wright. Neither of those specified transactions
occurred in the Initial Period. However, the Escrow Agreement
specified that if neither of the two specified transactions
occurred during the Initial Period, a sale of the Company in a
business combination on or before August 26, 2007 where the
per share valuation of the Companys common stock in such
sale was equal to or greater than $28.00 per share would result
in the release of the shares held in escrow to the Company for
reissuance to Messrs. Leach, Beal, Copeland, Kamradt and
Wright. These conditions for release of these shares to
Messrs. Leach, Beal, Copeland, Kamradt and Wright were not
met by August 26, 2007, and thereafter the escrow agent
distributed the escrowed shares to the original owners of the
shares.
Defined contribution plan. The Company sponsors a
401(k) defined contribution plan for the benefit of
substantially all employees and maintains certain other acquired
plans. The Company matches 100 percent of employee
contributions, not to exceed 6 percent of the
employees annual salary. The Company contributions to the
plans for the years ended December 31, 2008, 2007 and 2006
were approximately $1.2 million, $419,000, and $321,000,
respectively. The increase in contributions for the year ended
December 31, 2008, were primarily attributable to the
addition of employees due to the Henry Entities acquisition on
July 31, 2008.
Stock incentive plan. The Companys 2006 Stock
Incentive Plan (together with applicable option agreements and
restricted stock agreements, the Plan) provides for
granting stock options and restricted stock awards to employees
and individuals associated with the Company. The following table
shows the number of awards available under the Companys
Plan at December 31, 2008:
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
common
|
|
|
|
shares
|
|
|
|
|
Approved and authorized awards
|
|
|
5,850,000
|
|
Stock option grants, net of forfeitures
|
|
|
(3,343,684
|
)
|
Restricted stock grants, net of forfeitures
|
|
|
(512,809
|
)
|
|
|
|
|
|
Awards available for future grant
|
|
|
1,993,507
|
|
|
|
Restricted stock awards. All restricted shares are
treated as issued and outstanding in the accompanying
consolidated balance sheets. If an employee terminates
employment prior the lapse date, the awarded shares are
forfeited and cancelled and are no longer considered issued
F-62
and outstanding. A summary of the Companys restricted
stock awards for the years ended December 31, 2008, 2007
and 2006 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Grant date
|
|
|
|
restricted
|
|
|
fair value
|
|
|
|
shares
|
|
|
per share
|
|
|
|
|
Restricted stock:
|
|
|
|
|
|
|
|
|
Outstanding at January 1, 2006
|
|
|
|
|
|
|
|
|
Shares granted
|
|
|
213,584
|
|
|
$
|
15.40
|
|
Shares cancelled/forfeited
|
|
|
(1,368
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
212,216
|
|
|
|
|
|
Shares granted
|
|
|
220,995
|
|
|
$
|
9.22
|
|
Shares cancelled/forfeited
|
|
|
(1,662
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
(60,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
371,549
|
|
|
|
|
|
Shares granted
|
|
|
128,001
|
|
|
$
|
32.13
|
|
Shares cancelled/forfeited
|
|
|
(46,741
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
(45,458
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
407,351
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of the impact on the consolidated statements of
operations for the Companys restricted stock awards during
the years ended December 31, 2008, 2007 and 2006 is
presented below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Stock-based compensation expense related to restricted stock
|
|
$
|
2,122
|
|
|
$
|
1,378
|
|
|
$
|
1,044
|
|
Income tax benefit related to restricted stock
|
|
$
|
808
|
|
|
$
|
533
|
|
|
$
|
407
|
|
Deductions in current taxable income related to restricted stock
|
|
$
|
1,234
|
|
|
$
|
|
|
|
$
|
|
|
|
|
Stock option awards. The stock options granted from
August 13, 2004 through February 27, 2006 under the
Stock Option Plan were to purchase Preferred Units. A portion of
the options vested based upon passage of time (Time
Vesting) and a portion of the options vested based upon
the Company obtaining certain results related to a liquidation
value (Performance Vesting). Seventy-eight percent
of the aggregate options granted were vested based on Time
Vesting, in which they vested one-third each year for a three
year period, which would result in approximately
61 percent, 28 percent and 11 percent of their
total grant date fair value being expensed in the first, second
and third years, respectively, commencing on the first
anniversary of the date of grant. The remaining 22 percent
of the aggregate options granted were vested based on
Performance Vesting. Performance Vesting was considered to be
achieved when the Company attained a liquidation valuation which
resulted in a 25 percent internal rate of return and a
return on investment of two times the total dollars invested by
the original shareholders of the Company, upon the occurrence of
one of the following events:
(i) the liquidation, dissolution or winding up of the
affairs of the Company,
F-63
(ii) a sale of all or substantially all of the assets of
the Company and a distribution to the shareholders of the
proceeds of such sale, or
(iii) any merger, consolidation or other transaction
resulting in at least 50 percent of the voting securities
of the Company being owned by a single person or a group.
As a result of the Combination, event (iii) listed above
occurred, which resulted in a change of control as defined in
the Stock Option Plan. As such, the 78 percent of the
aggregate options which vested based on Time Vesting were
immediately vested as of the date of the Combination.
CEHCs board of directors determined that, based upon the
value received by the CEHC shareholders in the Combination, the
thresholds for internal rate of return and return on investment
which determined the portion of vesting based on Performance
Vesting, were not met and that 22 percent portion of the
options were not vested.
The CEHC board of directors determined that CEHC would vest the
22 percent of aggregate stock options based on Performance
Vesting for only the stock option holders who were non-officers,
if CEHCs officers agreed that the 22 percent of
aggregate stock options based on Performance Vesting for the
officers would vest at the end of three years after the closing
of the Combination, which will result in approximately
33 percent, 33 percent and 34 percent of their
total grant date fair value being expensed in the first, second,
and third years, respectively, commencing on the first
anniversary of the date of grant; each officer so agreed.
A summary of CEHCs stock option activity, under the Stock
Option Plan, for the period ended February 27, 2006
(Combination date) is presented below. The amounts shown are
immediately prior to the conversion of CEHC stock options to
Resources stock options as a result of the Combination:
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2006
|
|
|
|
through February 27, 2006
|
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
average
|
|
|
|
unitsa
|
|
|
price
|
|
|
|
|
Outstanding at beginning of period
|
|
|
1,365,075
|
|
|
$
|
10.32
|
|
Options granted
|
|
|
514,267
|
|
|
$
|
10.68
|
|
Options forfeited
|
|
|
|
|
|
$
|
|
|
Options exercised
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
1,879,342
|
|
|
$
|
10.42
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period
|
|
|
1,562,770
|
|
|
$
|
10.51
|
|
|
|
|
|
|
(a)
|
|
Each option Unit can be exercised
for on Preferred Unit which is comprised of one-half of a share
of CEHC common stock and one share of CEHC preferred stock.
|
Also in conjunction with the Combination described in
Note A and Note D and the conversion of CEHC preferred
stock into Resources common stock at the ratio of 0.75:1, the
CEHC unit options were converted into Resources stock options.
Each CEHC unit option, (considered to be exchangeable for one
share of CEHC preferred stock and one-half of a share of CEHC
common stock), was converted into 1.25 options to purchase
common stock of Resources. Each Resources stock option is
considered to be exchangeable for one share of Resources common
stock. The
F-64
following table summarizes the conversion of the CEHC unit
options in conjunction with the Combination:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CEHC
|
|
|
|
|
|
Resources
|
|
|
|
|
CEHC
|
|
unit
|
|
|
Conversion
|
|
|
option
|
|
|
Resources
|
|
unit option exercise price
|
|
options
|
|
|
rate
|
|
|
exercise price
|
|
|
options
|
|
|
|
|
$10.00
|
|
|
1,721,010
|
|
|
|
1.25:1
|
|
|
$
|
8.00
|
|
|
|
2,151,129
|
|
$15.00
|
|
|
158,332
|
|
|
|
1.25:1
|
|
|
$
|
12.00
|
|
|
|
197,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,879,342
|
|
|
|
|
|
|
|
|
|
|
|
2,349,113
|
|
|
|
A summary of the Companys stock option activity under the
Plan, for the years ended December 31, 2008 and 2007 and
for the period from February 27, 2006 through
December 31, 2006 is presented below. The amounts shown
below are on a post-combination and post-conversion basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
February 27,
|
|
|
|
Years ended December 31,
|
|
|
2006 through
|
|
|
|
2008
|
|
|
2007
|
|
|
December 31, 2006
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
average
|
|
|
Number of
|
|
|
average
|
|
|
Number of
|
|
|
average
|
|
|
|
options
|
|
|
exercise price
|
|
|
options
|
|
|
exercise price
|
|
|
options
|
|
|
exercise price
|
|
|
|
|
Stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
3,011,722
|
|
|
$
|
9.71
|
|
|
|
2,797,997
|
|
|
$
|
8.93
|
|
|
|
2,349,113
|
|
|
$
|
8.34
|
|
Options granted
|
|
|
607,555
|
|
|
$
|
23.54
|
|
|
|
215,000
|
|
|
$
|
12.85
|
|
|
|
450,000
|
|
|
$
|
12.00
|
|
Options forfeited
|
|
|
(275,593
|
)
|
|
$
|
14.96
|
|
|
|
(1,275
|
)
|
|
$
|
8.00
|
|
|
|
(1,116
|
)
|
|
$
|
10.88
|
|
Options exercised
|
|
|
(612,360
|
)
|
|
$
|
8.80
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
2,731,324
|
|
|
$
|
12.46
|
|
|
|
3,011,722
|
|
|
$
|
9.71
|
|
|
|
2,797,997
|
|
|
$
|
8.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at end of period
|
|
|
1,567,389
|
|
|
$
|
9.18
|
|
|
|
2,063,499
|
|
|
$
|
8.79
|
|
|
|
1,952,274
|
|
|
$
|
8.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period
|
|
|
517,019
|
|
|
$
|
11.16
|
|
|
|
508,462
|
|
|
$
|
10.58
|
|
|
|
1,952,274
|
|
|
$
|
8.40
|
|
|
|
F-65
The following table summarizes information about the
Companys vested stock options outstanding and exercisable
at December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
|
|
average
|
|
|
|
|
|
|
|
|
|
Number vested
|
|
|
remaining
|
|
exercise
|
|
|
|
|
|
|
|
|
|
and exercisable
|
|
|
contractual life
|
|
price
|
|
|
Intrinsic value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Vested options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
1,232,647
|
|
|
2.58 years
|
|
$
|
8.00
|
|
|
$
|
18,268
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
143,492
|
|
|
4.99 years
|
|
$
|
12.00
|
|
|
|
1,553
|
|
Exercise price
|
|
$
|
14.68
|
|
|
|
191,250
|
|
|
7.78 years
|
|
$
|
14.68
|
|
|
|
1,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,567,389
|
|
|
|
|
$
|
9.18
|
|
|
$
|
21,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
236,227
|
|
|
5.62 years
|
|
$
|
8.00
|
|
|
$
|
3,501
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
89,542
|
|
|
6.78 years
|
|
$
|
12.00
|
|
|
|
969
|
|
Exercise price
|
|
$
|
14.68
|
|
|
|
191,250
|
|
|
7.78 years
|
|
$
|
14.68
|
|
|
|
1,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
517,019
|
|
|
|
|
$
|
11.16
|
|
|
$
|
6,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
1,753,819
|
|
|
3.15 years
|
|
$
|
8.00
|
|
|
$
|
22,116
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
197,180
|
|
|
5.72 years
|
|
$
|
12.00
|
|
|
|
1,698
|
|
Exercise price
|
|
$
|
15.40
|
|
|
|
112,500
|
|
|
8.45 years
|
|
$
|
15.40
|
|
|
|
586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,063,499
|
|
|
|
|
$
|
10.58
|
|
|
$
|
24,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
275,685
|
|
|
6.62 years
|
|
$
|
8.00
|
|
|
$
|
3,476
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
120,277
|
|
|
7.78 years
|
|
$
|
12.00
|
|
|
|
1,036
|
|
Exercise price
|
|
$
|
15.40
|
|
|
|
112,500
|
|
|
8.45 years
|
|
$
|
15.40
|
|
|
|
586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
508,462
|
|
|
|
|
$
|
10.58
|
|
|
$
|
5,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
1,755,094
|
|
|
8.47 years
|
|
$
|
8.00
|
|
|
$
|
15,099
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
197,180
|
|
|
8.86 years
|
|
$
|
12.00
|
|
|
|
769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,952,274
|
|
|
|
|
$
|
8.40
|
|
|
$
|
15,868
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-66
The following table summarizes information about stock-based
compensation for options which is recognized in general and
administrative expense in the accompanying consolidated
statement of operations for the years ended December 31,
2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Grant date fair value for awards during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting
optionsa
|
|
$
|
580
|
|
|
$
|
87
|
|
|
$
|
1,931
|
|
Performance vesting options:
|
|
|
|
|
|
|
|
|
|
|
|
|
Officersb
|
|
|
|
|
|
|
|
|
|
|
531
|
|
Non-officersc
|
|
|
|
|
|
|
|
|
|
|
142
|
|
Stock option grants under the
Pland
|
|
|
5,675
|
|
|
|
1,921
|
|
|
|
3,555
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,255
|
|
|
$
|
2,008
|
|
|
$
|
6,159
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock
options:
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting
optionsa
|
|
$
|
181
|
|
|
$
|
17
|
|
|
$
|
5,085
|
|
Performance vesting options:
|
|
|
|
|
|
|
|
|
|
|
|
|
Officersb
|
|
|
253
|
|
|
|
602
|
|
|
|
511
|
|
Non-officersc
|
|
|
|
|
|
|
|
|
|
|
505
|
|
Stock option grants under the
Pland
|
|
|
2,667
|
|
|
|
1,844
|
|
|
|
1,024
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,101
|
|
|
$
|
2,463
|
|
|
$
|
7,125
|
|
|
|
|
|
|
|
Income taxes and other information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to stock options
|
|
$
|
1,990
|
|
|
$
|
953
|
|
|
$
|
2,779
|
|
Deductions in current taxable income related to stock options
exercised
|
|
$
|
10,756
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
(a)
|
|
Options granted prior to
February 27, 2006, vested immediately as of the date of the
Combination, as a result of a change of control. Options granted
thereafter vest using a four year graded vesting schedule by
approval from the Board of Directors.
|
|
(b)
|
|
Options granted prior to
February 27, 2006, vest using a three year cliff vesting
schedule by approval from CEHCs Board of Directors.
|
|
|
|
(c)
|
|
Vested as of the date of the
Combination by approval from CEHCs Board of Directors.
|
|
|
|
(d)
|
|
Vest using a three or four year
graded vesting schedule by approval from the Board of Directors.
The 2007 grant date fair value includes an adjustment of
$765,000 from a change in fair value due to the Code
Section 409A (defined later) option modification.
|
In calculating the compensation expense for options, the Company
has estimated the fair value of each grant using the
Black-Scholes option-pricing model. Assumptions utilized in the
model are shown below. Amounts shown are assumptions under the
Plan for options exercisable for Resources common stock at a
rate of 1:1:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Risk-free interest rate
|
|
|
3.18%
|
|
|
|
4.47%
|
|
|
|
4.81%
|
|
Expected term (years)
|
|
|
6.21
|
|
|
|
6.25
|
|
|
|
2.87
|
|
Expected volatility
|
|
|
38.88%
|
|
|
|
37.33%
|
|
|
|
37.12%
|
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock option modifications. On November 8,
2007, the compensation committee of the Companys board of
directors authorized and approved amendments to certain
outstanding agreements related to options to purchase the
Companys common stock that were previously awarded to
certain of the Companys executive officers and employees
in order to amend such
F-67
award agreements so that the subject stock option award would
constitute deferred compensation that is compliant with
Section 409A of the Internal Revenue Code of 1986, as
amended (the Code), or exempt from the application
of Code Section 409A. As the offer to amend outstanding
stock option agreements previously issued to certain of the
Companys employees may constitute a tender offer under the
Securities Exchange Act of 1934, on November 8, 2007, the
board of directors of the Company authorized commencement of a
tender offer to amend the applicable outstanding stock option
award agreements in the form approved by the compensation
committee.
Generally, the amendments provide that the employee stock
options, which had previously vested in connection with the
Combination, will become exercisable in 25 percent
increments over a four year period beginning in 2008 and
continuing through 2011 or upon the occurrence of certain
specified events. Employees who decided to amend their stock
option award agreement received a cash payment equal to $0.50
for each share of common stock subject to the amendment on
January 2, 2008. The Company made aggregate cash payments
of approximately $192,000 to such employees. The Companys
affected executive officers received and accepted a similar
offer to amend their stock option awards issued prior to the
Combination on substantially the same terms, except such
officers were not offered the $0.50 per share payment.
In addition, the Companys named executive officers
received stock option awards in June 2006 to purchase
450,000 shares of common stock, in the aggregate, at a
purchase price of $12.00 per share. The Company subsequently
determined that the fair market value of a share of common stock
as of the date of the award was $15.40. As a result, the
compensation committee of the Companys board of directors
authorized and approved an amendment to these stock option award
agreements pursuant to which the exercise price of such stock
options would be increased from $12.00 per share to $15.40 per
share. The Company agreed to issue to the executive officer an
award of the number of shares of restricted stock equal to
(i) the product of $3.40 and the number of shares of common
stock subject to the stock option award, divided by
(ii) the Fair Market Value of a share of common stock on
the date of the award of restricted stock.
The Company has determined that its aggregate compensation
expense resulting from these modifications of approximately
$0.8 million will be recorded during the period from
November 8, 2007 to December 31, 2007 and during the
years ending December 31, 2008, 2009 and 2010.
Future stock-based compensation expense. The
following table reflects the future stock-based compensation
expense to be recorded for all the stock-based compensation
awards that are outstanding at December 31, 2008 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
|
|
|
Stock
|
|
|
|
|
|
|
stock
|
|
|
options
|
|
|
Total
|
|
|
|
|
2009
|
|
$
|
2,470
|
|
|
$
|
2,701
|
|
|
$
|
5,171
|
|
2010
|
|
|
1,393
|
|
|
|
1,242
|
|
|
|
2,635
|
|
2011
|
|
|
475
|
|
|
|
466
|
|
|
|
941
|
|
2012
|
|
|
40
|
|
|
|
55
|
|
|
|
95
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,378
|
|
|
$
|
4,464
|
|
|
$
|
8,842
|
|
|
|
F-68
|
|
Note H.
|
Disclosures
about fair value of financial instruments
|
The Company adopted SFAS No. 157, Fair Value
Measurements, (SFAS No. 157)
effective January 1, 2008 for financial assets and
liabilities measured on a recurring basis.
SFAS No. 157 applies to all financial assets and
financial liabilities that are being measured and reported on a
fair value basis. In February 2008, the FASB issued FSP
No. 157-2,
which delayed the effective date of SFAS No. 157 by
one year for nonfinancial assets and liabilities. As defined in
SFAS No. 157, fair value is the price that would be
received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the
measurement date. SFAS No. 157 requires disclosure
that establishes a framework for measuring fair value and
expands disclosure about fair value measurements. The statement
requires fair value measurements be classified and disclosed in
one of the following categories:
Level 1: Unadjusted quoted prices in active
markets that are accessible at the measurement date for
identical, unrestricted assets or liabilities. The Company
considers active markets to be those in which transactions for
the assets or liabilities occur in sufficient frequency and
volume to provide pricing information on an ongoing basis.
Level 2: Quoted prices in markets that are not
active, or inputs which are observable, either directly or
indirectly, for substantially the full term of the asset or
liability. This category includes those derivative instruments
that the Company values using observable market data.
