form10k.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
x ANNUAL REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For
the fiscal year ended December 31, 2008
or
¨ TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the
transition period from __________ to _________
Commission
File Number 000-07246
PETROLEUM
DEVELOPMENT CORPORATION
(Exact
name of registrant as specified in its charter)
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Nevada
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95-2636730
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(State
of Incorporation)
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(I.R.S.
Employer Identification No.)
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120
Genesis Boulevard
Bridgeport,
West Virginia 26330
(Address
of principal executive offices) (Zip Code)
Registrant's
telephone number, including area code: (304) 842-3597
Securities
registered pursuant to Section 12(b) of the Act:
Title
of Each Class
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Name
of Each Exchange on Which Registered
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Common
Stock, par value $.01 per share
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NASDAQ
Global Select Market
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Securities
registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes ¨ No
x
Indicate
by check mark if registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes ¨ No
x
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes x No
¨
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this chapter) is not contained herein, and will not
be contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. ¨
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definitions of “large accelerated filer”, “accelerated
filer” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act.
Large
accelerated filer x
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Accelerated
filer ¨
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Non-accelerated
filer ¨
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Smaller
reporting company ¨
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(Do
not check if a smaller reporting
company)
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes ¨ No
x
The
aggregate market value of our common stock held by non-affiliates on June 30,
2008, was $965,929,153 (based on the then closing price of $66.49).
As of
February 23, 2009 there were 14,868,158 ares of our common stock
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
The
information required by Part III of this Form is incorporated by reference to
our definitive proxy statement to be filed pursuant to Regulation 14A for our
2009 Annual Meeting of Shareholders.
2008
ANNUAL REPORT ON FORM 10-K
TABLE
OF CONTENTS
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PART
I
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Page
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Item
1.
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1
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Item
1A.
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16
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Item
1B.
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25
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Item
2.
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26
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Item
3.
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26
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Item
4.
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26
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PART
II
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Item
5.
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26
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Item
6.
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29
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Item
7.
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30
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Item
7A.
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47
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Item
8.
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49
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Item
9.
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49
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Item
9A.
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49
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Item
9B.
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50
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PART
III
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Item
10.
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50
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Item
11.
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50
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Item
12.
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50
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Item
13.
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51
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Item
14.
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51
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PART
IV
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Item
15.
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51
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52
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53
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PART I
REFERENCES
TO THE REGISTRANT
Unless
the context otherwise requires, references to “PDC”, “the Company”, “we”, “us”,
“our”, “ours”, or “ourselves” in this report refer to the registrant, Petroleum
Development Corporation, together with its subsidiaries, proportionate share of
its sponsored drilling partnerships and an entity in which it has a controlling
interest.
GLOSSARY
OF OIL AND NATURAL GAS TERMS
Words
defined in the Glossary of Oil and Natural Gas Terms are set in boldface type
the first time they appear.
SPECIAL
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This
report contains forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934 regarding our business, financial condition, results of operations and
prospects. Words such as expects, anticipates, intends, plans,
believes, seeks, estimates and similar expressions or variations of such words
are intended to identify forward-looking statements herein, which include
statements of estimated oil
and natural gas production and reserves, drilling plans, future cash flows,
anticipated liquidity, anticipated capital expenditures and our management’s
strategies, plans and objectives. However, these are not the
exclusive means of identifying forward-looking statements
herein. Although forward-looking statements contained in this report
reflect our good faith judgment, such statements can only be based on facts and
factors currently known to us. Consequently, forward-looking
statements are inherently subject to risks and uncertainties, including risks
and uncertainties incidental to the exploration for, and the acquisition,
development, production and marketing of, natural gas and oil, and actual
outcomes may differ materially from the results and outcomes discussed in the
forward-looking statements. Important factors that could cause actual
results to differ materially from the forward looking statements include, but
are not limited to:
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changes
in production volumes, worldwide demand, and commodity prices for oil and
natural gas;
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the
timing and extent of our success in discovering, acquiring, developing and
producing natural gas and oil
reserves;
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our
ability to acquire leases, drilling rigs, supplies and services at
reasonable prices;
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the
availability and cost of capital to
us;
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risks
incident to the drilling and operation of natural gas and oil
wells;
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future
production and development costs;
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the
availability of sufficient pipeline and other transportation facilities to
carry our production and the impact of these facilities on
price;
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the
effect of existing and future laws, governmental regulations and the
political and economic climate of the United States of America
(“U.S.”);
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the
effect of natural gas and oil derivatives
activities;
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conditions
in the capital markets; and
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losses
possible from pending or future
litigation.