Substantially all of these inputs are observable in the
marketplace throughout the full term of the derivative
instrument, can be derived from observable data, or supported by
observable levels at which transactions are executed in the
marketplace. Level 2 instruments primarily include
non-exchange traded derivatives such as
over-the-counter
commodity price swaps, investments and interest rate swaps. The
Companys valuation models are primarily industry-standard
models that consider various inputs including: (i) quoted
forward prices for commodities, (ii) time value and
(iii) current market and contractual prices for the
underlying instruments, as well as other relevant economic
measures. The Company utilizes our counterparties
valuations to assess the reasonableness of our prices and
valuation techniques.
Level 3: Measured based on prices or valuation
models that require inputs that are both significant to the fair
value measurement and less observable from objective sources (
i.e. , supported by little or no market activity).
Level 3 instruments primarily include derivative
instruments, such as basis swaps, commodity price collars and
floors, as well as investments. The Companys valuation
models are primarily industry-standard models that consider
various inputs including: (i) quoted forward prices for
commodities, (ii) time value, (iii) volatility factors
and (iv) current market and contractual prices for the
underlying instruments, as well as other relevant economic
measures. Although the Company utilizes our counterparties
valuations to assess the reasonableness of our prices and
valuation techniques, the Company does not have sufficient
corroborating market evidence to support classifying these
assets and liabilities as Level 2.
The following represents information about the estimated fair
values of the Companys financial instruments:
Cash and cash equivalents, accounts receivable, other current
assets, accounts payable, interest payable and other current
liabilities. The carrying amounts approximate fair
value due to the short maturity of these instruments.
F-69
Notes receivableofficers and employees. The
carrying amounts approximate fair value due to the comparability
of the interest rate to risk-adjusted rates for similar
financial instruments.
Line of credit and term note. The carrying amount of
borrowings outstanding under the Companys revolving credit
facility and term note (see Note J) approximate fair
value because the instruments bear interest at variable market
rates.
Derivative instruments. The fair value of the
derivative instruments are estimated by management considering
various factors, including closing exchange and
over-the-counter
quotations and the time value of the underlying commitments. As
required by SFAS No. 157, financial assets and
liabilities are classified based on the lowest level of input
that is significant to the fair value measurement. The
Companys assessment of the significance of a particular
input to the fair value measurement requires judgment, and may
affect the valuation of the fair value of assets and liabilities
and their placement within the fair value hierarchy levels. The
following table summarizes the valuation of the Companys
financial instruments by SFAS No. 157 pricing levels
at December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
Total carrying
|
|
|
|
Quoted prices in
|
|
|
Significant other
|
|
|
unobservable
|
|
|
value at
|
|
|
|
active markets
|
|
|
observable inputs
|
|
|
inputs
|
|
|
December 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2008
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
124,641
|
|
|
$
|
|
|
|
$
|
124,641
|
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
(680
|
)
|
|
|
|
|
|
|
(680
|
)
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
(1,083
|
)
|
|
|
|
|
|
|
(1,083
|
)
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
49,562
|
|
|
|
49,562
|
|
|
|
|
|
|
|
Total financial assets (liabilities)
|
|
$
|
|
|
|
$
|
122,878
|
|
|
$
|
49,562
|
|
|
$
|
172,440
|
|
|
|
The following table sets forth a reconciliation of changes in
the fair value of financial assets and liabilities classified as
Level 3 in the fair value hierarchy (in thousands):
|
|
|
|
|
Balance at January 1, 2008
|
|
$
|
1,866
|
|
Realized and unrealized gains
|
|
|
49,122
|
|
Purchases, issuances, and settlements
|
|
|
(1,426
|
)
|
|
|
|
|
|
Balance at December 31, 2008
|
|
$
|
49,562
|
|
|
|
|
|
|
Total gains for the period included in earnings attributable to
the change in unrealized gains relating to assets still held at
the reporting date
|
|
$
|
47,696
|
|
|
|
For additional information on the Companys derivative
instruments see Note I.
F-70
|
|
Note I.
|
Derivative
financial instruments
|
The Company uses financial derivative contracts to manage
exposures to commodity price and interest rate. Commodity hedges
are used to (i) reduce the effect of the volatility of
price changes on the natural gas and crude oil the Company
produces and sells, (ii) support the Companys annual
capital budget and expenditure plans and (iii) support the
economics associated with acquisitions. Interest rate hedges are
used to hedge our mitigate the cash flow risk associated with
rising interest rates. The Company does not enter into
derivative financial instruments for speculative or trading
purposes. The Company also may enter physical delivery contracts
to effectively provide commodity price hedges. Because these
contracts are not expected to be net cash settled, they are
considered to be normal sales contracts and not derivatives.
Therefore, these contracts are not recorded in the financial
statements.
Currently, the Company does not designate its derivative
instruments to qualify for hedge accounting. Accordingly, the
Company reflects the changes in the fair value of its derivative
instruments in the statements of operations.
A key requirement for designation of derivative instruments to
qualify for hedge accounting is that at both the inception of
the hedge and on an ongoing basis, the hedging relationship is
expected to be highly effective in achieving offsetting cash
flows attributable to the hedged risk during the term of the
hedge. Generally, the hedging relationship can be considered to
be highly effective if there is a high degree of historical
correlation between the hedging instrument and the forecasted
transaction. For all quarters ended prior to July 1, 2007,
prices received for the Companys natural gas were highly
correlated with the Inside FERCEl Paso Natural Gas
index (the Index)the Index referenced in all
of the Companys natural gas derivative instruments.
However, during the quarter ended September 30, 2007, this
historical relationship did not meet the criteria as being
highly correlated. Natural gas produced from the Companys
New Mexico shelf assets has a substantial component of natural
gas liquids. Prices received for natural gas liquids are not
highly correlated to the price of natural gas, but are more
closely correlated to the price of oil. During the third quarter
of 2007, the price of oil and natural gas liquids, and
therefore, the prices the Company received for its natural gas
(including natural gas liquids) rose substantially and at a
significantly higher rate than the corresponding change in the
Index. This resulted in a decrease in correlation between the
prices received and the Index below the level required for cash
flow hedge accounting. According to SFAS No. 133, an
entity shall discontinue hedge accounting prospectively for an
existing hedge if the hedge is no longer highly effective. Hedge
accounting must be discontinued regardless of whether the
Company believes the hedge will be prospectively highly
effective. The hedge must be discontinued during the period the
hedges became ineffective. As a result, any changes in fair
value must be recorded in earnings. Because the natural gas and
natural gas liquids prices fluctuate at different rates over
time, the loss of effectiveness does not relate to any single
date.
During the three months ended June 30, 2007, the Company
determined that all of its natural gas commodity contracts no
longer qualified as hedges under the requirements of
SFAS No. 133 for the reason stated in the above
paragraph. These contracts are referred to as dedesignated
hedges.
Therefore, June 30, 2007, was considered the last date the
Companys natural gas hedges were highly effective, and the
Company discontinued hedge accounting during the three months
ended September 30, 2007 and all periods thereafter.
Mark-to-market
adjustments related to these dedesignated hedges are recorded
each period to earnings. Effective portions of dedesignated
hedges, previously recorded in AOCI at June 30, 2007,
remain in AOCI and are
F-71
being reclassified into earnings under natural gas revenues,
during the periods which the hedged forecasted transaction
affects earnings.
2008 commodity derivative contracts. During the year
ended December 31, 2008, the Company entered into
additional commodity derivative contracts to hedge a portion of
its estimated future production. The following table summarizes
information about these additional commodity derivative
contracts at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
remaining
|
|
|
Daily
|
|
|
Index
|
|
|
contract
|
|
|
|
volume
|
|
|
volume
|
|
|
price
|
|
|
period
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
|
768,000
|
|
|
|
2,104
|
|
|
$
|
120.00 -
$134.60a
|
|
|
|
1/1/09-12/31/09
|
|
Price swap
|
|
|
292,000
|
|
|
|
800
|
|
|
$
|
98.35a
|
|
|
|
1/1/09-12/31/09
|
|
Price swap
|
|
|
348,000
|
|
|
|
953
|
|
|
$
|
125.10a
|
|
|
|
1/1/09-12/31/09
|
|
Price swap
|
|
|
240,000
|
|
|
|
658
|
|
|
$
|
128.80a
|
|
|
|
1/1/10-12/31/10
|
|
Price swap
|
|
|
336,000
|
|
|
|
921
|
|
|
$
|
128.66a
|
|
|
|
1/1/11-12/31/11
|
|
Price swap
|
|
|
504,000
|
|
|
|
1,377
|
|
|
$
|
127.80a
|
|
|
|
1/1/12-12/31/12
|
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
1,825,000
|
|
|
|
5,000
|
|
|
$
|
8.44b
|
|
|
|
1/1/09-12/31/09
|
|
Index basis swap
|
|
|
6,022,500
|
|
|
|
16,500
|
|
|
$
|
1.08c
|
|
|
|
1/1/09-12/31/09
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price.
|
|
(b)
|
|
The index price for the natural gas
price collar is based on the Inside FERC-El Paso Permian
Basin
first-of-the-month
spot price.
|
|
|
|
(c)
|
|
Represents the basis differential
between the El Paso Permian delivery point and NYMEX Henry
Hub delivery point.
|
Commodity derivative contracts assumed in the Henry Entities
acquisition. As part of the Henry Entities acquisition,
the Company assumed the following commodity derivative contracts
on July 31, 2008. The following table summarizes
information about the remaining portion of these assumed
derivative contracts at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
remaining
|
|
Daily
|
|
Index
|
|
Remaining
|
|
|
volume
|
|
volume
|
|
price
|
|
contract period
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
Price swap
|
|
443,491
|
|
1,215
|
|
$73.59a
|
|
1/1/09-12/31/09
|
Price swap
|
|
401,746
|
|
1,101
|
|
$72.03a
|
|
1/1/10-12/31/10
|
Price swap
|
|
221,746
|
|
608
|
|
$68.92a
|
|
1/1/11-12/31/11
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price and the prices represent weighted average
prices.
|
2008 interest rate derivative contracts. During
2008, the Company entered into interest rate derivative
contracts to hedge a portion of its future interest rate
exposure. The Company hedged its LIBOR interest rate on the
Companys bank debt by fixing the rate at 1.90 percent
for three years beginning in May of 2009 on $300 million of
the Companys bank debt. The interest rate derivative
contracts were not designated as cash flow hedges.
F-72
The following table sets forth the Companys outstanding
derivative contracts at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
remaining
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
volume/
|
|
|
|
|
|
Index
|
|
|
Remaining
|
|
|
|
Fair value
|
|
|
notional
|
|
|
Daily
|
|
|
price /
|
|
|
contract
|
|
|
|
asset (liability)
|
|
|
amount
|
|
|
volume
|
|
|
rate
|
|
|
period
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
$
|
49,562
|
|
|
|
768,000
|
|
|
|
2,104
|
|
|
$
|
120.00 -
$134.60a
|
|
|
|
1/1/09-12/31/09
|
|
Price swap
|
|
|
58,269
|
|
|
|
1,813,491
|
|
|
|
4,968
|
|
|
$
|
87.16a c
|
|
|
|
1/1/09-12/31/09
|
|
Price swap
|
|
|
17,948
|
|
|
|
641,746
|
|
|
|
1,758
|
|
|
$
|
93.26a c
|
|
|
|
1/1/10-12/31/10
|
|
Price swap
|
|
|
18,191
|
|
|
|
557,746
|
|
|
|
1,528
|
|
|
$
|
104.91a c
|
|
|
|
1/1/11-12/31/11
|
|
Price swap
|
|
|
24,339
|
|
|
|
504,000
|
|
|
|
1,377
|
|
|
$
|
127.80a
|
|
|
|
1/1/12-12/31/12
|
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
5,894
|
|
|
|
1,825,000
|
|
|
|
5,000
|
|
|
$
|
8.44b
|
|
|
|
1/1/09-12/31/09
|
|
Basis swap
|
|
|
(680
|
)
|
|
|
6,022,500
|
|
|
|
16,500
|
|
|
$
|
1.08d
|
|
|
|
1/1/09-12/31/09
|
|
Interest rate (notional amount in dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rate swap
|
|
|
(1,083
|
)
|
|
$
|
300,000,000
|
|
|
|
|
|
|
|
1.90%e
|
|
|
|
5/1/09-4/30/12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net asset
|
|
$
|
172,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price.
|
|
(b)
|
|
The index price for the natural gas
price collar is based on the Inside FERC-El Paso Permian
Basin
first-of-the-month
spot price.
|
|
|
|
(c)
|
|
Prices represent weighted-average
prices.
|
|
|
|
(d)
|
|
Represents the basis differential
between the El Paso Permian delivery point and the NYMEX
Henry Hub delivery point.
|
|
(e)
|
|
The index rate is based on the
one-month LIBOR.
|
F-73
The Companys reported oil and gas revenue and average oil
and gas prices includes the effects of oil quality and Btu
content, gathering and transportation costs, gas processing and
shrinkage, and the net effect of the commodity hedges that
qualified for cash flow hedge accounting. The following table
summarizes the gains and losses reported in earnings related to
the commodity and interest rate derivative instruments and the
net change in AOCI (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Increase (decrease) in oil and gas revenue from derivative
activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments on cash flow hedges in oil sales
|
|
$
|
(30,591
|
)
|
|
$
|
(11,091
|
)
|
|
$
|
(7,000
|
)
|
Cash receipts from cash flow hedges in gas sales
|
|
|
|
|
|
|
188
|
|
|
|
1,232
|
|
Dedesignated cash flow hedges reclassified from AOCI in gas sales
|
|
|
(696
|
)
|
|
|
1,103
|
|
|
|
|
|
|
|
|
|
|
|
Total decrease in oil and gas revenue from derivative activity
|
|
$
|
(31,287
|
)
|
|
$
|
(9,800
|
)
|
|
$
|
(5,768
|
)
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as
hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
gain (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
257,307
|
|
|
$
|
(22,089
|
)
|
|
$
|
|
|
Interest rate derivatives
|
|
|
(1,083
|
)
|
|
|
|
|
|
|
|
|
Cash (payments) receipts on derivatives not designated as
hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
(6,354
|
)
|
|
|
1,815
|
|
|
|
|
|
Interest rate derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives not designated as hedges
|
|
$
|
249,870
|
|
|
$
|
(20,274
|
)
|
|
$
|
|
|
|
|
|
|
|
|
Gain (loss) from ineffective portion of cash flow
hedges:
|
|
$
|
1,336
|
|
|
$
|
(821
|
)
|
|
$
|
1,193
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
gain (loss) of cash flow hedges
|
|
$
|
(7,985
|
)
|
|
$
|
(33,783
|
)
|
|
$
|
11,936
|
|
Reclassification adjustment of losses to earnings
|
|
|
30,591
|
|
|
|
10,903
|
|
|
|
5,768
|
|
Net AOCI upon dedesignation at June 30, 2007
|
|
|
|
|
|
|
(407
|
)
|
|
|
|
|
|
|
|
|
|
|
Net change, before income taxes
|
|
|
22,606
|
|
|
|
(23,287
|
)
|
|
|
17,704
|
|
Income tax effect
|
|
|
(8,835
|
)
|
|
|
9,102
|
|
|
|
(6,230
|
)
|
|
|
|
|
|
|
Net change, net of income taxes
|
|
$
|
13,771
|
|
|
$
|
(14,185
|
)
|
|
$
|
11,474
|
|
|
|
|
|
|
|
Dedesignated cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net AOCI upon dedesignation at June 30, 2007
|
|
$
|
|
|
|
$
|
407
|
|
|
$
|
|
|
Reclassification adjustment of (gains) losses to earnings
|
|
|
696
|
|
|
|
(1,103
|
)
|
|
|
|
|
Income tax effect
|
|
|
(272
|
)
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
Net change, net of income taxes
|
|
$
|
424
|
|
|
$
|
(424
|
)
|
|
$
|
|
|
|
|
All of the Companys commodity derivative contracts are
expected to settle by December 31, 2012. All the
Companys commodity derivative contracts previously
accounted for as cash flow hedges and designated as hedges were
settled on December 31, 2008.
F-74
Post 2008 commodity derivative contracts. After
December 31, 2008 and through February 19, 2009, the
Company entered into the following additional commodity
derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
remaining
|
|
|
Daily
|
|
|
Index
|
|
|
contract
|
|
|
|
volume
|
|
|
volume
|
|
|
price
|
|
|
period
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
600,000
|
|
|
|
1,644
|
|
|
$
|
57.55a
|
|
|
|
1/1/10-12/31/10
|
|
Price collar
|
|
|
600,000
|
|
|
|
6,522
|
|
|
$
|
45.00-$49.00a
|
|
|
|
3/1/09-5/31/09
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price.
|
The Companys debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Senior credit facility
|
|
$
|
630,000
|
|
|
$
|
216,000
|
|
2nd lien credit facility
|
|
|
|
|
|
|
109,900
|
|
Unamortized original issue discount on 2nd lien credit facility
|
|
|
|
|
|
|
(496
|
)
|
|
|
|
|
|
|
Total long-term debt
|
|
|
630,000
|
|
|
|
325,404
|
|
Current portion of 2nd lien credit facility
|
|
|
|
|
|
|
2,000
|
|
|
|
|
|
|
|
Total debt
|
|
$
|
630,000
|
|
|
$
|
327,404
|
|
|
|
Senior credit facility. On July 31, 2008, the
Company amended and restated its senior credit facility in
various respects, including increasing the borrowing base to
$960 million, subject to scheduled semiannual
redeterminations, and extending the maturity date to
July 31, 2013 (the Senior Credit Facility). The
Company paid an arrangement fee of $14.4 million upon
closing the Senior Credit Facility. At December 31, 2008,
the Company had letters of credit outstanding under the Senior
Credit Facility of approximately $275,000 and its availability
to borrow additional funds was $329.7 million. In October
2008, the Companys $960 million borrowing base was
reaffirmed until the next scheduled borrowing base
redetermination in April 2009. Between scheduled borrowing base
redeterminations the Company and, if requested by 66
2 / 3 percent of the lenders, the lenders may
each request one special redetermination.
Advances on the Senior Credit Facility bear interest, at the
Companys option, based on (i) the prime rate of
JPMorgan Chase Bank (JPM Prime Rate)
(3.25 percent at December 31, 2008) or
(ii) a Eurodollar rate (substantially equal to the London
Interbank Offered Rate). The interest rates of Eurodollar rate
advances and JPM Prime Rate advances vary, with interest margins
ranging from 125 to 275 basis points and zero to
125 basis points, respectively, per annum depending on the
balance outstanding. The Company pays commitment fees on the
unused portion of the available borrowing base ranging from 25
to 50 basis points per annum.
The Senior Credit Facility also includes a
same-day
advance facility under which the Company may borrow funds on a
daily basis from the administrative agent. Same day advances
cannot exceed $25 million and the maturity dates cannot
exceed fourteen days. The interest rate on this facility is the
JPM Prime Rate plus the applicable interest margin.
F-75
The Companys obligations under the Senior Credit Facility
are secured by a first lien on substantially all of the
Companys oil and gas properties. In addition, all of the
Companys subsidiaries are guarantors and all general
partner, limited partner and membership interests in the
Companys subsidiaries owned by the Company have been
pledged to secure borrowings under the Senior Credit Facility.
The credit agreement contains various restrictive covenants and
compliance requirements which include (a) maintenance of
certain financial ratios including (i) maintenance of a
quarterly ratio of total debt to consolidated earnings before
interest expense, income taxes, depletion, depreciation, and
amortization, exploration expense and other noncash income and
expenses to be no greater than 4.0 to 1.0, and
(ii) maintenance of a ratio of current assets to current
liabilities, excluding noncash assets and liabilities related to
financial derivatives and asset retirement obligations and
including the unfunded amounts under the Senior Credit Facility,
to be no less than 1.0 to 1.0; (b) limits on the incurrence
of additional indebtedness and certain types of liens;
(c) restrictions as to mergers and sales or transfer of
assets; and (d) a restriction on the payment of cash
dividends. At December 31, 2008, the Company was in
compliance with its debt covenants.