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Further,
we urge you to carefully review and consider the disclosures made in this
report, including the risks and uncertainties that may affect our business as
described herein under Item 1A, Risk Factors, and our other
filings with the Securities and Exchange Commission (“SEC”). We
caution you not to place undue reliance on forward-looking statements, which
speak only as of the date of this report. We undertake no
obligation to update any forward-looking statements in order to reflect any
event or circumstance occurring after the date of this report or currently
unknown facts or conditions or the occurrence of unanticipated
events.
General
We are an
independent energy company engaged in the exploration, development, production
and marketing of oil and natural gas. Since we began oil and natural
gas operations in 1969, we have grown through drilling and development
activities, acquisitions of producing natural gas and oil wells and the
expansion of our natural gas marketing activities.
As of
December 31, 2008, we owned interests in approximately 4,712 gross,
3,259 net,
wells located primarily in the Rocky Mountain Region and the Appalachian and
Michigan Basins with 753 billion cubic feet equivalent, or Bcfe,
of net proved
reserves, of which 88% was natural gas and 12% was oil.
During
2008, our production was 38.7 Bcfe, averaging 106.1 MMcfe
per day, a 38.5% increase over 76.6 MMcfe per day produced in
2007. We replaced our 2008 production with 106 Bcfe of new proved
reserves, net of dispositions, for a reserve
replacement rate of 274%. Reserve replacement through the
drillbit was 104 Bcfe, or 268% of production, and reserve replacement through
acquisitions was 2 Bcfe, or 6% of production. Proved reserves grew
9.8% during 2008, from 686 Bcfe to 753 Bcfe, of which 44% were proved
developed reserves.
We make available free of charge on our website at www.petd.com our annual
reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
8-K, and any amendments to these reports as soon as reasonably practicable after
we electronically file these reports with, or furnish them to, the
SEC. We will also make available to any shareholder, without charge,
a copy of our Annual Report on Form 10-K, or any other filing, as filed with the
SEC, by mail. For a mailed copy of a report, you may contact
Petroleum Development Corporation, Investor Relations, 1775 Sherman Street,
Suite 3000, Denver, CO 80203, or call toll free (800) 624-3821.
In addition to our SEC filings, other information, including our press
releases, Bylaws, Committee Charters, Code of Business Conduct and Ethics,
Shareholder Communication Policy, Director Nomination Procedures and the
Whistleblower Hotline, is also available on our website. However, the
information available on our website is not part of this report and is not
hereby incorporated by reference.
Business
Strategy
Our
primary objective is to continue to increase shareholder value through the
growth of our reserves, production, net income and cash flow. To
achieve meaningful increases in these key areas, we maintain an active drilling
program that focuses on low risk development of our oil and natural gas
reserves, limited exploratory drilling and the acquisition of producing
properties with significant development potential.
Drill
and Develop
Our acreage holdings include positions in the Rocky Mountain Region and the
Appalachian, Michigan and Fort Worth Basins. In the Rocky Mountain
Region, we focus on developmental drilling in Northeastern Colorado, or NECO,
the Wattenberg Field (both located in the DJ Basin), the Grand Valley Field,
Piceance Basin, and additional limited development in North
Dakota. We drilled 379 gross, 333.4 net, wells in 2008, compared to
349 gross, 276.3 net, wells in 2007. In addition, we seek to maximize
the value of our existing wells through a program of well recompletions
and refractures. During
2008, we recompleted and/or refraced a total of 125 wells compared to 181 in
2007. In 2009, with a limited inventory of available recompletion
opportunities, we plan to recomplete and/or refrac 40 wells in the Appalachian
Basin.
We
believe that we will be able to continue to drill a substantial number of new
wells on our current undeveloped properties. As of December 31, 2008,
we had leases or other development rights to approximately 224,800 undeveloped
acres, of which approximately 188,000 acres, or 83.5%, were in the Rocky
Mountain Region. We plan to drill approximately 166 gross, 144.1 net,
wells in 2009, excluding exploratory
wells. To support future development activities, we have
conducted exploratory drilling in the past and plan to drill seven wells in
2009, primarily in the Appalachian Basin. The goal of the exploration
program is to develop new areas for us to include in our future development
drilling activity.
Strategically
Acquire
Our acquisition efforts focus on producing properties that have a significant
undeveloped acreage component. When weighing potential acquisitions,
we prefer properties that have most of their value in producing wells, behind
the pipe reserves or high quality proved undeveloped
locations. Historically, acquisitions have offered efficiency
improvements through economies of scale in management and administration
costs. During the period December 2006 through October 2007, we
completed three acquisitions of assets or companies in our core operating area
of the Wattenberg Field in Colorado and acquired assets in southwestern
Pennsylvania within close proximity to our existing assets in the Appalachian
Basin. We had no significant acquisitions of properties in
2008. We expect to continue to evaluate acquisition
opportunities. See Note 14, Acquisitions, to our
accompanying consolidated financial statements included in this
report.