2nd lien credit facility. On March 27,
2007, the Company entered into a second lien credit facility
(the 2nd Lien Credit Facility), for a term loan
facility in the amount of $200 million. The 2nd Lien
Credit Facility was fully paid on July 31, 2008 from
proceeds from the Companys Senior Credit Facility and the
facility was terminated.
Principal maturities of long-term debt. Principal
maturities of long-term debt outstanding at December 31,
2008 are as follows (in thousands):
|
|
|
|
|
|
2009
|
|
$
|
|
|
2010
|
|
|
|
|
2011
|
|
|
|
|
2012
|
|
|
|
|
2013
|
|
|
630,000
|
|
|
|
|
|
|
Total
|
|
$
|
630,000
|
|
|
|
Interest expense. The following amounts have been
incurred and charged to interest expense for the years ended
December 31, 2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Cash payments for interest
|
|
$
|
27,747
|
|
|
$
|
41,036
|
|
|
$
|
23,882
|
|
Amortization of original issue discount
|
|
|
58
|
|
|
|
98
|
|
|
|
|
|
Amortization of deferred loan origination costs
|
|
|
2,157
|
|
|
|
1,338
|
|
|
|
1,494
|
|
Write-off of deferred loan origination costs and original issue
discount
|
|
|
1,547
|
|
|
|
2,631
|
|
|
|
|
|
Net changes in accruals
|
|
|
(1,237
|
)
|
|
|
(6,414
|
)
|
|
|
7,320
|
|
|
|
|
|
|
|
Interest costs incurred
|
|
|
30,272
|
|
|
|
38,689
|
|
|
|
32,696
|
|
Less: capitalized interest
|
|
|
(1,233
|
)
|
|
|
(2,647
|
)
|
|
|
(2,129
|
)
|
|
|
|
|
|
|
Total interest expense
|
|
$
|
29,039
|
|
|
$
|
36,042
|
|
|
$
|
30,567
|
|
|
|
F-76
|
|
Note K.
|
Commitments
and contingencies
|
Severance agreements. The Company has entered into
severance and change in control agreements with all of its
officers. The current annual salaries for the Companys
officers covered under such agreements total approximately
$2.4 million.
Indemnifications. The Company has agreed to
indemnify its directors and officers, employees and agents with
respect to claims and damages arising from acts or omissions
taken in such capacity, as well as with respect to certain
litigation.
Legal actions. The Company is a party to proceedings
and claims incidental to its business. While many of these
matters involve inherent uncertainty, the Company believes that
the amount of the liability, if any, ultimately incurred with
respect to such proceedings and claims will not have a material
adverse effect on the Companys consolidated financial
position as a whole or on its liquidity, capital resources or
future annual results of operations. The Company will continue
to evaluate litigation against the Company on a
quarter-by-quarter
basis and will establish and adjust any reserves as appropriate
to reflect its assessment of the then current status of the
matters.
Acquisition commitments. In connection with the
Acquisition, the Company agreed to pay certain employees of the
Henry Entities bonuses of approximately $11.0 million in
the aggregate at each of the first and second anniversaries of
the closing of the Acquisition, respectively. Except as
described below, these employees must remain employed with the
Company to receive the bonus. A Henry Entities employee who is
otherwise entitled to a full bonus will receive the full bonus
(i) if the Company terminates the employee without cause,
(ii) upon death or disability of such employee or
(iii) upon a change in control of the Company. If such
employee resigns or is terminated for cause the employee will
not receive the bonus and the Company will be required to pay
the sellers in the Acquisition 65 percent of the bonus
amount not paid to the employee. The Company will reflect the
bonus amounts to be paid to these employees as a period cost
which will be included in the Companys results of
operations over the period earned. Amounts that ultimately are
determined to be paid to the sellers will be treated as a
contingent purchase price and reflected as an
adjustment to the purchase price. During 2008, the Company
recognized $4.3 million of the obligation in its results of
operations and $0.7 million as contingent purchase price.
Daywork commitments. The Company periodically enters
into contractual arrangements under which the Company is
committed to expend funds to drill wells in the future,
including agreements to secure drilling rig services, which
require the Company to make future minimum payments to the rig
operators. The Company records drilling commitments in the
periods in
F-77
which well capital is incurred or rig services are provided. The
following table summarizes the Companys future drilling
commitments at December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment due by period
|
|
|
|
|
|
|
Less than
|
|
|
1-3
|
|
|
3-5
|
|
|
More than
|
|
|
|
Total
|
|
|
1 year
|
|
|
years
|
|
|
years
|
|
|
5 years
|
|
|
|
|
Daywork drilling contracts
|
|
$
|
5,584
|
|
|
$
|
5,584
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Daywork drilling contracts with related
partiesa
|
|
|
12,296
|
|
|
|
12,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daywork drilling contracts assumed in the Henry Properties
acquisitionb
|
|
|
10,850
|
|
|
|
7,978
|
|
|
|
2,872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual drilling commitments
|
|
$
|
28,730
|
|
|
$
|
25,858
|
|
|
$
|
2,872
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
(a)
|
|
Consists of daywork drilling
contracts with Silver Oak Drilling, LLC, an affiliate of the
Chase Group.
|
|
(b)
|
|
A major oil and gas company which
owns an interest in the wells being drilled and the Company are
parties to these contracts. Only the Companys 25% share of
the contract obligation has been reflected above.
|
Operating leases. The Company leases vehicles,
equipment and office facilities under non-cancellable operating
leases. Lease payments associated with these operating leases
for the years ended December 31, 2008, 2007 and 2006 were
approximately $720,000, $288,000 and $685,000, respectively.
Future minimum lease commitments under non-cancellable operating
leases at December 31, 2008 are as follows (in thousands):
|
|
|
|
|
|
2009
|
|
$
|
970
|
|
2010
|
|
|
985
|
|
2011
|
|
|
989
|
|
2012
|
|
|
981
|
|
2013
|
|
|
818
|
|
|
|
|
|
|
Total
|
|
$
|
4,743
|
|
|
|
The Company accounts for income taxes in accordance with the
provisions of SFAS No. 109. The Company and its
subsidiaries file federal corporate income tax returns on a
consolidated basis. The tax returns and the amount of taxable
income or loss are subject to examination by United States
federal and state taxing authorities.
The Companys provision for income taxes differed from the
U.S. statutory rate of 35 percent primarily due to
state income taxes and non-deductible expenses. The effective
income tax rate for the years ended December 31, 2008, 2007
and 2006 was 36.8 percent, 38.7 percent and
42.2 percent, respectively.
SFAS No. 109 requires that the Company continually
assess both positive and negative evidence to determine whether
it is more likely than not that deferred tax assets can be
realized prior to their expiration. Management monitors
Company-specific, oil and gas industry and worldwide economic
factors and assesses the likelihood that the Companys net
operating loss carryforwards (NOLs) and other
deferred tax attributes in the United States, state, and local
tax
F-78
jurisdictions will be utilized prior to their expiration. At
December 31, 2008 and 2007, the Company had no valuation
allowances related to its deferred tax assets.
The Company adopted the provisions of FASB Interpretation
No. 48 Accounting for Uncertainty in Income Taxes
(FIN No. 48) an interpretation
of FASB Statement No. 109 Accounting for Income
Taxes, on January 1, 2007. At the time of
adoption and at December 31, 2008, the Company did not have
any significant uncertain tax positions requiring recognition in
the financial statements. The tax years 2004 through 2008 remain
subject to examination by major tax jurisdictions.
The FASB issued
FIN No. 48-1,
Definition of Settlement in FASB Interpretation
No. 48,
(FIN No. 48-1)
to clarify when a tax position is effectively settled.
FIN No. 48-1
provides guidance in determining the proper timing for
recognizing tax benefits and applying the new information
relevant to the technical merits of a tax position obtained
during a tax authority examination.
FIN No. 48-1
provides criteria to determine whether a tax position is
effectively settled after completion of a tax authority
examination, even if the potential legal obligation remains
under the statute of limitations. The Companys adoption of
this pronouncement did not have a significant effect on its
consolidated financial statements.
Texas margins tax. On May 18, 2006, the
Governor of Texas signed into law House Bill 3
(HB-3) which modifies the existing franchise tax
law. The modified franchise tax will be computed by subtracting
either costs of goods sold or compensation expense, as defined
in HB-3, from gross revenue to arrive at a gross margin. The
resulting gross margin will be taxed at a one percent rate. HB-3
has also expanded the definition of tax-paying entities to
include limited partnerships. HB-3 became effective for
activities occurring on or after January 1, 2007.
The portion of tax expense attributable to the enactment of the
Texas margin tax was $226,000 and $113,000 for the years ended
December 31, 2008 and 2007, respectively.
Income tax provision. The Companys income tax
provision and amounts separately allocated were attributable to
the following items for the years ended December 31, 2008,
2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Income from operations
|
|
$
|
162,085
|
|
|
$
|
16,019
|
|
|
$
|
14,379
|
|
Changes in stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred hedge gains (losses)
|
|
|
(3,121
|
)
|
|
|
(13,204
|
)
|
|
|
4,200
|
|
Net settlement losses included in earnings
|
|
|
12,228
|
|
|
|
3,830
|
|
|
|
2,030
|
|
Tax benefits related to stock-based compensation
|
|
|
(3,614
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
167,578
|
|
|
$
|
6,645
|
|
|
$
|
20,609
|
|
|
|
F-79
The Companys income tax provision attributable to income
from operations consisted of the following for the years ended
December 31, 2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
$
|
8,080
|
|
|
$
|
1,902
|
|
|
$
|
1,527
|
|
U.S. state and local
|
|
|
521
|
|
|
|
401
|
|
|
|
234
|
|
|
|
|
|
|
|
|
|
|
8,601
|
|
|
|
2,303
|
|
|
|
1,761
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
|
141,668
|
|
|
|
10,069
|
|
|
|
10,777
|
|
U.S. state and local
|
|
|
11,816
|
|
|
|
3,647
|
|
|
|
1,841
|
|
|
|
|
|
|
|
|
|
|
153,484
|
|
|
|
13,716
|
|
|
|
12,618
|
|
|
|
|
|
|
|
|
|
$
|
162,085
|
|
|
$
|
16,019
|
|
|
$
|
14,379
|
|
|
|
The reconciliation between the tax expense computed by
multiplying pretax income by the U.S. federal statutory
rate and the reported amounts of income tax expense is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Income at U.S. federal statutory rate
|
|
$
|
154,276
|
|
|
$
|
14,483
|
|
|
$
|
11,916
|
|
State income taxes (net of federal tax effect)
|
|
|
13,372
|
|
|
|
2,631
|
|
|
|
2,083
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
380
|
|
Statutory depletion carryover
|
|
|
|
|
|
|
(613
|
)
|
|
|
|
|
Change in tax rate
|
|
|
(5,671
|
)
|
|
|
|
|
|
|
|
|
Nondeductible expense & other
|
|
|
108
|
|
|
|
(482
|
)
|
|
|
|
|
|
|
|
|
|
|
Expense for income taxes
|
|
$
|
162,085
|
|
|
$
|
16,019
|
|
|
$
|
14,379
|
|
|
|
F-80
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Deferred tax asset:
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
$
|
5,569
|
|
|
$
|
4,440
|
|
Derivative instruments
|
|
|
|
|
|
|
17,612
|
|
Statutory depletion carryover
|
|
|
1,635
|
|
|
|
613
|
|
Federal tax credit carryovers
|
|
|
8,525
|
|
|
|
1,195
|
|
Other
|
|
|
10,625
|
|
|
|
564
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
26,354
|
|
|
|
24,424
|
|
|
|
|
|
|
|
Deferred tax liability:
|
|
|
|
|
|
|
|
|
Oil and gas properties, principally due to differences in basis
and depletion and the deduction of intangible drilling costs for
tax purposes
|
|
|
(557,011
|
)
|
|
|
(269,938
|
)
|
Intangible assetoperating rights
|
|
|
(14,387
|
)
|
|
|
|
|
Derivative instruments
|
|
|
(65,689
|
)
|
|
|
|
|
Other
|
|
|
(235
|
)
|
|
|
(54
|
)
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(637,322
|
)
|
|
|
(269,992
|
)
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(610,968
|
)
|
|
$
|
(245,568
|
)
|
|
|
|
|
Note M.
|
Major
customers and derivative counterparties
|
Sales to major customers. The Companys share
of oil and gas production is sold to various purchasers. The
Company is of the opinion that the loss of any one purchaser
would not have a material adverse effect on the ability of the
Company to sell its oil and gas production.
The following purchasers individually accounted for ten percent
or more of the consolidated oil and natural gas revenues,
including the results of commodity hedges, during the years
ended December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Navajo Refining Company, L.P.
|
|
|
59%
|
|
|
|
60%
|
|
|
|
52%
|
|
DCP Midstream LP
|
|
|
18%
|
|
|
|
23%
|
|
|
|
17%
|
|
|
|
At December 31, 2008, the Company had receivables from
Navajo Refining Company, L.P. and DCP Midstream LP of
$16.2 million and $3.7 million, respectively, which
are reflected in Accounts receivableoil and gas in the
accompanying consolidated balance sheet.
Derivative counterparties. The Company uses credit
and other financial criteria to evaluate the credit standing of,
and to select, counterparties to its derivative instruments. The
Companys credit facility agreements require that the
senior unsecured debt ratings of the Companys derivative
counterparties be not less than either A- by
Standard & Poors Rating Group rating system or
A3 by Moodys Investors Service, Inc. rating system. At
December 31, 2008 and 2007, the counterparties with whom
the Company had outstanding derivative contracts met or exceeded
the required ratings. Although the Company does not obtain
collateral or otherwise
F-81
secure the fair value of its derivative instruments, management
believes the associated credit risk is mitigated by the
Companys credit risk policies and procedures and by the
credit rating requirements of the Companys credit facility
agreements.
Contract Operator Agreement and Transition Services
Agreement. On February 27, 2006, the Company
signed a Contract Operator Agreement with Mack Energy
Corporation (MEC), an affiliate of the Chase Group,
whereby the Company engaged MEC as its contract operator to
provide certain services with respect to the Chase Group
Properties. The initial term of the Contract Operator Agreement
was five years commencing on March 1, 2006 and ending on
February 28, 2011. The Company and MEC entered into a
Transition Services Agreement on April 23, 2007, which
terminated the Contract Operator Agreement and under which MEC
continued to provide certain field level operating services on
the Chase Group Properties. The Transition Services Agreement
was terminated automatically on August 7, 2007 upon the
Companys completion of the Companys initial public
offering. Upon termination of such agreement, the Companys
employees along with third party contractors assumed the
operation of the subject properties.
The Company incurred charges from MEC of approximately
$1.9 million and $18.2 million for the year ended
December 31, 2008 and from the termination dates of the
respective agreements through December 31, 2007,
respectively, in the ordinary course of business. The Company
incurred charges from MEC of approximately $18.2 million
and $10.3 million during 2007 for services rendered under
the Contract Operator Agreement and Transition Services
Agreement through the termination dates of the respective
agreements and the year ended December 31, 2006,
respectively.
The Company had outstanding invoices payable to MEC of
approximately zero and $0.4 million at December 31,
2008 and 2007, respectively, which are reflected in accounts
payablerelated parties in the accompanying consolidated
balance sheet.
Other related party transactions. The Company also
has engaged in transactions with certain other affiliates of the
Chase Group, including Silver Oak, an oilfield services company,
a supply company, a drilling fluids supply company, a pipe and
tubing supplier, a fixed base operator of aircraft services and
a software company.
The Company incurred charges from these related party vendors of
approximately $23.2 million, $43.8 million and
$32.4 million for the years ended December 31, 2008,
2007 and 2006, respectively, for services rendered.
At December 31, 2008 and 2007, the Company had outstanding
invoices payable to the other related party vendors identified
above of approximately $21,000 and $1.7 million,
respectively, which are reflected in accounts
payablerelated parties in the accompanying consolidated
balance sheets.
Overriding royalty and royalty interests. Certain
members of the Chase Group own overriding royalty interests in
certain of the Chase Group Properties. The amount paid
attributable to such interests was approximately
$3.1 million, $2.4 million and $1.2 million for
the years ended December 31, 2008, 2007 and 2006,
respectively. The Company owed royalty payments of approximately
$146,000 and $315,000 to these members of the Chase Group at
December 31, 2008 and 2007, respectively.
F-82
Royalties are paid on certain properties located in Andrews
County, Texas to a partnership of which one of the
Companys directors is the General Partner, and who also
owns a 3.5 percent partnership interest. The Company paid
approximately $332,000, $205,000 and $72,000 for the years ended
December 31, 2008, 2007 and 2006, respectively. The Company
owed this partnership royalty payments of approximately $13,000
and $29,000 at December 31, 2008 and 2007, respectively.
In April 2005, the Company acquired certain working interests in
46,861 gross (26,908 net) acres located in Culberson
County, Texas from an entity partially owned by a person who
became an executive officer of the Company immediately following
such acquisition. In connection with this acquisition, such
entity retained a 2 percent overriding royalty interest in
the acquired properties, which overriding royalty interest is
now owned equally by such officer and a non-officer employee of
the Company. The amount attributable to such interest was
approximately $3,000 during the year ended December 31,
2007. During the year ended December 31, 2008, no payments
were made related to this overriding royalty interest.
Prospect participation. Subsequent to the closing of
the Combination, the Company acquired working interests from
Caza in certain lands in New Mexico in which Caza owns an
interest. The Company paid Caza approximately zero, $3,000 and
$2.1 million for the years ended December 31, 2008,
2007 and 2006 for these interests. At December 31, 2008 and
2007, the Company had no outstanding invoices owed to Caza.
Working interests owned by employees. As part of the
Henry Properties acquisition, the Company purchased oil and gas
properties in which employees owned a working interest. The
Company distributed revenues to these employees of approximately
$155,000 and received joint interest payments from these
employees of $635,000 for the year ended December 31, 2008.
At December 31, 2008, the Company was owed by these
employees approximately $300,000, which is reflected in accounts
receivablerelated parties.
|
|
Note O.
|
Net income per
share
|
Basic net income per share is computed by dividing net income
applicable to common shareholders by the weighted average number
of common shares treated as outstanding for the period. As
discussed in Note F, agreements to sell stock to the
Companys officers and certain employees subject to
Purchase Notes are accounted for as options (Bundled
Capital Options and Capital Options,
respectively). As a result, Bundled Capital Options and Capital
Options are excluded from the weighted average number of common
shares treated as outstanding during each period until the
Purchase Notes are paid in full, thus exercising the options.
All Bundled Capital Options were exercised prior to
September 30, 2007. All Capital Options were exercised
prior to March 31, 2008.
The computation of diluted income per share reflects the
potential dilution that could occur if securities or other
contracts to issue common stock that are dilutive to income were
exercised or converted into common stock or resulted in the
issuance of common stock that would then share in the earnings
of the Company. These amounts include unexercised Bundled
Capital Options, Capital Options, stock options and restricted
stock (as issued under the Plan and described in Note G).
Potentially dilutive effects are calculated using the treasury
stock method.
The CEHC 6% Series A Preferred Stock were entitled to
receive an amount equal to its stated value ($9.00) plus any
unpaid dividends upon occurrence of a liquidation event, as
defined. In connection with the Combination on February 24,
2006, a liquidation event occurred. Instead of
F-83
receiving the stated value, the holders of the CEHC 6%
Series A Preferred Stock agreed to accept 0.75 shares
of Resources common stock in exchange for each share of CEHC 6%
Series A Preferred Stock. This was considered to be an
induced conversion, as defined in the FASB Emerging Issues Task
Force Topic D-42, The Effect on the Calculation of
Earnings per Share for the Redemption or Induced Conversion of
Preferred Stock. The excess of the carrying amount of the
CEHC 6% Series A Preferred Stock over the fair value of the
Resources common stock issued is required to be added to
2006 net income to arrive at 2006 net income
applicable to common shareholders for the year ended
December 31, 2006.
The following table is a reconciliation of the basic weighted
average common shares outstanding to diluted weighted average
common shares outstanding for the years ended December 31,
2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
79,206
|
|
|
|
64,316
|
|
|
|
47,287
|
|
Dilutive bundled capital options
|
|
|
|
|
|
|
847
|
|
|
|
2,516
|
|
Dilutive capital options
|
|
|
6
|
|
|
|
154
|
|
|
|
192
|
|
Dilutive common stock options
|
|
|
1,134
|
|
|
|
901
|
|
|
|
714
|
|
Dilutive restricted stock
|
|
|
241
|
|
|
|
91
|
|
|
|
20
|
|
|
|
|
|
|
|
Diluted
|
|
|
80,587
|
|
|
|
66,309
|
|
|
|
50,729
|
|
|
|
Since the Company had net income applicable to common
shareholders, the effects of all potentially dilutive securities
including Bundled Capital Options, Capital Options, incentive
stock options and unvested restricted stock were considered in
the computation of diluted earnings per share. Because the
exercise prices of certain incentive stock options were greater
than the average market price of the common shares and would be
anti-dilutive, incentive stock options to purchase
313,354 shares, 366,250 shares and 450,000 of common
stock for the years ended December 31, 2008, 2007 and 2006,
respectively, were outstanding but not included in the
computations of diluted income per share from continuing
operations. Also excluded from the computation of diluted income
per share for the year ended December 31, 2008, were
56,086 shares of restricted stock because the effect would
be anti-dilutive.
|
|
Note P.
|
Other current
liabilities
|
The following table provides the components of the
Companys other current liabilities at December 31,
2008 and 2007 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Other current liabilities:
|
|
|
|
|
|
|
|
|
Accrued production costs
|
|
$
|
15,489
|
|
|
$
|
4,135
|
|
Payroll related matters
|
|
|
11,290
|
|
|
|
3,821
|
|
Accrued interest
|
|
|
353
|
|
|
|
1,590
|
|
Asset retirement obligations
|
|
|
2,611
|
|
|
|
912
|
|
Other
|
|
|
8,314
|
|
|
|
4,008
|
|
|
|
|
|
|
|
Other current liabilities
|
|
$
|
38,057
|
|
|
$
|
14,466
|
|
|
|
F-84
|
|
Note Q.
|
Subsidiary
guarantors
|
All of the Companys wholly-owned subsidiaries have fully
and unconditionally guaranteed the Credit Facility of the
Company (see Note J). In accordance with practices accepted
by the SEC, the Company has prepared Consolidating Condensed
Financial Statements in order to quantify the assets and results
of operations of such subsidiaries as subsidiary guarantors. The
following Consolidating Condensed Balance Sheets at
December 31, 2008 and 2007, and Consolidating Statements of
Operations and Consolidating Condensed Statements of Cash Flows
for the years ended December 31, 2008, 2007 and 2006,
present financial information for Concho Resources Inc. as the
Parent on a stand-alone basis (carrying any investments in
subsidiaries under the equity method), financial information for
the subsidiary guarantors on a stand-alone basis (carrying any
investment in non-guarantor subsidiaries under the equity
method), and the consolidation and elimination entries necessary
to arrive at the information for the Company on a consolidated
basis. All current and deferred taxes are recorded on Concho
Resources Inc., as the subsidiaries are flow-through entities
for tax purposes. The subsidiary guarantors are not restricted
from making distributions to the Company.
F-85
Consolidating
condensed balance sheet
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
Parent issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivablerelated parties
|
|
$
|
2,500,186
|
|
|
$
|
1,432,829
|
|
|
$
|
(3,932,701
|
)
|
|
$
|
314
|
|
Other current assets
|
|
|
120,406
|
|
|
|
158,063
|
|
|
|
|
|
|
|
278,469
|
|
Total oil and natural gas properties, net
|
|
|
|
|
|
|
2,386,584
|
|
|
|
|
|
|
|
2,386,584
|
|
Other property and equipment, net
|
|
|
|
|
|
|
14,820
|
|
|
|
|
|
|
|
14,820
|
|
Investment in subsidiaries
|
|
|
734,969
|
|
|
|
|
|
|
|
(734,969
|
)
|
|
|
|
|
Total other long-term assets
|
|
|
73,538
|
|
|
|
61,478
|
|
|
|
|
|
|
|
135,016
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,429,099
|
|
|
$
|
4,053,774
|
|
|
$
|
(4,667,670
|
)
|
|
$
|
2,815,203
|
|
|
|
|
|
|
|
Liabilities and equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payablerelated parties
|
|
$
|
860,758
|
|
|
$
|
3,072,255
|
|
|
$
|
(3,932,701
|
)
|
|
$
|
312
|
|
Other current liabilities
|
|
|
39,424
|
|
|
|
231,082
|
|
|
|
|
|
|
|
270,506
|
|
Other long-term liabilities
|
|
|
573,763
|
|
|
|
15,468
|
|
|
|
|
|
|
|
589,231
|
|
Long-term debt
|
|
|
630,000
|
|
|
|
|
|
|
|
|
|
|
|
630,000
|
|
Equity
|
|
|
1,325,154
|
|
|
|
734,969
|
|
|
|
(734,969
|
)
|
|
|
1,325,154
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
3,429,099
|
|
|
$
|
4,053,774
|
|
|
$
|
(4,667,670
|
)
|
|
$
|
2,815,203
|
|
|
|
Consolidating
condensed balance sheet
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
Parent issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivablerelated parties
|
|
$
|
1,086,155
|
|
|
$
|
644,595
|
|
|
$
|
(1,730,750
|
)
|
|
$
|
|
|
Other current assets
|
|
|
17,127
|
|
|
|
90,856
|
|
|
|
|
|
|
|
107,983
|
|
Total oil and natural gas properties, net
|
|
|
|
|
|
|
1,387,909
|
|
|
|
|
|
|
|
1,387,909
|
|
Other property and equipment, net
|
|
|
|
|
|
|
7,085
|
|
|
|
|
|
|
|
7,085
|
|
Investment in subsidiaries
|
|
|
411,240
|
|
|
|
|
|
|
|
(411,240
|
)
|
|
|
|
|
Total other long-term assets
|
|
|
3,426
|
|
|
|
1,826
|
|
|
|
|
|
|
|
5,252
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,517,948
|
|
|
$
|
2,132,271
|
|
|
$
|
(2,141,990
|
)
|
|
$
|
1,508,229
|
|
|
|
|
|
|
|
Liabilities and equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payablerelated parties
|
|
$
|
107,523
|
|
|
$
|
1,625,346
|
|
|
$
|
(1,730,750
|
)
|
|
$
|
2,119
|
|
Other current liabilities
|
|
|
40,036
|
|
|
|
86,487
|
|
|
|
|
|
|
|
126,523
|
|
Other long-term liabilities
|
|
|
269,587
|
|
|
|
9,198
|
|
|
|
|
|
|
|
278,785
|
|
Long-term debt
|
|
|
325,404
|
|
|
|
|
|
|
|
|
|
|
|
325,404
|
|
Equity
|
|
|
775,398
|
|
|
|
411,240
|
|
|
|
(411,240
|
)
|
|
|
775,398
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
1,517,948
|
|
|
$
|
2,132,271
|
|
|
$
|
(2,141,990
|
)
|
|
$
|
1,508,229
|
|
|
|
F-86
Consolidating
condensed statement of operations
For the year ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
Parent issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Total operating revenues
|
|
$
|
(31,287
|
)
|
|
$
|
565,076
|
|
|
$
|
|
|
|
$
|
533,789
|
|
Total operating costs and expenses
|
|
|
177,384
|
|
|
|
(242,779
|
)
|
|
|
|
|
|
|
(65,395
|
)
|
|
|
|
|
|
|
Income from operations
|
|
|
146,097
|
|
|
|
322,297
|
|
|
|
|
|
|
|
468,394
|
|
Interest expense
|
|
|
(29,039
|
)
|
|
|
|
|
|
|
|
|
|
|
(29,039
|
)
|
Other, net
|
|
|
323,729
|
|
|
|
1,432
|
|
|
|
(323,729
|
)
|
|
|
1,432
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
440,787
|
|
|
|
323,729
|
|
|
|
(323,729
|
)
|
|
|
440,787
|
|
Income tax expense
|
|
|
(162,085
|
)
|
|
|
|
|
|
|
|
|
|
|
(162,085
|
)
|
|
|
|
|
|
|
Net income
|
|
$
|
278,702
|
|
|
$
|
323,729
|
|
|
$
|
(323,729
|
)
|
|
$
|
278,702
|
|
|
|
Consolidating
condensed statement of operations
For the year ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
Parent issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Total operating revenues
|
|
$
|
(2,968
|
)
|
|
$
|
297,301
|
|
|
$
|
|
|
|
$
|
294,333
|
|
Total operating costs and expenses
|
|
|
(22,472
|
)
|
|
|
(195,924
|
)
|
|
|
|
|
|
|
(218,396
|
)
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(25,440
|
)
|
|
|
101,377
|
|
|
|
|
|
|
|
75,937
|
|
Interest expense
|
|
|
(36,042
|
)
|
|
|
|
|
|
|
|
|
|
|
(36,042
|
)
|
Other, net
|
|
|
102,861
|
|
|
|
1,174
|
|
|
|
(102,551
|
)
|
|
|
1,484
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
41,379
|
|
|
|
102,551
|
|
|
|
(102,551
|
)
|
|
|
41,379
|
|
Income tax expense
|
|
|
(16,019
|
)
|
|
|
|
|
|
|
|
|
|
|
(16,019
|
)
|
|
|
|
|
|
|
Net income
|
|
$
|
25,360
|
|
|
$
|
102,551
|
|
|
$
|
(102,551
|
)
|
|
$
|
25,360
|
|
Preferred stock dividends
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
Net income applicable to common shareholders
|
|
$
|
25,315
|
|
|
$
|
102,551
|
|
|
$
|
(102,551
|
)
|
|
$
|
25,315
|
|
|
|
F-87
Consolidating
condensed statement of operations
For the year ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
Parent issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Total operating revenues
|
|
$
|
366
|
|
|
$
|
197,924
|
|
|
$
|
|
|
|
$
|
198,290
|
|
Total operating costs and expenses
|
|
|
(180
|
)
|
|
|
(134,682
|
)
|
|
|
|
|
|
|
(134,862
|
)
|
|
|
|
|
|
|
Income from operations
|
|
|
186
|
|
|
|
63,242
|
|
|
|
|
|
|
|
63,428
|
|
Interest expense
|
|
|
(30,567
|
)
|
|
|
|
|
|
|
|
|
|
|
(30,567
|
)
|
Other, net
|
|
|
64,428
|
|
|
|
469
|
|
|
|
(63,711
|
)
|
|
|
1,186
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
34,047
|
|
|
|
63,711
|
|
|
|
(63,711
|
)
|
|
|
34,047
|
|
Income tax expense
|
|
|
(14,379
|
)
|
|
|
|
|
|
|
|
|
|
|
(14,379
|
)
|
|
|
|
|
|
|
Net income
|
|
$
|
19,668
|
|
|
$
|
63,711
|
|
|
$
|
(63,711
|
)
|
|
$
|
19,668
|
|
Preferred stock dividends
|
|
|
(1,244
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,244
|
)
|
Effect of induced conversion of preferred stock
|
|
|
11,601
|
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
|
|
|
|
Net income applicable to common shareholders
|
|
$
|
30,025
|
|
|
$
|
63,711
|
|
|
$
|
(63,711
|
)
|
|
$
|
30,025
|
|
|
|
Consolidating
condensed statement of cash flows
For the year ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
Parent issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(532,919
|
)
|
|
$
|
924,316
|
|
|
$
|
|
|
|
$
|
391,397
|
|
Net cash flows used in investing activities
|
|
|
(5,386
|
)
|
|
|
(940,664
|
)
|
|
|
|
|
|
|
(946,050
|
)
|
Net cash flows provided by financing activities
|
|
|
538,198
|
|
|
|
3,783
|
|
|
|
|
|
|
|
541,981
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(107
|
)
|
|
|
(12,565
|
)
|
|
|
|
|
|
|
(12,672
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
107
|
|
|
|
30,317
|
|
|
|
|
|
|
|
30,424
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
|
|
|
$
|
17,752
|
|
|
$
|
|
|
|
$
|
17,752
|
|
|
|
F-88
Consolidating
condensed statement of cash flows
For the year ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
Parent issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(15,094
|
)
|
|
$
|
184,863
|
|
|
$
|
|
|
|
$
|
169,769
|
|
Net cash flows provided by (used in) investing activities
|
|
|
631
|
|
|
|
(160,984
|
)
|
|
|
|
|
|
|
(160,353
|
)
|
Net cash flows provided by financing activities
|
|
|
14,235
|
|
|
|
5,651
|
|
|
|
|
|
|
|
19,886
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(228
|
)
|
|
|
29,530
|
|
|
|
|
|
|
|
29,302
|
|
Cash and cash equivalents at beginning of year
|
|
|
335
|
|
|
|
787
|
|
|
|
|
|
|
|
1,122
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
107
|
|
|
$
|
30,317
|
|
|
$
|
|
|
|
$
|
30,424
|
|
|
|
Consolidating
condensed statement of cash flows
For the year ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
(in thousands)
|
|
Parent issuer
|
|
|
guarantors
|
|
|
entries
|
|
|
Total
|
|
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(487,349
|
)
|
|
$
|
599,530
|
|
|
$
|
|
|
|
$
|
112,181
|
|
Net cash flows used in investing activities
|
|
|
|
|
|
|
(596,852
|
)
|
|
|
|
|
|
|
(596,852
|
)
|
Net cash flows provided by financing activities
|
|
|
476,611
|
|
|
|
|
|
|
|
|
|
|
|
476,611
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(10,738
|
)
|
|
|
2,678
|
|
|
|
|
|
|
|
(8,060
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
11,073
|
|
|
|
(1,891
|
)
|
|
|
|
|
|
|
9,182
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
335
|
|
|
$
|
787
|
|
|
$
|
|
|
|
$
|
1,122
|
|
|
|
F-89
Capitalized costs
(in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Oil and gas properties:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
2,316,330
|
|
|
$
|
1,303,665
|
|
Unproved
|
|
|
377,244
|
|
|
|
251,353
|
|
Less: accumulated depletion
|
|
|
(306,990
|
)
|
|
|
(167,109
|
)
|
|
|
|
|
|
|
Net capitalized costs for oil and gas properties
|
|
$
|
2,386,584
|
|
|
$
|
1,387,909
|
|
|
|
Costs incurred
for oil and gas producing activities
(in
thousands)a:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
597,713
|
|
|
$
|
|
|
|
$
|
830,537
|
|
Unproved
|
|
|
240,294
|
|
|
|
7,293
|
|
|
|
220,295
|
|
Exploration
|
|
|
160,174
|
|
|
|
116,004
|
|
|
|
49,297
|
|
Development
|
|
|
178,842
|
|
|
|
64,524
|
|
|
|
124,817
|
|
|
|
|
|
|
|
Total costs incurred for oil and gas properties
|
|
$
|
1,177,023
|
|
|
$
|
187,821
|
|
|
$
|
1,224,946
|
|
|
|
|
|
|
(a)
|
|
The costs incurred for oil and gas
producing activities includes the following amounts of asset
retirement obligations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Proved property acquisition costs
|
|
$
|
7,062
|
|
|
$
|
|
|
|
$
|
6,155
|
|
Exploration costs
|
|
|
563
|
|
|
|
(15
|
)
|
|
|
43
|
|
Development costs
|
|
|
(1,123
|
)
|
|
|
315
|
|
|
|
1,095
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,502
|
|
|
$
|
300
|
|
|
$
|
7,293
|
|
|
|
Reserve quantity
information
The estimates of proved oil and gas reserves, which are all
located in the United States primarily in the Permian Basin
region of Southeast New Mexico and West Texas, were prepared by
the Companys engineers. These reserve estimates were
reviewed and confirmed by Netherland, Sewell &
Associates, Inc. and Cawley, Gillespie & Associates,
Inc. Reserves were estimated in accordance with guidelines
established by the United States Securities and Exchange
Commission (SEC) and the FASB, which require that
reserve estimates be prepared under existing economic and
operating conditions with no provision for price and cost
escalations except by
F-90
contractual arrangements except that future production costs
exclude overhead charges for Company operated properties.
The following table summarizes the prices utilized in the
reserve estimates for 2008, 2007 and 2006. Commodity prices
utilized for the reserve estimates were adjusted for location,
grade and quality are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Prices utilized in the reserve estimates before adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end West Texas Intermediate posted oil price per Bbl
|
|
$
|
41.00
|
|
|
$
|
92.50
|
|
|
$
|
57.75
|
|
Year-end Henry Hub spot market natural gas price per MMBtu
|
|
$
|
5.71
|
|
|
$
|
6.80
|
|
|
$
|
5.64
|
|
|
|
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved
reserves and in the projection of future rates of production and
the timing of development expenditures. The accuracy of such
estimates is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results
of subsequent drilling, testing and production may cause either
upward or downward revision of previous estimates. Further, the
volumes considered to be commercially recoverable fluctuate with
changes in prices and operating costs. The Company emphasizes
that reserve estimates are inherently imprecise and that
estimates of new discoveries are more imprecise than those of
currently producing oil and gas properties. Accordingly, these
estimates are expected to change as additional information
becomes available in the future.
The following table provides a rollforward of the total proved
reserves for the years ended December 31, 2008, 2007 and
2006, as well as proved developed reserves at the beginning and
end of each respective year. Oil and condensate volumes are
expressed in MBbls and natural gas volumes are expressed in MMcf.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Oil and
|
|
|
Natural
|
|
|
|
|
|
Oil and
|
|
|
Natural
|
|
|
|
|
|
Oil and
|
|
|
Natural
|
|
|
|
|
|
|
condensate
|
|
|
gas
|
|
|
Total
|
|
|
condensate
|
|
|
gas
|
|
|
Total
|
|
|
condensate
|
|
|
gas
|
|
|
Total
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
(Mbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
|
|
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, January 1
|
|
|
53,361
|
|
|
|
225,837
|
|
|
|
91,000
|
|
|
|
44,322
|
|
|
|
200,818
|
|
|
|
77,792
|
|
|
|
9,658
|
|
|
|
49,530
|
|
|
|
17,913
|
|
Purchase of
minerals-in-place
|
|
|
20,837
|
|
|
|
56,022
|
|
|
|
30,174
|
|
|
|
105
|
|
|
|
354
|
|
|
|
164
|
|
|
|
27,163
|
|
|
|
137,963
|
|
|
|
50,157
|
|
Sales of
minerals-in-place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Discoveries and
extensionsa
|
|
|
24,194
|
|
|
|
73,380
|
|
|
|
36,424
|
|
|
|
13,140
|
|
|
|
48,751
|
|
|
|
21,265
|
|
|
|
10,226
|
|
|
|
39,427
|
|
|
|
16,797
|
|
Revisions of previous estimates
|
|
|
(7,521
|
)
|
|
|
(34,323
|
)
|
|
|
(13,242
|
)
|
|
|
(1,191
|
)
|
|
|
(12,022
|
)
|
|
|
(3,195
|
)
|
|
|
(430
|
)
|
|
|
(16,595
|
)
|
|
|
(3,196
|
)
|
Production
|
|
|
(4,586
|
)
|
|
|
(14,968
|
)
|
|
|
(7,081
|
)
|
|
|
(3,014
|
)
|
|
|
(12,064
|
)
|
|
|
(5,025
|
)
|
|
|
(2,295
|
)
|
|
|
(9,507
|
)
|
|
|
(3,880
|
)
|
|
|
|
|
|
|
Balance, December 31
|
|
|
86,285
|
|
|
|
305,948
|
|
|
|
137,275
|
|
|
|
53,361
|
|
|
|
225,837
|
|
|
|
91,000
|
|
|
|
44,322
|
|
|
|
200,818
|
|
|
|
77,791
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
|
|
|
27,617
|
|
|
|
128,872
|
|
|
|
49,096
|
|
|
|
23,443
|
|
|
|
112,423
|
|
|
|
42,180
|
|
|
|
6,502
|
|
|
|
34,160
|
|
|
|
12,195
|
|
December 31
|
|
|
46,661
|
|
|
|
179,124
|
|
|
|
76,515
|
|
|
|
27,617
|
|
|
|
128,872
|
|
|
|
49,096
|
|
|
|
23,443
|
|
|
|
112,423
|
|
|
|
42,180
|
|
|
|
|
|
|
(a)
|
|
The 2008, 2007 and 2006 discoveries
and extensions included 14,533, 9,601 and 5,211 net MBoe,
respectively, related to additions from the Companys
infill drilling activities.
|
F-91
Standardized
measure of discounted future net cash flows
The standardized measure of discounted future net cash flows is
computed by applying year-end prices of oil and gas (with
consideration of price changes only to the extent provided by
contractual arrangements) to the estimated future production of
proved oil and gas reserves less estimated future expenditures
(based on year-end costs) to be incurred in developing and
producing the proved reserves, discounted using a rate of
10 percent per year to reflect the estimated timing of the
future cash flows. Future income taxes are calculated by
comparing undiscounted future cash flows to the tax basis of oil
and gas properties plus available carryforwards and credits and
applying the current tax rates to the difference.