Manage
Risk
We seek opportunities to reduce the risk inherent to our business in the oil and
natural gas industry by focusing our drilling efforts primarily on lower risk
development
wells and by maintaining positions in several different geographic
regions and markets. Historically, we have concentrated on
development drilling and geographical diversification to reduce risk levels
associated with natural gas and oil drilling, production and
markets. Currently, a majority of our proved reserves are located in
the Rocky Mountain Region due to our success in that area over the past several
years. However, we benefit from operational diversity in the Rocky
Mountain Region by maintaining significant activity and production in three
separate areas, including the Grand Valley Field of the Piceance Basin in
western Colorado, the Wattenberg Field in north central Colorado and the NECO
area. Additionally, we regularly review opportunities to further
diversify into other regions where we can apply our operational
expertise. We believe development drilling will remain the foundation
of our drilling activities in the future because it is less risky than
exploratory drilling and is likely to generate cash returns more
quickly. We expect that future activities may include some level of
exploratory drilling when the economic environment and commodity price models
justify such risks. We view exploratory activities as having the
potential to identify new development opportunities at a cost competitive to the
current cost of acquiring proven locations.
To help
manage the risks associated with the oil and natural gas industry, we maintain a
conservative financial approach and proactively employ strategies to reduce the
effects of commodity price volatility. We also believe that
successful oil and natural gas marketing is essential to risk management and
profitable operations. To further this goal, we utilize Riley Natural
Gas, or RNG, a wholly-owned subsidiary, to manage the marketing of our oil and
natural gas and our use of oil and natural gas commodity derivatives as risk
management tools. This allows us to maintain better control over
third party risk in sales and derivative activities. We use oil and
natural gas derivatives contracts primarily to reduce the effects of volatile
commodity prices. We currently have derivative contracts in place on
a significant portion of our production; however, pursuant to our derivative
policy, all volumes for derivatives contracts are limited to 80% of our future
production from producing wells at the time we enter into the derivative
contracts, with the exception of put contracts for which volumes are not
limited. As of December 31, 2008, we had oil and natural gas hedges
in place covering 52% of our expected oil production and 62% of our expected
natural gas production in 2009. Further, while our derivative
instruments are utilized to manage the impact of price volatility of our oil and
natural gas production, they do not qualify for use of hedge accounting under
the terms of SFAS No. 133, requiring us to recognize changes in the fair value
of our derivative positions in earnings each reporting period and, therefore,
resulting in the potential for significant earnings volatility. See
Note 1, Summary of Significant Accounting
Polices – Derivative Financial Instruments, to our accompanying
consolidated financial statements included in this report.
Business
Segments
We divide
our operating activities into four segments:
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·
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natural
gas marketing activities;
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·
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well
operations and pipeline income; and
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·
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oil
and gas well drilling operations.
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See Note 16, Business Segments, to our
accompanying consolidated financial statements included in this
report.
Oil
and Gas Sales
Our oil
and gas sales segment is our largest business segment based on
revenue. This segment reflects revenues and expenses from production
and sale of oil and natural gas. During 2008, approximately 84.8% of
our oil and gas sales revenue was generated by the Rocky Mountain Region, 10.9%
by the Appalachian Basin and 4.3% by the Michigan Basin. As of the
end of 2008, our total proved reserves were located as follows: Rocky Mountain
Region 82%, Appalachian Basin 15% and Michigan 3%. The majority of
our undeveloped
acreage is in the Rocky Mountain Region, where we focused our 2008
drilling activities. This segment represents approximately 133% of
our income before income taxes for the year ended December 31,
2008.
Natural
Gas Marketing Activities
Our natural gas marketing activities segment is comprised of our wholly-owned
subsidiary, RNG, through which we purchase, aggregate and resell natural gas
produced by us and others. This allows us to diversify our operations
beyond natural gas drilling and production. Through RNG, we have
established relationships with many of the natural gas producers in the
Appalachian Basin and we have gained significant expertise in the natural gas
end-user market. We do not take speculative positions on commodity
prices, and we employ derivative strategies to manage the financial effects of
commodity price volatility. Our natural gas marketing segment
represented approximately 1% of our income before income taxes for the year
ended December 31, 2008.
Well
Operations and Pipeline Income
We operate approximately 95.5% of the wells in which we own a working
interest. With respect to wells in which we own an interest of
less than 100%, we charge the other working interest owners, including our
drilling partnerships, a competitive fee for operating the well and transporting
natural gas. Our well operations and pipeline income segment
represented approximately 2% of our income before income taxes for the year
ended December 31, 2008.