Discounted future cash flow estimates like those shown below are
not intended to represent estimates of the fair value of oil and
gas properties. Estimates of fair value would also consider
probable and possible reserves, anticipated future oil and gas
prices, interest rates, changes in development and production
costs and risks associated with future production. Because of
these and other considerations, any estimate of fair value is
necessarily subjective and imprecise.
The following table provides the standardized measure of
discounted future cash flows at December 31, 2008, 2007 and
2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Oil and gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
5,785,109
|
|
|
$
|
6,507,955
|
|
|
$
|
3,560,326
|
|
Future production costs
|
|
|
(1,666,380
|
)
|
|
|
(1,517,415
|
)
|
|
|
(995,335
|
)
|
Future development and abandonment
costsa
|
|
|
(668,005
|
)
|
|
|
(484,140
|
)
|
|
|
(484,462
|
)
|
Future income tax expense
|
|
|
(919,251
|
)
|
|
|
(1,482,633
|
)
|
|
|
(530,212
|
)
|
|
|
|
|
|
|
|
|
|
2,531,473
|
|
|
|
3,023,767
|
|
|
|
1,550,317
|
|
10% annual discount factor
|
|
|
(1,332,488
|
)
|
|
|
(1,591,993
|
)
|
|
|
(839,968
|
)
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
1,198,985
|
|
|
$
|
1,431,774
|
|
|
$
|
710,349
|
|
|
|
|
|
|
(a)
|
|
Includes $28.8 million,
$19.5 million and $25.3 million of undiscounted asset
retirement cash inflow estimated at December 31, 2008, 2007
and 2006, respectively, using current estimates of future
salvage values less future abandonment costs. See Note E
for corresponding information regarding the Companys
discounted asset retirement obligations.
|
F-92
Changes in
standardized measure of discounted future net cash
flows
The following table provides a rollforward of the standardized
measure of discounted future cash flows for the years ended
December 31, 2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
Oil and gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of
minerals-in-place
|
|
$
|
1,014,689
|
|
|
$
|
4,054
|
|
|
$
|
795,072
|
|
Sales of
minerals-in-place
|
|
|
(24
|
)
|
|
|
(54
|
)
|
|
|
|
|
Extensions and discoveries
|
|
|
426,208
|
|
|
|
511,519
|
|
|
|
156,266
|
|
Net changes in prices and production costs
|
|
|
(1,622,800
|
)
|
|
|
802,584
|
|
|
|
(109,264
|
)
|
Oil and gas sales, net of production costs
|
|
|
(473,841
|
)
|
|
|
(249,866
|
)
|
|
|
(166,236
|
)
|
Changes in future development costs
|
|
|
74,160
|
|
|
|
72,441
|
|
|
|
(6,085
|
)
|
Revisions of previous quantity estimates
|
|
|
(283,557
|
)
|
|
|
(82,299
|
)
|
|
|
(51,147
|
)
|
Accretion of discount
|
|
|
255,660
|
|
|
|
85,533
|
|
|
|
23,085
|
|
Changes in production rates, timing and other
|
|
|
104,137
|
|
|
|
35,834
|
|
|
|
(10,119
|
)
|
|
|
|
|
|
|
Change in present value of future net revenues
|
|
|
(505,368
|
)
|
|
|
1,179,746
|
|
|
|
631,572
|
|
Net change in present value of future income taxes
|
|
|
272,579
|
|
|
|
(458,321
|
)
|
|
|
(144,985
|
)
|
|
|
|
|
|
|
|
|
|
(232,789
|
)
|
|
|
721,425
|
|
|
|
486,587
|
|
Balance, beginning of year
|
|
|
1,431,774
|
|
|
|
710,349
|
|
|
|
223,762
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
1,198,985
|
|
|
$
|
1,431,774
|
|
|
$
|
710,349
|
|
|
|
F-93
Selected
quarterly financial results
The following table provides selected quarterly financial
results for the years ended December 31, 2008 and 2007 (in
thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
Year ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
106,711
|
|
|
$
|
137,383
|
|
|
$
|
170,457
|
|
|
$
|
119,238
|
|
Operating costs and expenses (excluding gains (losses) on
derivatives not designated as hedges)
|
|
|
(48,205
|
)
|
|
|
(54,942
|
)
|
|
|
(90,889
|
)
|
|
|
(121,229
|
)
|
Gains (losses) on derivatives not designated as hedges
|
|
|
(17,178
|
)
|
|
|
(102,456
|
)
|
|
|
163,312
|
|
|
|
206,192
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
$
|
41,328
|
|
|
$
|
(20,015
|
)
|
|
$
|
242,880
|
|
|
$
|
204,201
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
22,365
|
|
|
$
|
(14,420
|
)
|
|
$
|
141,928
|
|
|
$
|
128,829
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
22,365
|
|
|
$
|
(14,420
|
)
|
|
$
|
141,928
|
|
|
$
|
128,829
|
|
|
|
|
|
|
|
Net income (loss) per common shareBasic
|
|
$
|
0.30
|
|
|
$
|
(0.19
|
)
|
|
$
|
1.75
|
|
|
$
|
1.53
|
|
|
|
|
|
|
|
Net income (loss) per common shareDiluted
|
|
$
|
0.29
|
|
|
$
|
(0.19
|
)
|
|
$
|
1.72
|
|
|
$
|
1.51
|
|
|
|
|
|
|
|
Year ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
60,346
|
|
|
$
|
66,103
|
|
|
$
|
69,098
|
|
|
$
|
98,786
|
|
Operating costs and expenses (excluding gains (losses) on
derivatives not designated as hedges)
|
|
|
(41,938
|
)
|
|
|
(46,324
|
)
|
|
|
(49,690
|
)
|
|
|
(60,170
|
)
|
Gains (losses) on derivatives not designated as hedges
|
|
|
|
|
|
|
|
|
|
|
3,088
|
|
|
|
(23,362
|
)
|
|
|
|
|
|
|
Income from operations
|
|
$
|
18,408
|
|
|
$
|
19,779
|
|
|
$
|
22,496
|
|
|
$
|
15,254
|
|
|
|
|
|
|
|
Net income
|
|
$
|
4,623
|
|
|
$
|
5,925
|
|
|
$
|
7,954
|
|
|
$
|
6,858
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
4,589
|
|
|
$
|
5,914
|
|
|
$
|
7,954
|
|
|
$
|
6,858
|
|
|
|
|
|
|
|
Net income per common shareBasic
|
|
$
|
0.08
|
|
|
$
|
0.10
|
|
|
$
|
0.12
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
Net income per common shareDiluted
|
|
$
|
0.08
|
|
|
$
|
0.10
|
|
|
$
|
0.11
|
|
|
$
|
0.09
|
|
|
|
F-94
PROSPECTUS
Concho
Resources Inc.
Debt Securities
Preferred Stock
Common Stock
Depositary Shares
Warrants
Guarantee
of Debt Securities of Concho Resources Inc. by:
COG Operating LLC
COG Realty LLC
Concho Energy Services LLC
Quail Ranch LLC
We may offer and sell the securities listed above from time to
time in one or more offerings in one or more classes or series.
Any debt securities we offer pursuant to this prospectus may be
fully and unconditionally guaranteed by certain of our
subsidiaries, including COG Operating LLC, COG Realty LLC,
Concho Energy Services LLC, and Quail Ranch LLC.
This prospectus provides you with a general description of the
securities that may be offered. Each time securities are
offered, we will provide a prospectus supplement and attach it
to this prospectus. The prospectus supplement will contain more
specific information about the offering and the terms of the
securities being offered, including any guarantees by our
subsidiaries. A prospectus supplement may also add, update or
change information contained in this prospectus. This prospectus
may not be used to offer or sell securities without a prospectus
supplement describing the method and terms of the offering.
We may sell these securities directly or through agents,
underwriters or dealers, or through a combination of these
methods. See Plan of Distribution. The prospectus
supplement will list any agents, underwriters or dealers that
may be involved and the compensation they will receive. The
prospectus supplement will also show you the total amount of
money that we will receive from selling the securities being
offered, after the expenses of the offering. You should
carefully read this prospectus and any accompanying prospectus
supplement, together with the documents we incorporate by
reference, before you invest in any of our securities.
Investing in any of our securities involves
risk. Please read carefully the information included
and incorporated by reference in this prospectus and in any
applicable prospectus supplement for a discussion of the factors
you should consider before deciding to purchase our securities.
See Risk Factors beginning on page 4 of this
prospectus.
Our common stock is listed on the New York Stock Exchange under
the symbol CXO.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or determined if this prospectus is truthful or
complete. Any representation to the contrary is a criminal
offense.
This
prospectus is dated September 9, 2009.
Table of
contents
|
|
|
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
2
|
|
|
|
|
3
|
|
|
|
|
4
|
|
|
|
|
4
|
|
|
|
|
5
|
|
|
|
|
6
|
|
|
|
|
18
|
|
|
|
|
22
|
|
|
|
|
23
|
|
|
|
|
24
|
|
|
|
|
24
|
|
You should rely only on the information contained in or
incorporated by reference into this prospectus and any
prospectus supplement. We have not authorized any dealer,
salesman or other person to provide you with additional or
different information. If anyone provides you with different or
inconsistent information, you should not rely on it. This
prospectus and any prospectus supplement are not an offer to
sell or the solicitation of an offer to buy any securities other
than the securities to which they relate and are not an offer to
sell or the solicitation of an offer to buy securities in any
jurisdiction to any person to whom it is unlawful to make an
offer or solicitation in that jurisdiction. You should not
assume that the information contained in this prospectus is
accurate as of any date other than the date on the front cover
of this prospectus, or that the information contained in any
document incorporated by reference is accurate as of any date
other than the date of the document incorporated by reference,
regardless of the time of delivery of this prospectus or any
sale of a security.
i
About
this prospectus
This prospectus is part of a registration statement that we
filed with the Securities and Exchange Commission, which we
refer to as the SEC, using a shelf registration
process. Under this shelf registration process, we may offer and
sell any combination of the securities described in this
prospectus in one or more offerings. This prospectus provides
you with a general description of the securities we may offer.
Each time we sell securities, we will provide a prospectus
supplement that will contain specific information about the
terms of the offering and the offered securities. The prospectus
supplement may also add, update or change information contained
in this prospectus. Any statement that we make in this
prospectus will be modified or superseded by any inconsistent
statement made by us in a prospectus supplement. You should read
both this prospectus and any prospectus supplement together with
additional information described under the heading Where
You Can Find More Information.
Unless the context requires otherwise or unless otherwise noted,
all references in this prospectus or any accompanying prospectus
supplement to Concho, we or
our are to Concho Resources Inc. and its
subsidiaries.
The
company
We are an independent oil and natural gas company engaged in the
acquisition, development, exploitation and exploration of oil
and natural gas properties. Our core operations are focused in
the Permian Basin of Southeast New Mexico and West Texas. These
core operating areas are complemented by activities in our
emerging plays. We intend to grow our reserves and production
through development drilling, exploitation and exploration
activities on our multi-year project inventory and through
acquisitions that meet our strategic and financial objectives.
We were formed in February 2006 as a result of the combination
of Concho Equity Holdings Corp. and a portion of the oil and
natural gas properties and related assets owned by Chase Oil
Corporation and certain of its affiliates. Concho Equity
Holdings Corp., which was subsequently merged into one of our
wholly-owned subsidiaries, was formed in April 2004 and
represented the third of three Permian Basin-focused companies
that have been formed since 1997 by certain members of our
current management team (the prior two companies were sold to
large domestic independent oil and gas companies).
Our principal executive offices are located at 550 West
Texas Avenue, Suite 100, Midland, Texas 79701. Our common
stock is listed on the New York Stock Exchange under the symbol
CXO.
1
Where you
can find more information
We file annual, quarterly and current reports and other
information with the SEC (File
No. 001-33615)
pursuant to the Securities Exchange Act of 1934 (the
Exchange Act). You may read and copy any documents
that are filed at the SECs public reference room at
100 F Street, N.E., Washington, D.C. 20549. You
may also obtain copies of these documents at prescribed rates
from the public reference section of the SEC at its Washington
address. Please call the SEC at
1-800-SEC-0330
for further information.
Our filings are also available to the public through the
SECs website at
http://www.sec.gov.
The SEC allows us to incorporate by reference
information that we file with it, which means that we can
disclose important information to you by referring you to
documents previously filed with the SEC. The information
incorporated by reference is an important part of this
prospectus, and the information that we later file with the SEC
will automatically update and supersede this information. The
following documents we filed with the SEC pursuant to the
Exchange Act are incorporated herein by reference:
|
|
|
|
|
our Annual Report on
Form 10-K
for the year ended December 31, 2008;
|
|
|
|
our Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2009;
|
|
|
|
our Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2009;
|
|
|
|
our Current Reports on
Form 8-K
and 8-K/A
filed on each of August 6, 2008, October 7, 2008,
January 28, 2009, March 4, 2009, April 9, 2009,
June 12, 2009, August 12, 2009 and September 9,
2009 (excluding any information furnished pursuant to
Item 2.02 or Item 7.01 of any such Current Report on
Form 8-K); and
|
|
|
|
the description of our common stock contained in our
registration statement on
Form 8-A12B
filed on July 23, 2007, including any amendment to that
form that we may file in the future for the purpose of updating
the description of our common stock.
|
These reports contain important information about us, our
financial condition and our results of operations.
All future documents filed pursuant to Sections 13(a),
13(c), 14 and 15(d) of the Exchange Act (excluding any
information furnished pursuant to Item 2.02 or
Item 7.01 on any Current Report on
Form 8-K)
before the termination of each offering under this prospectus
shall be deemed to be incorporated in this prospectus by
reference and to be a part hereof from the date of filing of
such documents. Any statement contained herein, or in a document
incorporated or deemed to be incorporated by reference herein,
shall be deemed to be modified or superseded for purposes of
this prospectus to the extent that a statement contained herein
or in any subsequently filed document that also is or is deemed
to be incorporated by reference herein, modifies or supersedes
such statement. Any such statement so modified or superseded
shall not be deemed, except as so modified or superseded, to
constitute a part of this prospectus.
You may request a copy of these filings at no cost by writing or
telephoning us at the following address and telephone number:
Concho Resources Inc.
550 West Texas Avenue, Suite 100
Midland, Texas 79701
Attention: General Counsel
(432) 683-7443
We also maintain a website at
http://www.conchoresources.com.
However, the information on our website is not part of this
prospectus.
2
Cautionary
statement regarding forward-looking statements
Various statements contained in or incorporated by reference
into this prospectus, our filings with the SEC and our public
releases, including those that express a belief, expectation, or
intention, as well as those that are not statements of
historical fact, are forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 (the
Securities Act) and Section 21E of the Exchange
Act. These forward-looking statements may include projections
and estimates concerning capital expenditures, our liquidity and
capital resources, the timing and success of specific projects,
outcomes and effects of litigation, claims and disputes,
elements of our business strategy and other statements
concerning our operations, economic performance and financial
condition. Forward-looking statements are generally accompanied
by words such as estimate, project,
predict, believe, expect,
anticipate, potential,
could, may, foresee,
plan, goal or other words that convey
the uncertainty of future events or outcomes. We have based
these forward-looking statements on our current expectations and
assumptions about future events. These statements are based on
certain assumptions and analyses made by us in light of our
experience and our perception of historical trends, current
conditions and expected future developments as well as other
factors we believe are appropriate under the circumstances.
These forward-looking statements speak only as of the date of
this prospectus; we disclaim any obligation to update or revise
these statements unless required by securities law, and we
caution you not to rely on them unduly. While our management
considers these expectations and assumptions to be reasonable,
they are inherently subject to significant business, economic,
competitive, regulatory and other risks, contingencies and
uncertainties relating to, among other matters, the risks
discussed in our Annual Report on
Form 10-K
for the year ended December 31, 2008, our Quarterly Reports
on
Form 10-Q
for the quarters ended March 31, 2009 and June 30,
2009 and our subsequent SEC filings, as well as those factors
summarized below:
|
|
|
|
|
our business and financial strategy;
|
|
|
|
the estimated quantities of crude oil and natural gas reserves;
|
|
|
|
our use of industry technology;
|
|
|
|
our realized oil and natural gas prices;
|
|
|
|
the timing and amount of the future production of our oil and
natural gas;
|
|
|
|
the amount, nature and timing of our capital expenditures;
|
|
|
|
the drilling of our wells;
|
|
|
|
our competition and government regulations;
|
|
|
|
the marketing of our oil and natural gas;
|
|
|
|
our exploitation activities or property acquisitions;
|
|
|
|
the costs of exploiting and developing our properties and
conducting other operations;
|
|
|
|
general economic and business conditions;
|
|
|
|
our cash flow and anticipated liquidity;
|
|
|
|
hedging results;
|
|
|
|
uncertainty regarding our future operating results;
|
|
|
|
our plans, objectives, expectations and intentions contained in
this prospectus that are not historical; and
|
|
|
|
our ability to integrate acquisitions.
|
Reserve engineering is a process of estimating underground
accumulations of oil and natural gas that cannot be measured in
an exact way. The accuracy of any reserve estimate depends on
the quality of available data, the interpretation of such data
and price and cost assumptions made by our reserve engineers. In
addition, the results of drilling, testing and production
activities may justify revisions of estimates that were made
previously. If significant, such revisions would change the
schedule of any further production and development drilling.
Accordingly, reserve estimates may differ from the quantities of
oil and natural gas that are ultimately recovered.
3
Risk
factors
An investment in our securities involves a significant degree of
risk. Before you invest in our securities you should carefully
consider those risk factors included in our most recent Annual
Report on
Form 10-K,
any Quarterly Reports on
Form 10-Q
and any Current Reports on
Form 8-K,
which are incorporated herein by reference, and those risk
factors that may be included in any applicable prospectus
supplement, together with all of the other information included
in this prospectus, any prospectus supplement and the documents
we incorporate by reference, in evaluating an investment in our
securities. If any of the risks discussed in the foregoing
documents were to occur, our business, financial condition,
results of operations and cash flows could be materially
adversely affected. Please read Cautionary Statement
Regarding Forward-Looking Statements.
Ratios of
earnings to fixed charges and earnings to fixed charges and
preferred stock dividends
The following table contains our consolidated ratios of earnings
to fixed charges and earnings to fixed charges and preferred
stock dividends for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
Chase Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
Properties
|
|
|
|
Six Months
|
|
|
Years Ended
|
|
|
2004) through
|
|
|
Years Ended
|
|
|
|
Ended June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
|
Ratios of earnings to fixed charges(a)
|
|
|
(c
|
)
|
|
|
15.36
|
|
|
|
2.00
|
|
|
|
1.97
|
|
|
|
2.01
|
|
|
|
(c
|
)
|
|
|
NM(d
|
)
|
|
|
NM(d
|
)
|
Ratios of earnings to fixed charges and preferred stock
dividends(b)
|
|
|
(e
|
)
|
|
|
15.36
|
|
|
|
2.00
|
|
|
|
1.90
|
|
|
|
(f
|
)
|
|
|
(e
|
)
|
|
|
NM(d
|
)
|
|
|
NM(d
|
)
|
|
|
|
(a) |
|
The ratio has been computed by dividing earnings by fixed
charges. For purposes of computing the ratio: |
|
|
|
|
|
earnings include income (loss) before income taxes, adjusted for
interest expense and the portion of rental expense deemed to be
representative of the interest component of rental expense; and |
|
|
|
fixed charges consist of interest expense, capitalized interest
and the portion of rental expense deemed to be representative of
the interest component of rental expense. |
|
|
|
(b) |
|
The ratio has been computed by dividing earnings by fixed
charges and preferred stock dividends. For purposes of computing
the ratio: |
|
|
|
|
|
earnings include income (loss) before income taxes, adjusted for
interest expense and the portion of rental expense deemed to be
representative of the interest component of rental expense; and |
|
|
|
fixed charges and preferred stock dividends consist of interest
expense, capitalized interest, the portion of rental expense
deemed to be representative of the interest component of rental
expense and preferred stock dividends. |
|
|
|
(c) |
|
Due to our net loss for the six months ended June 30, 2009
and from inception (April 21, 2004) through
December 31, 2004, the ratio coverage was less than 1:1. To
achieve ratio coverage of 1:1, we would have needed additional
earnings of approximately $80.3 million and
$3.6 million, respectively. |
|
(d) |
|
Not meaningful, as there were no fixed charges or preferred
stock dividends for these periods. |
|
(e) |
|
Due to our net loss for the six months ended June 30, 2009
and from inception (April 21, 2004) through
December 31, 2004, the ratio coverage was less than 1:1. To
achieve a ratio coverage of 1:1, we would have needed additional
earnings of approximately $80.3 million and
$4.4 million, respectively. |
|
(f) |
|
Due to the fixed charges and preferred stock dividends exceeding
earnings for the period, we would have needed additional
earnings of approximately $1.1 million to achieve a ratio
coverage of 1:1. |
4
Use of
proceeds
Except as may be stated in the applicable prospectus supplement,
we intend to use the net proceeds from any sales of securities
by us under this prospectus for general corporate purposes,
which may include repayment or refinancing of borrowings,
working capital, capital expenditures, investments and
acquisitions. Pending any specific application, we may initially
invest funds in short-term marketable securities or apply them
to repayments of indebtedness.
5
Description
of debt securities
The Debt Securities will be either our senior debt securities
(Senior Debt Securities) or our subordinated debt
securities (Subordinated Debt Securities). The
Senior Debt Securities and the Subordinated Debt Securities will
be issued under separate indentures among us, the Subsidiary
Guarantors of such Debt Securities, if any, and a trustee to be
determined (the Trustee). Senior Debt Securities
will be issued under a Senior Indenture and
Subordinated Debt Securities will be issued under a
Subordinated Indenture. Together, the Senior
Indenture and the Subordinated Indenture are called
Indentures.
The Debt Securities may be issued from time to time in one or
more series. The particular terms of each series that are
offered by a prospectus supplement will be described in the
prospectus supplement.
Unless the Debt Securities are guaranteed by our subsidiaries as
described below, the rights of Concho and our creditors,
including holders of the Debt Securities, to participate in the
assets of any subsidiary upon the latters liquidation or
reorganization, will be subject to the prior claims of the
subsidiarys creditors, except to the extent that we may
ourself be a creditor with recognized claims against such
subsidiary.
We have summarized selected provisions of the Indentures below.
The summary is not complete. The form of each Indenture has been
filed with the SEC as an exhibit to the registration statement
of which this prospectus is a part, and you should read the
Indentures for provisions that may be important to you.
Capitalized terms used in the summary have the meanings
specified in the Indentures.
General
The Indentures provide that Debt Securities in separate series
may be issued thereunder from time to time without limitation as
to aggregate principal amount. We may specify a maximum
aggregate principal amount for the Debt Securities of any
series. We will determine the terms and conditions of the Debt
Securities, including the maturity, principal and interest, but
those terms must be consistent with the Indenture. The Debt
Securities will be our unsecured obligations.
The Subordinated Debt Securities will be subordinated in right
of payment to the prior payment in full of all of our Senior
Debt as described under Subordination of
Subordinated Debt Securities and in the prospectus
supplement applicable to any Subordinated Debt Securities. If
the prospectus supplement so indicates, the Debt Securities will
be convertible into our common stock.
If specified in the prospectus supplement respecting a
particular series of Debt Securities, certain subsidiaries of
Concho (each a Subsidiary Guarantor) will fully and
unconditionally guarantee (the Subsidiary Guarantee)
that series as described under Subsidiary
Guarantee and in the prospectus supplement. Each
Subsidiary Guarantee will be an unsecured obligation of the
Subsidiary Guarantor. A Subsidiary Guarantee of Subordinated
Debt Securities will be subordinated to the Senior Debt of the
Subsidiary Guarantor on the same basis as the Subordinated Debt
Securities are subordinated to our Senior Debt.
The applicable prospectus supplement will set forth the price or
prices at which the Debt Securities to be issued will be offered
for sale and will describe the following terms of such Debt
Securities:
(1) the title of the Debt Securities;
(2) whether the Debt Securities are Senior Debt Securities
or Subordinated Debt Securities and, if Subordinated Debt
Securities, the related subordination terms;
(3) whether any Subsidiary Guarantor will provide a
Subsidiary Guarantee of the Debt Securities;
(4) any limit on the aggregate principal amount of the Debt
Securities;
(5) each date on which the principal of the Debt Securities
will be payable;
(6) the interest rate that the Debt Securities will bear
and the interest payment dates for the Debt Securities;
6
(7) each place where payments on the Debt Securities will
be payable;
(8) any terms upon which the Debt Securities may be
redeemed, in whole or in part, at our option;
(9) any sinking fund or other provisions that would
obligate us to redeem or otherwise repurchase the Debt
Securities;
(10) the portion of the principal amount, if less than all,
of the Debt Securities that will be payable upon declaration of
acceleration of the Maturity of the Debt Securities;
(11) whether the Debt Securities are defeasible;
(12) any addition to or change in the Events of Default;
(13) whether the Debt Securities are convertible into our
common stock and, if so, the terms and conditions upon which
conversion will be effected, including the initial conversion
price or conversion rate and any adjustments thereto and the
conversion period;
(14) any addition to or change in the covenants in the
Indenture applicable to the Debt Securities; and
(15) any other terms of the Debt Securities not
inconsistent with the provisions of the Indenture.
Debt Securities, including any Debt Securities that provide for
an amount less than the principal amount thereof to be due and
payable upon a declaration of acceleration of the Maturity
thereof (Original Issue Discount Securities), may be
sold at a substantial discount below their principal amount.
Special United States federal income tax considerations
applicable to Debt Securities sold at an original issue discount
may be described in the applicable prospectus supplement. In
addition, special United States federal income tax or other
considerations applicable to any Debt Securities that are
denominated in a currency or currency unit other than United
States dollars may be described in the applicable prospectus
supplement.
Subordination
of Subordinated Debt Securities
The indebtedness evidenced by the Subordinated Debt Securities
will, to the extent set forth in the Subordinated Indenture with
respect to each series of Subordinated Debt Securities, be
subordinated in right of payment to the prior payment in full of
all of our Senior Debt, including the Senior Debt Securities,
and it may also be senior in right of payment to all of our
Subordinated Debt. The prospectus supplement relating to any
Subordinated Debt Securities will summarize the subordination
provisions of the Subordinated Indenture applicable to that
series including:
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the applicability and effect of such provisions upon any payment
or distribution respecting that series following any
liquidation, dissolution or other
winding-up,
or any assignment for the benefit of creditors or other
marshalling of assets or any bankruptcy, insolvency or similar
proceedings;
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|
the applicability and effect of such provisions in the event of
specified defaults with respect to any Senior Debt, including
the circumstances under which and the periods during which we
will be prohibited from making payments on the Subordinated Debt
Securities; and
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the definition of Senior Debt applicable to the Subordinated
Debt Securities of that series and, if the series is issued on a
senior subordinated basis, the definition of Subordinated Debt
applicable to that series.
|
The prospectus supplement will also describe as of a recent date
the approximate amount of Senior Debt to which the Subordinated
Debt Securities of that series will be subordinated.
The failure to make any payment on any of the Subordinated Debt
Securities by reason of the subordination provisions of the
Subordinated Indenture described in the prospectus supplement
will not be construed as preventing the occurrence of an Event
of Default with respect to the Subordinated Debt Securities
arising from any such failure to make payment.
The subordination provisions described above will not be
applicable to payments in respect of the Subordinated Debt
Securities from a defeasance trust established in connection
with any legal defeasance or
7
covenant defeasance of the Subordinated Debt Securities as
described under Legal Defeasance and Covenant
Defeasance.
Subsidiary
guarantee
If specified in the prospectus supplement, one or more of the
Subsidiary Guarantors will guarantee the Debt Securities of a
series. Unless otherwise indicated in the prospectus supplement,
the following provisions will apply to the Subsidiary Guarantee
of the Subsidiary Guarantor.
Subject to the limitations described below and in the prospectus
supplement, one or more of the Subsidiary Guarantors will
jointly and severally, fully and unconditionally guarantee the
punctual payment when due, whether at Stated Maturity, by
acceleration or otherwise, of all our payment obligations under
the Indentures and the Debt Securities of a series, whether for
principal of, premium, if any, or interest on the Debt
Securities or otherwise (all such obligations guaranteed by a
Subsidiary Guarantor being herein called the Guaranteed
Obligations). The Subsidiary Guarantors will also pay all
expenses (including reasonable counsel fees and expenses)
incurred by the applicable Trustee in enforcing any rights under
a Subsidiary Guarantee with respect to a Subsidiary Guarantor.
In the case of Subordinated Debt Securities, a Subsidiary
Guarantors Subsidiary Guarantee will be subordinated in
right of payment to the Senior Debt of such Subsidiary Guarantor
on the same basis as the Subordinated Debt Securities are
subordinated to our Senior Debt. No payment will be made by any
Subsidiary Guarantor under its Subsidiary Guarantee during any
period in which payments by us on the Subordinated Debt
Securities are suspended by the subordination provisions of the
Subordinated Indenture.
Each Subsidiary Guarantee will be limited in amount to an amount
not to exceed the maximum amount that can be guaranteed by the
relevant Subsidiary Guarantor without rendering such Subsidiary
Guarantee voidable under applicable law relating to fraudulent
conveyance or fraudulent transfer or similar laws affecting the
rights of creditors generally.
Each Subsidiary Guarantee will be a continuing guarantee and
will:
(1) remain in full force and effect until either
(a) payment in full of all the applicable Debt Securities
(or such Debt Securities are otherwise satisfied and discharged
in accordance with the provisions of the applicable Indenture)
or (b) released as described in the following paragraph;
(2) be binding upon each Subsidiary Guarantor; and
(3) inure to the benefit of and be enforceable by the
applicable Trustee, the Holders and their successors,
transferees and assigns.
In the event that (a) a Subsidiary Guarantor ceases to be a
Subsidiary, (b) either legal defeasance or covenant
defeasance occurs with respect to the series or (c) all or
substantially all of the assets or all of the Capital Stock of
such Subsidiary Guarantor is sold, including by way of sale,
merger, consolidation or otherwise, such Subsidiary Guarantor
will be released and discharged of its obligations under its
Subsidiary Guarantee without any further action required on the
part of the Trustee or any Holder, and no other person acquiring
or owning the assets or Capital Stock of such Subsidiary
Guarantor will be required to enter into a Subsidiary Guarantee.
In addition, the prospectus supplement may specify additional
circumstances under which a Subsidiary Guarantor can be released
from its Subsidiary Guarantee.
Form,
exchange and transfer
The Debt Securities of each series will be issuable only in
fully registered form, without coupons, and, unless otherwise
specified in the applicable prospectus supplement, only in
denominations of $1,000 and integral multiples thereof.
At the option of the Holder, subject to the terms of the
applicable Indenture and the limitations applicable to Global
Securities, Debt Securities of each series will be exchangeable
for other Debt Securities of the same series of any authorized
denomination and of a like tenor and aggregate principal amount.
8
Subject to the terms of the applicable Indenture and the
limitations applicable to Global Securities, Debt Securities may
be presented for exchange as provided above or for registration
of transfer (duly endorsed or with the form of transfer endorsed
thereon duly executed) at the office of the Security Registrar
or at the office of any transfer agent designated by us for such
purpose. No service charge will be made for any registration of
transfer or exchange of Debt Securities, but we may require
payment of a sum sufficient to cover any tax or other
governmental charge payable in that connection. Such transfer or
exchange will be effected upon the Security Registrar or such
transfer agent, as the case may be, being satisfied with the
documents of title and identity of the person making the
request. The Security Registrar and any other transfer agent
initially designated by us for any Debt Securities will be named
in the applicable prospectus supplement. We may at any time
designate additional transfer agents or rescind the designation
of any transfer agent or approve a change in the office through
which any transfer agent acts, except that we will be required
to maintain a transfer agent in each Place of Payment for the
Debt Securities of each series.
If the Debt Securities of any series (or of any series and
specified tenor) are to be redeemed in part, we will not be
required to (1) issue, register the transfer of or exchange
any Debt Security of that series (or of that series and
specified tenor, as the case may be) during a period beginning
at the opening of business 15 days before the day of
mailing of a notice of redemption of any such Debt Security that
may be selected for redemption and ending at the close of
business on the day of such mailing or (2) register the
transfer of or exchange any Debt Security so selected for
redemption, in whole or in part, except the unredeemed portion
of any such Debt Security being redeemed in part.
Global
Securities
Some or all of the Debt Securities of any series may be
represented, in whole or in part, by one or more Global
Securities that will have an aggregate principal amount equal to
that of the Debt Securities they represent. Each Global Security
will be registered in the name of a Depositary or its nominee
identified in the applicable prospectus supplement, will be
deposited with such Depositary or nominee or its custodian and
will bear a legend regarding the restrictions on exchanges and
registration of transfer thereof referred to below and any such
other matters as may be provided for pursuant to the applicable
Indenture.
Notwithstanding any provision of the Indentures or any Debt
Security described in this prospectus, no Global Security may be
exchanged in whole or in part for Debt Securities registered,
and no transfer of a Global Security in whole or in part may be
registered, in the name of any Person other than the Depositary
for such Global Security or any nominee of such Depositary
unless:
(1) the Depositary has notified us that it is unwilling or
unable to continue as Depositary for such Global Security or has
ceased to be qualified to act as such as required by the
applicable Indenture, and in either case we fail to appoint a
successor Depositary within 90 days;
(2) an Event of Default with respect to the Debt Securities
represented by such Global Security has occurred and is
continuing and the Trustee has received a written request from
the Depositary to issue certificated Debt Securities;
(3) subject to the rules of the Depositary, we shall have
elected to terminate the book-entry system through the
Depositary; or
(4) other circumstances exist, in addition to or in lieu of
those described above, as may be described in the applicable
prospectus supplement.
All certificated Debt Securities issued in exchange for a Global
Security or any portion thereof will be registered in such names
as the Depositary may direct.
As long as the Depositary, or its nominee, is the registered
holder of a Global Security, the Depositary or such nominee, as
the case may be, will be considered the sole owner and Holder of
such Global Security and the Debt Securities that it represents
for all purposes under the Debt Securities and the applicable
Indenture. Except in the limited circumstances referred to
above, owners of beneficial interests in a Global Security will
not be entitled to have such Global Security or any Debt
Securities that it represents registered in their names,
9
will not receive or be entitled to receive physical delivery of
certificated Debt Securities in exchange for those interests and
will not be considered to be the owners or Holders of such
Global Security or any Debt Securities that it represents for
any purpose under the Debt Securities or the applicable
Indenture. All payments on a Global Security will be made to the
Depositary or its nominee, as the case may be, as the Holder of
the security. The laws of some jurisdictions may require that
some purchasers of Debt Securities take physical delivery of
such Debt Securities in certificated form. These laws may impair
the ability to transfer beneficial interests in a Global
Security.
Ownership of beneficial interests in a Global Security will be
limited to institutions that have accounts with the Depositary
or its nominee (participants) and to persons that
may hold beneficial interests through participants. In
connection with the issuance of any Global Security, the
Depositary will credit, on its book-entry registration and
transfer system, the respective principal amounts of Debt
Securities represented by the Global Security to the accounts of
its participants. Ownership of beneficial interests in a Global
Security will be shown only on, and the transfer of those
ownership interests will be effected only through, records
maintained by the Depositary (with respect to participants
interests) or any such participant (with respect to interests of
Persons held by such participants on their behalf). Payments,
transfers, exchanges and other matters relating to beneficial
interests in a Global Security may be subject to various
policies and procedures adopted by the Depositary from time to
time. None of us, the Subsidiary Guarantors, the Trustees or the
agents of us, the Subsidiary Guarantors or the Trustees will
have any responsibility or liability for any aspect of the
Depositarys or any participants records relating to,
or for payments made on account of, beneficial interests in a
Global Security, or for maintaining, supervising or reviewing
any records relating to such beneficial interests.
Payment
and Paying Agents
Unless otherwise indicated in the applicable prospectus
supplement, payment of interest on a Debt Security on any
Interest Payment Date will be made to the Person in whose name
such Debt Security (or one or more Predecessor Securities) is
registered at the close of business on the Regular Record Date
for such interest.
Unless otherwise indicated in the applicable prospectus
supplement, principal of and any premium and interest on the
Debt Securities of a particular series will be payable at the
office of such Paying Agent or Paying Agents as we may designate
for such purpose from time to time, except that at our option
payment of any interest on Debt Securities in certificated form
may be made by check mailed to the address of the Person
entitled thereto as such address appears in the Security
Register. Unless otherwise indicated in the applicable
prospectus supplement, the corporate trust office of the Trustee
under the Senior Indenture in The City of New York will be
designated as sole Paying Agent for payments with respect to
Senior Debt Securities of each series, and the corporate trust
office of the Trustee under the Subordinated Indenture in The
City of New York will be designated as the sole Paying Agent for
payment with respect to Subordinated Debt Securities of each
series. Any other Paying Agents initially designated by us for
the Debt Securities of a particular series will be named in the
applicable prospectus supplement. We may at any time designate
additional Paying Agents or rescind the designation of any
Paying Agent or approve a change in the office through which any
Paying Agent acts, except that we will be required to maintain a
Paying Agent in each Place of Payment for the Debt Securities of
a particular series.
All money paid by us to a Paying Agent for the payment of the
principal of or any premium or interest on any Debt Security
which remains unclaimed at the end of two years after such
principal, premium or interest has become due and payable will
be repaid to us, and the Holder of such Debt Security thereafter
may look only to us for payment.
10
Consolidation,
merger and sale of assets
Unless otherwise specified in the prospectus supplement, we may
not consolidate with or merge into, or transfer, lease or
otherwise dispose of all or substantially all of our assets to,
any Person (a successor Person), and may not permit
any Person to consolidate with or merge into us, unless:
(1) the successor Person (if not us) is a corporation,
partnership, trust or other entity organized and validly
existing under the laws of any domestic jurisdiction and assumes
our obligations on the Debt Securities and under the Indentures;
(2) immediately before and after giving pro forma effect to
the transaction, no Event of Default, and no event which, after
notice or lapse of time or both, would become an Event of
Default, has occurred and is continuing; and
(3) several other conditions, including any additional
conditions with respect to any particular Debt Securities
specified in the applicable prospectus supplement, are met.
The successor Person (if not us) will be substituted for us
under the applicable Indenture with the same effect as if it had
been an original party to such Indenture, and, except in the
case of a lease, we will be relieved from any further
obligations under such Indenture and the Debt Securities.
Events of
Default
Unless otherwise specified in the prospectus supplement, each of
the following will constitute an Event of Default under the
applicable Indenture with respect to Debt Securities of any
series:
(1) failure to pay principal of or any premium on any Debt
Security of that series when due, whether or not, in the case of
Subordinated Debt Securities, such payment is prohibited by the
subordination provisions of the Subordinated Indenture;
(2) failure to pay any interest on any Debt Securities of
that series when due, continued for 30 days, whether or
not, in the case of Subordinated Debt Securities, such payment
is prohibited by the subordination provisions of the
Subordinated Indenture;
(3) failure to deposit any sinking fund payment, when due,
in respect of any Debt Security of that series, whether or not,
in the case of Subordinated Debt Securities, such deposit is
prohibited by the subordination provisions of the Subordinated
Indenture;
(4) failure to perform or comply with the provisions
described under Consolidation, Merger and Sale
of Assets;
(5) failure to perform any of our other covenants in such
Indenture (other than a covenant included in such Indenture
solely for the benefit of a series other than that series),
continued for 60 days after written notice has been given
by the applicable Trustee, or the Holders of at least 25% in
principal amount of the Outstanding Debt Securities of that
series, as provided in such Indenture;
(6) any Debt of ourself, any Significant Subsidiary or, if
a Subsidiary Guarantor has guaranteed the series, such
Subsidiary Guarantor, is not paid within any applicable grace
period after final maturity or is accelerated by its holders
because of a default and the total amount of such Debt unpaid or
accelerated exceeds $20.0 million;
(7) any judgment or decree for the payment of money in
excess of $20.0 million is entered against us, any
Significant Subsidiary or, if a Subsidiary Guarantor has
guaranteed the series, such Subsidiary Guarantor, remains
outstanding for a period of 60 consecutive days following entry
of such judgment and is not discharged, waived or stayed;
(8) certain events of bankruptcy, insolvency or
reorganization affecting us, any Significant Subsidiary or, if a
Subsidiary Guarantor has guaranteed the series, such Subsidiary
Guarantor; and
11
(9) if any Subsidiary Guarantor has guaranteed such series,
the Subsidiary Guarantee of any such Subsidiary Guarantor is
held by a final non-appealable order or judgment of a court of
competent jurisdiction to be unenforceable or invalid or ceases
for any reason to be in full force and effect (other than in
accordance with the terms of the applicable Indenture) or any
Subsidiary Guarantor or any Person acting on behalf of any
Subsidiary Guarantor denies or disaffirms such Subsidiary
Guarantors obligations under its Subsidiary Guarantee
(other than by reason of a release of such Subsidiary Guarantor
from its Subsidiary Guarantee in accordance with the terms of
the applicable Indenture).
If an Event of Default (other than an Event of Default with
respect to Concho Resources Inc. described in clause (8)
above) with respect to the Debt Securities of any series at the
time Outstanding occurs and is continuing, either the applicable
Trustee or the Holders of at least 25% in principal amount of
the Outstanding Debt Securities of that series by notice as
provided in the Indenture may declare the principal amount of
the Debt Securities of that series (or, in the case of any Debt
Security that is an Original Issue Discount Debt Security, such
portion of the principal amount of such Debt Security as may be
specified in the terms of such Debt Security) to be due and
payable immediately, together with any accrued and unpaid
interest thereon. If an Event of Default with respect to Concho
Resources Inc. described in clause (8) above with respect
to the Debt Securities of any series at the time Outstanding
occurs, the principal amount of all the Debt Securities of that
series (or, in the case of any such Original Issue Discount
Security, such specified amount) will automatically, and without
any action by the applicable Trustee or any Holder, become
immediately due and payable, together with any accrued and
unpaid interest thereon. After any such acceleration and its
consequences, but before a judgment or decree based on
acceleration, the Holders of a majority in principal amount of
the Outstanding Debt Securities of that series may, under
certain circumstances, rescind and annul such acceleration if
all Events of Default with respect to that series, other than
the non-payment of accelerated principal (or other specified
amount), have been cured or waived as provided in the applicable
Indenture. For information as to waiver of defaults, see
Modification and Waiver below.
Subject to the provisions of the Indentures relating to the
duties of the Trustees in case an Event of Default has occurred
and is continuing, no Trustee will be under any obligation to
exercise any of its rights or powers under the applicable
Indenture at the request or direction of any of the Holders,
unless such Holders have offered to such Trustee reasonable
security or indemnity. Subject to such provisions for the
indemnification of the Trustees, the Holders of a majority in
principal amount of the Outstanding Debt Securities of any
series will have the right to direct the time, method and place
of conducting any proceeding for any remedy available to the
Trustee or exercising any trust or power conferred on the
Trustee with respect to the Debt Securities of that series.
No Holder of a Debt Security of any series will have any right
to institute any proceeding with respect to the applicable
Indenture, or for the appointment of a receiver or a trustee, or
for any other remedy thereunder, unless:
(1) such Holder has previously given to the Trustee under
the applicable Indenture written notice of a continuing Event of
Default with respect to the Debt Securities of that series;
(2) the Holders of at least 25% in principal amount of the
Outstanding Debt Securities of that series have made written
request, and such Holder or Holders have offered reasonable
security or indemnity, to the Trustee to institute such
proceeding as trustee; and
(3) the Trustee has failed to institute such proceeding,
and has not received from the Holders of a majority in principal
amount of the Outstanding Debt Securities of that series a
direction inconsistent with such request, within 60 days
after such notice, request and offer.
However, such limitations do not apply to a suit instituted by a
Holder of a Debt Security for the enforcement of payment of the
principal of or any premium or interest on such Debt Security on
or after the applicable due date specified in such Debt Security
or, if applicable, to convert such Debt Security.
We will be required to furnish to each Trustee annually a
statement by certain of our officers as to whether or not we, to
their knowledge, are in default in the performance or observance
of any of the terms, provisions and conditions of the applicable
Indenture and, if so, specifying all such known defaults.
12
Modification
and waiver
We may modify or amend an Indenture without the consent of any
holders of the Debt Securities in certain circumstances,
including:
(1) to evidence the succession under the Indenture of
another Person to us or any Subsidiary Guarantor and to provide
for its assumption of our or such Subsidiary Guarantors
obligations to holders of Debt Securities;
(2) to make any changes that would add any additional
covenants of us or the Subsidiary Guarantors for the benefit of
the holders of Debt Securities or that do not adversely affect
the rights under the Indenture of the Holders of Debt Securities
in any material respect;
(3) to add any additional Events of Default;
(4) to provide for uncertificated notes in addition to or
in place of certificated notes;
(5) to secure the Debt Securities;
(6) to establish the form or terms of any series of Debt
Securities;
(7) to evidence and provide for the acceptance of
appointment under the Indenture of a successor Trustee;
(8) to cure any ambiguity, defect or inconsistency;
(9) to add Subsidiary Guarantors; or
(10) in the case of any Subordinated Debt Security, to make
any change in the subordination provisions that limits or
terminates the benefits applicable to any Holder of Senior Debt.
Other modifications and amendments of an Indenture may be made
by us, the Subsidiary Guarantors, if applicable, and the
applicable Trustee with the consent of the Holders of not less
than a majority in principal amount of the Outstanding Debt
Securities of each series affected by such modification or
amendment; provided, however, that no such modification or
amendment may, without the consent of the Holder of each
Outstanding Debt Security affected thereby:
(1) change the Stated Maturity of the principal of, or any
installment of principal of or interest on, any Debt Security;
(2) reduce the principal amount of, or any premium or
interest on, any Debt Security;
(3) reduce the amount of principal of an Original Issue
Discount Security or any other Debt Security payable upon
acceleration of the Maturity thereof;
(4) change the place or currency of payment of principal
of, or any premium or interest on, any Debt Security;
(5) impair the right to institute suit for the enforcement
of any payment due on or any conversion right with respect to
any Debt Security;
(6) modify the subordination provisions in the case of
Subordinated Debt Securities, or modify any conversion
provisions, in either case in a manner adverse to the Holders of
the Subordinated Debt Securities;
(7) except as provided in the applicable Indenture, release
the Subsidiary Guarantee of a Subsidiary Guarantor;
(8) reduce the percentage in principal amount of
Outstanding Debt Securities of any series, the consent of whose
Holders is required for modification or amendment of the
Indenture;
(9) reduce the percentage in principal amount of
Outstanding Debt Securities of any series necessary for waiver
of compliance with certain provisions of the Indenture or for
waiver of certain defaults;
(10) modify such provisions with respect to modification,
amendment or waiver; or
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(11) following the making of an offer to purchase Debt
Securities from any Holder that has been made pursuant to a
covenant in such Indenture, modify such covenant in a manner
adverse to such Holder.
The Holders of not less than a majority in principal amount of
the Outstanding Debt Securities of any series may waive
compliance by us with certain restrictive provisions of the
applicable Indenture. The Holders of not less than a majority in
principal amount of the Outstanding Debt Securities of any
series may waive any past default under the applicable
Indenture, except a default in the payment of principal, premium
or interest and certain covenants and provisions of the
Indenture which cannot be amended without the consent of the
Holder of each Outstanding Debt Security of such series.
Each of the Indentures provides that in determining whether the
Holders of the requisite principal amount of the Outstanding
Debt Securities have given or taken any direction, notice,
consent, waiver or other action under such Indenture as of any
date:
(1) the principal amount of an Original Issue Discount
Security that will be deemed to be Outstanding will be the
amount of the principal that would be due and payable as of such
date upon acceleration of maturity to such date;
(2) if, as of such date, the principal amount payable at
the Stated Maturity of a Debt Security is not determinable (for
example, because it is based on an index), the principal amount
of such Debt Security deemed to be Outstanding as of such date
will be an amount determined in the manner prescribed for such
Debt Security;
(3) the principal amount of a Debt Security denominated in
one or more foreign currencies or currency units that will be
deemed to be Outstanding will be the United States-dollar
equivalent, determined as of such date in the manner prescribed
for such Debt Security, of the principal amount of such Debt
Security (or, in the case of a Debt Security described in
clause (1) or (2) above, of the amount described in
such clause); and
(4) certain Debt Securities, including those owned by us,
any Subsidiary Guarantor or any of our other Affiliates, will
not be deemed to be Outstanding.
Except in certain limited circumstances, we will be entitled to
set any day as a record date for the purpose of determining the
Holders of Outstanding Debt Securities of any series entitled to
give or take any direction, notice, consent, waiver or other
action under the applicable Indenture, in the manner and subject
to the limitations provided in the Indenture. In certain limited
circumstances, the Trustee will be entitled to set a record date
for action by Holders. If a record date is set for any action to
be taken by Holders of a particular series, only persons who are
Holders of Outstanding Debt Securities of that series on the
record date may take such action. To be effective, such action
must be taken by Holders of the requisite principal amount of
such Debt Securities within a specified period following the
record date. For any particular record date, this period will be
180 days or such other period as may be specified by us (or
the Trustee, if it set the record date), and may be shortened or
lengthened (but not beyond 180 days) from time to time.
Satisfaction
and discharge
Each Indenture will be discharged and will cease to be of
further effect as to all outstanding Debt Securities of any
series issued thereunder, when:
(1) either:
(a) all outstanding Debt Securities of that series that
have been authenticated (except lost, stolen or destroyed Debt
Securities that have been replaced or paid and Debt Securities
for whose payment money has theretofore been deposited in trust
and thereafter repaid to us) have been delivered to the Trustee
for cancellation; or
(b) all outstanding Debt Securities of that series that
have been not delivered to the Trustee for cancellation have
become due and payable or will become due and payable at their
Stated Maturity within one year or are to be called for
redemption within one year under arrangements satisfactory to
the Trustee and in any case we have irrevocably deposited with
the Trustee as trust funds money in an
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amount sufficient, without consideration of any reinvestment of
interest, to pay the entire indebtedness of such Debt Securities
not delivered to the Trustee for cancellation, for principal,
premium, if any, and accrued interest to the Stated Maturity or
redemption date;
(2) we have paid or caused to be paid all other sums
payable by us under the Indenture with respect to the Debt
Securities of that series; and
(3) we have delivered an Officers Certificate and an
Opinion of Counsel to the Trustee stating that all conditions
precedent to satisfaction and discharge of the Indenture with
respect to the Debt Securities of that series have been
satisfied.
Legal
defeasance and covenant defeasance
To the extent indicated in the applicable prospectus supplement,
we may elect, at our option at any time, to have our obligations
discharged under provisions relating to defeasance and discharge
of indebtedness, which we call legal defeasance, or
relating to defeasance of certain restrictive covenants applied
to the Debt Securities of any series, or to any specified part
of a series, which we call covenant defeasance.
Legal defeasance. The Indentures provide that,
upon our exercise of our option (if any) to have the legal
defeasance provisions applied to any series of Debt Securities,
we and, if applicable, each Subsidiary Guarantor will be
discharged from all our obligations, and, if such Debt
Securities are Subordinated Debt Securities, the provisions of
the Subordinated Indenture relating to subordination will cease
to be effective, with respect to such Debt Securities (except
for certain obligations to convert, exchange or register the
transfer of Debt Securities, to replace stolen, lost or
mutilated Debt Securities, to maintain paying agencies and to
hold moneys for payment in trust) upon the deposit in trust for
the benefit of the Holders of such Debt Securities of money or
U.S. Government Obligations, or both, which, through the
payment of principal and interest in respect thereof in
accordance with their terms, will provide money in an amount
sufficient (in the opinion of a nationally recognized firm of
independent public accountants) to pay the principal of and any
premium and interest on such Debt Securities on the respective
Stated Maturities in accordance with the terms of the applicable
Indenture and such Debt Securities. Such defeasance or discharge
may occur only if, among other things:
(1) we have delivered to the applicable Trustee an Opinion
of Counsel to the effect that we have received from, or there
has been published by, the United States Internal Revenue
Service a ruling, or there has been a change in tax law, in
either case to the effect that Holders of such Debt Securities
will not recognize gain or loss for federal income tax purposes
as a result of such deposit and legal defeasance and will be
subject to federal income tax on the same amount, in the same
manner and at the same times as would have been the case if such
deposit and legal defeasance were not to occur;
(2) no Event of Default or event that with the passing of
time or the giving of notice, or both, shall constitute an Event
of Default shall have occurred and be continuing at the time of
such deposit or, with respect to any Event of Default described
in clause (8) under Events of
Default, at any time until 121 days after such
deposit;
(3) such deposit and legal defeasance will not result in a
breach or violation of, or constitute a default under, any
agreement or instrument (other than the applicable Indenture) to
which we are a party or by which we are bound;
(4) in the case of Subordinated Debt Securities, at the
time of such deposit, no default in the payment of all or a
portion of principal of (or premium, if any) or interest on any
Senior Debt shall have occurred and be continuing, no event of
default shall have resulted in the acceleration of any Senior
Debt and no other event of default with respect to any Senior
Debt shall have occurred and be continuing permitting after
notice or the lapse of time, or both, the acceleration
thereof; and
(5) we have delivered to the Trustee an Opinion of Counsel
to the effect that such deposit shall not cause the Trustee or
the trust so created to be subject to the Investment Company Act
of 1940.
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Covenant defeasance. The Indentures provide
that, upon our exercise of our option (if any) to have the
covenant defeasance provisions applied to any Debt Securities,
we may fail to comply with certain restrictive covenants (but
not with respect to conversion, if applicable), including those
that may be described in the applicable prospectus supplement,
and the occurrence of certain Events of Default, which are
described above in clause (5) (with respect to such restrictive
covenants) and clauses (6), (7) and (9) under
Events of Default and any that may be described in
the applicable prospectus supplement, will not be deemed to
either be or result in an Event of Default and, if such Debt
Securities are Subordinated Debt Securities, the provisions of
the Subordinated Indenture relating to subordination will cease
to be effective, in each case with respect to such Debt
Securities. In order to exercise such option, we must deposit,
in trust for the benefit of the Holders of such Debt Securities,
money or U.S. Government Obligations, or both, which,
through the payment of principal and interest in respect thereof
in accordance with their terms, will provide money in an amount
sufficient (in the opinion of a nationally recognized firm of
independent public accountants) to pay the principal of and any
premium and interest on such Debt Securities on the respective
Stated Maturities in accordance with the terms of the applicable
Indenture and such Debt Securities. Such covenant defeasance may
occur only if we have delivered to the applicable Trustee an
Opinion of Counsel to the effect that Holders of such Debt
Securities will not recognize gain or loss for federal income
tax purposes as a result of such deposit and covenant defeasance
and will be subject to federal income tax on the same amount, in
the same manner and at the same times as would have been the
case if such deposit and covenant defeasance were not to occur,
and the requirements set forth in clauses (2), (3), (4) and
(5) above are satisfied. If we exercise this option with
respect to any series of Debt Securities and such Debt
Securities were declared due and payable because of the
occurrence of any Event of Default, the amount of money and
U.S. Government Obligations so deposited in trust would be
sufficient to pay amounts due on such Debt Securities at the
time of their respective Stated Maturities but may not be
sufficient to pay amounts due on such Debt Securities upon any
acceleration resulting from such Event of Default. In such case,
we would remain liable for such payments.
If we exercise either our legal defeasance or covenant
defeasance option, any Subsidiary Guarantee will terminate.
No
personal liability of directors, officers, employees and
stockholders
No director, officer, employee, incorporator, stockholder,
member, partner or trustee of the Company or any Subsidiary
Guarantor, as such, shall have any liability for any obligations
of the Company or any Subsidiary Guarantor under the Debt
Securities, the Indentures or any Subsidiary Guarantees or for
any claim based on, in respect of, or by reason of, such
obligations or their creation. By accepting a Debt Security,
each Holder shall be deemed to have waived and released all such
liability. The waiver and release shall be a part of the
consideration for the issue of the Debt Securities. The waiver
may not be effective to waive liabilities under the federal
securities laws, and it is the view of the SEC that such a
waiver is against public policy.
Notices
Notices to Holders of Debt Securities will be given by mail to
the addresses of such Holders as they may appear in the Security
Register.
Title
We, the Subsidiary Guarantors, the Trustees and any agent of us,
the Subsidiary Guarantors or a Trustee may treat the Person in
whose name a Debt Security is registered as the absolute owner
of the Debt Security (whether or not such Debt Security may be
overdue) for the purpose of making payment and for all other
purposes.
Governing
law
The Indentures and the Debt Securities will be governed by, and
construed in accordance with, the law of the State of New York.
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The
Trustee
We will enter into the Indentures with a Trustee that is
qualified to act under the Trust Indenture Act of 1939, as
amended, and with any other Trustees chosen by us and appointed
in a supplemental indenture for a particular series of Debt
Securities. We may maintain a banking relationship in the
ordinary course of business with our Trustee and one or more of
its affiliates.
Resignation or Removal of Trustee. If the
Trustee has or acquires a conflicting interest within the
meaning of the Trust Indenture Act, the Trustee must either
eliminate its conflicting interest or resign, to the extent and
in the manner provided by, and subject to the provisions of, the
Trust Indenture Act and the applicable Indenture. Any
resignation will require the appointment of a successor Trustee
under the applicable Indenture in accordance with the terms and
conditions of such Indenture.
The Trustee may resign or be removed by us with respect to one
or more series of Debt Securities and a successor Trustee may be
appointed to act with respect to any such series. The holders of
a majority in aggregate principal amount of the Debt Securities
of any series may remove the Trustee with respect to the Debt
Securities of such series.
Limitations on Trustee if It Is Our
Creditor. Each Indenture will contain certain
limitations on the right of the Trustee, in the event that it
becomes our creditor, to obtain payment of claims in certain
cases, or to realize on certain property received in respect of
any such claim as security or otherwise.
Certificates and Opinions to Be Furnished to
Trustee. Each Indenture will provide that, in
addition to other certificates or opinions that may be
specifically required by other provisions of an Indenture, every
application by us for action by the Trustee must be accompanied
by an Officers Certificate and an Opinion of Counsel
stating that, in the opinion of the signers, all conditions
precedent to such action have been complied with by us.
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Description
of capital stock
The following summary of our capital stock, Restated Certificate
of Incorporation (the Certificate of Incorporation)
and Amended and Restated Bylaws (the Bylaws) does
not purport to be complete and is qualified in its entirety by
reference to the provisions of applicable law and to our
Certificate of Incorporation and Bylaws.
Our authorized capital stock consists of 300,000,000 shares
of common stock, $0.001 par value per share, and
10,000,000 shares of preferred stock, $0.001 par value
per share.
Common
stock
As of September 1, 2009, we had 85,562,638 shares of
voting common stock outstanding, including 467,692 shares
of restricted stock. The shares of restricted stock have voting
rights, rights to receive dividends and are subject to certain
forfeiture restrictions.
Our common stock commenced trading on the NYSE under the symbol
CXO on August 3, 2007 in connection with our
initial public offering. As of September 1, 2009, there
were 41,941 holders of record of our common stock.
Holders of our common stock are entitled to one vote for each
share held on all matters submitted to a vote of stockholders
and do not have cumulative voting rights. Accordingly, holders
of a majority of the shares of our common stock entitled to vote
in any election of directors may elect all of the directors
standing for election.
Holders of our common stock are entitled to receive
proportionately any dividends if and when such dividends are
declared by our board of directors, subject to any preferential
dividend rights of preferred stock that may be outstanding at
the time such dividends are declared. Upon the liquidation,
dissolution or winding up of our company, the holders of our
common stock are entitled to receive ratably our net assets
available after the payment of all debts and other liabilities
and subject to the prior rights of any outstanding preferred
stock. Holders of our common stock have no preemptive,
subscription, redemption or conversion rights. The rights,
preferences and privileges of holders of our common stock are
subject to, and may be adversely affected by, the rights of the
holders of shares of any series of preferred stock that we may
designate and issue in the future.
We have not paid, and do not intend to pay in the foreseeable
future, cash dividends on our common stock.
There are no redemption or sinking fund provisions applicable to
our common stock. All outstanding shares of our common stock are
fully paid and non-assessable.
Preferred
stock
Under the terms of our Certificate of Incorporation, our board
of directors is authorized to designate and issue shares of
preferred stock in one or more series without further vote or
action by our stockholders. Our board of directors has the
discretion to determine the rights, preferences, privileges and
restrictions, including voting rights, dividend rights,
conversion rights, redemption privileges and liquidation
preferences, of each series of preferred stock. It is not
possible to state the actual effect of the issuance of any
shares of preferred stock upon the rights of holders of the
common stock until the board of directors determines the
specific rights of the holders of the preferred stock. However,
these effects might include:
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restricting dividends on the common stock;
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diluting the voting power of the common stock;
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impairing the liquidation rights of the common stock; and
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delaying or preventing a change in control of our company.
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We currently have no shares of preferred stock outstanding, and
we have no present plans to issue any shares of preferred stock.
Anti-takeover
provisions of our Certificate of Incorporation and
Bylaws
Our Certificate of Incorporation and Bylaws contain several
provisions that could delay or make more difficult the
acquisition of us through a hostile tender offer, open market
purchases, proxy contest, merger or other takeover attempt that
a stockholder might consider in his or her best interest,
including those attempts that might result in a premium over the
market price of our common stock.
Written
consent of stockholders
Our Certificate of Incorporation and Bylaws provide that any
action required or permitted to be taken by our stockholders
must be taken at a duly called meeting of stockholders and not
by written consent.
Special
meetings of stockholders
Subject to the rights of the holders of any series of preferred
stock, our Bylaws provide that special meetings of the
stockholders may only be called by the chairman of the board of
directors or by the resolution of our board of directors
approved by a majority of the total number of authorized
directors. No business other than that stated in a notice may be
transacted at any special meeting.
Advance
notice procedure for director nominations and stockholder
proposals
Our Bylaws provide that adequate notice must be given to
nominate candidates for election as directors or to make
proposals for consideration at annual meetings of our
stockholders. For nominations or other business to be properly
brought before an annual meeting by a stockholder, the
stockholder must have delivered a written notice to the
Secretary of our company at our principal executive offices not
less than 45 calendar days nor more than 75 calendar days prior
to the first anniversary of the date on which we first mailed
our proxy materials for the preceding years annual
meeting; provided, however, that in the event that the date of
the annual meeting is more than 30 calendar days before or more
than 30 calendar days after the first anniversary of the date of
the preceding years annual meeting notice by the
stockholder to be timely must be so delivered not later than the
close of business on the later of the 90th calendar day
prior to such annual meeting or the 10th calendar day
following the calendar day on which public announcement, if any,
of the date of such meeting is first made by us.
Nominations of persons for election to our board of directors
may be made at a special meeting of stockholders at which
directors are to be elected pursuant to our notice of meeting
(i) by or at the direction of our board of directors, or
(ii) by any stockholder of our company who is a stockholder
of record at the time of the giving of notice of the meeting,
who is entitled to vote at the meeting and who complies with the
notice procedures set forth in our Bylaws. In the event we call
a special meeting of stockholders for the purpose of electing
one or more directors to our board of directors, any stockholder
may nominate a person or persons (as the case may be) for
election to such position(s) if the stockholder provides written
notice to the Secretary of our company at our principal
executive offices not earlier than the close of business on the
90th calendar day prior to such special meeting, nor later
than the close of business on the later of the
70th calendar day prior to such special meeting or the
10th calendar day following the day on which public
announcement, if any, is first made of the date of the special
meeting and of the nominees proposed by our board of directors
to be elected at such meeting.
These procedures may operate to limit the ability of
stockholders to bring business before a stockholders meeting,
including the nomination of directors and the consideration of
any transaction that could result in a change in control and
that may result in a premium to our stockholders
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Classified
board
Our Certificate of Incorporation divides our directors into
three classes serving staggered three-year terms. As a result,
stockholders will elect approximately one-third of the board of
directors each year. This provision, when coupled with
provisions of our Certificate of Incorporation authorizing only
the board of directors to fill vacant or newly created
directorships or increase the size of the board of directors and
provisions providing that directors may only be removed for
cause and then only by the holders of not less than
662/3%
of the voting power of all outstanding voting stock, may deter a
stockholder from gaining control of our board of directors by
removing incumbent directors or increasing the number of
directorships and simultaneously filling the vacancies or newly
created directorships with its own nominees.
Authorized
capital stock
Our Certificate of Incorporation contains provisions that the
authorized but unissued shares of common stock and preferred
stock are available for future issuance, subject to various
limitations imposed by the New York Stock Exchange. These
additional shares may be utilized for a variety of corporate
purposes, including public offerings to raise capital, corporate
acquisitions and employee benefit plans. The existence of
authorized but unissued shares of common stock and preferred
stock could make it more difficult or discourage an attempt to
obtain control of our company by means of a proxy contest,
tender offer, merger or otherwise.
Amendment
of Bylaws
Under Delaware law, the power to adopt, amend or repeal bylaws
is conferred upon the stockholders. A corporation may, however,
in its certificate of incorporation also confer upon the board
of directors the power to adopt, amend or repeal its bylaws. Our
Certificate of Incorporation and Bylaws grant our board of
directors the power to adopt, amend and repeal our Bylaws on the
affirmative vote of a majority of the directors then in office.
Our stockholders may adopt, amend or repeal our Bylaws but only
at any regular or special meeting of stockholders by the holders
of not less than
662/3%
of the voting power of all outstanding voting stock.
Certain
oil and natural gas opportunities
Certain of our stockholders who received shares of common stock
in the combination transaction and our non-employee
directors may from time to time have investments in other
exploration and production companies that may compete with us.
Our certificate of incorporation and our Business Opportunities
Agreement provide a safe harbor under which these entities and
directors may participate in the oil and gas exploration,
exploitation, development and production business without
breaching their fiduciary duties as controlling stockholders or
directors. No participation is allowed with respect to:
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any business opportunity that is brought to the attention of a
covered individual or entity solely in such persons
capacity as a director or officer of our company and with
respect to which, at the time of such presentment, no other
covered individual or entity has independently received notice
or otherwise identified such opportunity; or
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any business opportunity that is identified by a covered
individual or entity solely through the disclosure of
information by or on behalf of us.
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The covered individuals and entities have no obligation to offer
such opportunities to us, but interested directors are required
to disclose conflicts of interest. We are not prohibited from
pursuing any business opportunity with respect to which we have
renounced any interest.
Limitation
of liability of directors
Our Certificate of Incorporation provides that no director shall
be personally liable to us or our stockholders for monetary
damages for breach of fiduciary duty as a director, except for
liability as follows:
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for any breach of the directors duty of loyalty to us or
our stockholders;
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for acts or omissions not in good faith or which involve
intentional misconduct or a knowing violation of laws;
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for unlawful payment of a dividend or unlawful stock purchase or
stock redemption; and
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for any transaction from which the director derived an improper
personal benefit.
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The effect of these provisions is to eliminate our rights and
our stockholders rights, through stockholders
derivative suits on our behalf, to recover monetary damages
against a director for a breach of fiduciary duty as a director,
including breaches resulting from grossly negligent behavior,
except in the situations described above.
Delaware
takeover statute
We are subject to Section 203 of the Delaware General
Corporation Law, which prohibits a Delaware corporation from
engaging in any business combination with any interested
stockholder for a period of three years after the date that such
stockholder became an interested stockholder, with the following
exceptions:
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before such date, the board of directors of the corporation
approved either the business combination or the transaction that
resulted in the stockholder becoming an interested stockholder
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upon completion of the transaction that resulted in the
stockholder becoming an interested stockholder, the interested
stockholder owned at least 85% of the voting stock of the
corporation outstanding at the time the transaction began,
excluding for purposes of determining the voting stock
outstanding (but not the outstanding voting stock owned by the
interested stockholder) those shares owned (1) by persons
who are directors and also officers and (2) employee stock
plans in which employee participants do not have the right to
determine confidentially whether shares held subject to the plan
will be tendered in a tender or exchange offer; or
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on or after such date, the business combination is approved by
the board of directors and authorized at an annual or special
meeting of the stockholders, and not by written consent, by the
affirmative vote of at least
662/3%
of the outstanding voting stock that is not owned by the
interested stockholder.
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In general, Section 203 defines a business combination to
include the following:
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any merger or consolidation involving the corporation and the
interested stockholder;
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any sale, transfer, pledge or other disposition (in one
transaction or a series of transactions) of 10% or more of the
assets of the corporation involving the interested stockholder;
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subject to certain exceptions, any transaction that results in
the issuance or transfer by the corporation of any stock of the
corporation to the interested stockholder;
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any transaction involving the corporation that has the effect of
increasing the proportionate share of the stock or any class or
series of the corporation beneficially owned by the interested
stockholder; or
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the receipt by the interested stockholder of the benefit of any
loss, advances, guarantees, pledges or other financial benefits
by or through the corporation.
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In general, Section 203 defines an interested
stockholder as an entity or person who, together with the
persons affiliates and associates, beneficially owns, or
within three years prior to the time of determination of
interested stockholder status did own, 15% or more of the
outstanding voting stock of the corporation.
Transfer
agent and registrar
The transfer agent and registrar for our common stock is
American Stock Transfer & Trust Company.
21
Description
of warrants
We may issue warrants for the purchase of our common stock.
Warrants may be issued independently or together with Debt
Securities, preferred stock or common stock offered by any
prospectus supplement and may be attached to or separate from
any such offered securities. Each series of warrants will be
issued under a separate warrant agreement to be entered into
between us and a bank or trust company, as warrant agent, all as
set forth in the prospectus supplement relating to the
particular issue of warrants. The warrant agent will act solely
as our agent in connection with the warrants and will not assume
any obligation or relationship of agency or trust for or with
any holders of warrants or beneficial owners of warrants. The
following summary of certain provisions of the warrants does not
purport to be complete and is subject to, and is qualified in
its entirety by reference to, all provisions of the warrant
agreements.
You should refer to the prospectus supplement relating to a
particular issue of warrants for the terms of and information
relating to the warrants, including, where applicable:
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(1)
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the number of shares of common stock purchasable upon exercise
of the warrants and the price at which such number of shares of
common stock may be purchased upon exercise of the warrants;
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(2)
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the date on which the right to exercise the warrants commences
and the date on which such right expires (the Expiration
Date);
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(3)
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United States federal income tax consequences applicable to the
warrants;
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(4)
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the amount of the warrants outstanding as of the most recent
practicable date; and
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(5)
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any other terms of the warrants.
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Warrants will be offered and exercisable for United States
dollars only. Warrants will be issued in registered form only.
Each warrant will entitle its holder to purchase such number of
shares of common stock at such exercise price as is in each case
set forth in, or calculable from, the prospectus supplement
relating to the warrants. The exercise price may be subject to
adjustment upon the occurrence of events described in such
prospectus supplement. After the close of business on the
Expiration Date (or such later date to which we may extend such
Expiration Date), unexercised warrants will become void. The
place or places where, and the manner in which, warrants may be
exercised will be specified in the prospectus supplement
relating to such warrants.
Prior to the exercise of any warrants, holders of the warrants
will not have any of the rights of holders of common stock,
including the right to receive payments of any dividends on the
common stock purchasable upon exercise of the warrants, or to
exercise any applicable right to vote.
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Plan of
distribution
We may sell the offered securities in and outside the United
States (1) through underwriters or dealers,
(2) directly to purchasers, including our affiliates and
stockholders, (3) through agents or (4) through a
combination of any of these methods. The prospectus supplement
will include the following information:
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the terms of the offering;
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the names of any underwriters or agents;
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the name or names of any managing underwriter or underwriters;
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the purchase price of the securities;
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the estimated net proceeds to us from the sale of the securities;
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any delayed delivery arrangements;
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any underwriting discounts, commissions and other items
constituting underwriters compensation;
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any discounts or concessions allowed or reallowed or paid to
dealers; and
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any commissions paid to agents.
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Sale
through underwriters or dealers
If underwriters are used in the sale, the underwriters will
acquire the securities for their own account for resale to the
public, either on a firm commitment basis or a best efforts
basis. The underwriters may resell the securities from time to
time in one or more transactions, including negotiated
transactions, at a fixed public offering price or at varying
prices determined at the time of sale. Underwriters may offer
securities to the public either through underwriting syndicates
represented by one or more managing underwriters or directly by
one or more firms acting as underwriters. Unless we inform you
otherwise in the prospectus supplement, the obligations of the
underwriters to purchase the securities will be subject to
certain conditions. The underwriters may change from time to
time any offering price and any discounts or concessions allowed
or reallowed or paid to dealers.
During and after an offering through underwriters, the
underwriters may purchase and sell the securities in the open
market. These transactions may include overallotment and
stabilizing transactions and purchases to cover syndicate short
positions created in connection with the offering. The
underwriters may also impose a penalty bid, which means that
selling concessions allowed to syndicate members or other
broker-dealers for the offered securities sold for their account
may be reclaimed by the syndicate if the offered securities are
repurchased by the syndicate in stabilizing or covering
transactions. These activities may stabilize, maintain or
otherwise affect the market price of the offered securities,
which may be higher than the price that might otherwise prevail
in the open market. If commenced, the underwriters may
discontinue these activities at any time.
If dealers are used, we will sell the securities to them as
principals. The dealers may then resell those securities to the
public at varying prices determined by the dealers at the time
of resale. We will include in the prospectus supplement the
names of the dealers and the terms of the transaction.
Direct
sales and sales through agents
We may sell the securities directly. In this case, no
underwriters or agents would be involved. We may also sell the
securities through agents designated from time to time. In the
prospectus supplement, we will name any agent involved in the
offer or sale of the offered securities, and we will describe
any commissions payable to the agent. Unless we inform you
otherwise in the prospectus supplement, any agent will agree to
use its reasonable best efforts to solicit purchases for the
period of its appointment.
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We may sell the securities directly to institutional investors
or others who may be deemed to be underwriters within the
meaning of the Securities Act with respect to any sale of
securities. We will describe the terms of any such sales in the
prospectus supplement.
Remarketing
arrangements
Offered securities may also be offered and sold, if so indicated
in the applicable prospectus supplement, in connection with a
remarketing upon their purchase, in accordance with a redemption
or repayment pursuant to their terms, or otherwise, by one or
more remarketing firms, acting as principals for their own
accounts or as agents for us. Any remarketing firm will be
identified and the terms of its agreements, if any, with us and
its compensation will be described in the applicable prospectus
supplement. Remarketing firms may be deemed to be underwriters,
as that term is defined in the Securities Act, in connection
with the securities remarketed.
Delayed
delivery contracts
If we so indicate in the prospectus supplement, we may authorize
agents, underwriters or dealers to solicit offers from certain
types of institutions to purchase securities from us at the
public offering price under delayed delivery contracts. These
contracts would provide for payment and delivery on a specified
date in the future. The contracts would be subject only to those
conditions described in the prospectus supplement. The
prospectus supplement will describe the commission payable for
solicitation of those contracts.
General
information
We may have agreements with the agents, dealers, underwriters
and remarketing firms to indemnify them against certain civil
liabilities, including liabilities under the Securities Act, or
to contribute with respect to payments that the agents, dealers,
underwriters or remarketing firms may be required to make.
Agents, dealers, underwriters and remarketing firms may be
customers of, engage in transactions with, or perform services
for us in the ordinary course of their businesses.
Legal
matters
Certain legal matters in connection with the securities will be
passed upon by Vinson & Elkins L.L.P., Houston, Texas,
as our counsel. Any underwriter or agent will be advised about
other issues relating to any offering by its own legal counsel.
Experts
The (i) consolidated financial statements of Concho
Resources Inc. and subsidiaries incorporated in this prospectus
by reference to our Annual Report on
Form 10-K
for the year ended December 31, 2008, retrospectively
adjusted by our Current Report on
Form 8-K
filed on September 9, 2009 and (ii) managements
assessment of the effectiveness of internal control over
financial reporting incorporated in this prospectus by reference
to our Annual Report on
Form 10-K
for the year ended December 31, 2008 have been so
incorporated by reference in reliance upon the reports of Grant
Thornton LLP, independent registered public accountants, upon
the authority of said firm as experts in auditing and accounting
in giving said reports.
The special-purpose combined financial statements of the Henry
Group Properties as of December 31, 2007 and 2006, and for
each of the years in the three-year period ended
December 31, 2007 incorporated in this prospectus by
reference to the Current Reports on
Form 8-K
filed on August 6, 2008 and October 7, 2008 have been
so incorporated by reference in reliance upon the report of
Davis, Kinard & Co., P.C., independent registered
public accounting firm, upon the authority of said firm as
experts in accounting and auditing.
Certain estimates of our net crude oil and natural gas reserves
and related information included or incorporated by reference in
this prospectus have been derived from reports prepared by
Cawley, Gillespie & Associates, Inc. and Netherland,
Sewell & Associates, Inc. All such information has
been so included or incorporated by reference on the authority
of such firms as experts regarding the matters contained in
their reports.
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