Oil
and Gas Well Drilling Operations
Our drilling and development segment reflects results of drilling and
development activities conducted for affiliated and non-affiliated
parties. Historically, we have engaged in these activities primarily
through sponsoring drilling partnerships, which allowed us to share the risks
and costs inherent in drilling and development operations with our investor
partners. Beginning with our third sponsored drilling partnership in
2005, we have drilled partnership wells on a “cost-plus” basis, which means that
we bill our investor partners for the actual drilling costs plus a fixed
drilling fee. Prior to our cost-plus drilling arrangements, drilling
was conducted on a “footage” basis, where the Company bore the risk of changes
in costs. In addition, we have typically purchased a 20% to 37%
working interest in the wells developed through these
partnerships. In September 2006, we raised approximately $90 million
through investor subscriptions in one drilling partnership, and in August 2007,
we raised approximately $90 million through an additional drilling
partnership.
Our oil and gas well drilling segment represented approximately 3% of our income
before income taxes for the year ended December 31, 2008. In January
2008, we announced that we did not plan to sponsor new drilling partnerships in
2008. However, a portion of the funds available for drilling from the
2007 partnership were advanced and unexpended at the end of
2007. The majority of these funds were used in 2008 for
drilling and completion
activities, a portion of which was recognized as income in 2008. The
funds remaining as of December 31, 2008, will be used for completion activities
to be conducted in 2009. Currently, we do not plan to sponsor a
drilling partnership in 2009 and anticipate that our oil and gas well drilling
segment’s contribution to operating income will decline significantly in
2009.
Areas
of Operations
We focus our exploration, development and production efforts in three primary
geographic regions:
During 2008, we generated approximately 85.6% of our production from Rocky
Mountain Region wells, 10.2% of our production from Appalachian Basin wells and
4.2% of our production from Michigan Basin wells. The majority of our
undeveloped acreage is in the Rocky Mountain Region and our current drilling
plans continue to be focused predominantly in this area.
Rocky Mountain Region. In 1999, we began operations in the
Rocky Mountain Region. Our Rocky Mountain Region is divided into four
operating areas: (1) Grand Valley Field, (2) Wattenberg Field, (3) NECO area and
(4) North Dakota area. Our Rocky Mountain Region includes
approximately 320,000 gross acres of leasehold and 2,408 gross, 1,542 net, oil
and natural gas wells in which we own an interest. The general
details of each area within the region are further outlined below:
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Grand
Valley Field, Piceance Basin, Garfield County,
Colorado. We commenced operations in the area in late
1999 and currently own an interest in 285 gross, 158.3 net, natural gas
wells. Our leasehold position encompasses approximately 7,900
gross acres with approximately 5,200 net undeveloped acres remaining for
development as of December 31, 2008. We drilled 62 gross, 54.4
net, wells in the area in 2008 and produced approximately 12.5 Bcfe net to
our interests. Development wells drilled in the area range from
7,000 to 9,500 feet in depth and the majority of wells are drilled
directionally from multi-well pads ranging from two to eight or more wells
per drilling pad. The primary target in the area is gas
reserves, developed from multiple sandstone reservoirs in the Mesaverde
Williams Fork formation. Well spacing is approximately ten
acres per well.
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Wattenberg
Field, DJ Basin, Weld and Adams Counties, Colorado. We
commenced operations in the area in late 1999 and currently own an
interest in 1,390 gross, 875.2 net, oil and natural gas
wells. Our leasehold position encompasses approximately 75,900
gross acres with approximately 24,000 net undeveloped acres remaining for
development as of December 31, 2008. We drilled 149 gross,
122.7 net, wells in the area in 2008 and produced approximately 15.4 Bcfe
net to our interests. Wells drilled in the area range from
approximately 7,000 to 8,000 feet in depth and generally target oil and
gas reserves in the Niobrara, Codell and J Sand
reservoirs. Well spacing ranges from 20 to 40 acres per
well. Operations in the area, in addition to the drilling of
new development wells, include the refrac of Codell and Niobrara
reservoirs in existing wellbores whereby the Codell sandstone reservoir is
fraced a second time and/or initial completion
attempts are made in the slightly shallower Niobrara carbonate
reservoir.
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NECO area.
DJ Basin, Yuma County Colorado and Cheyenne County,
Kansas. We commenced operations in the area in 2003 and
currently own an interest in 717 gross, 504 net, natural gas
wells. Our leasehold position encompasses approximately 141,600
gross acres with approximately 93,200 net undeveloped acres remaining for
development as of December 31, 2008. We drilled 98 gross, 88.1
net, wells in the area in 2008 and produced approximately 5 Bcfe net to
our interests. Wells drilled in the area range from
approximately 1,500 to 3,000 feet in depth and target gas reserves in the
shallow Niobrara reservoir. Well spacing is approximately 40
acres per well. New drilling operations range from exploratory
wells to test undrilled, seismically defined, structural features at the
Niobrara horizon to development wells targeting known reserves in existing
identified features.
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North
Dakota, Burke County. We commenced operations in the
area in 2006 and currently own an interest in 13 gross, 3.7 net, oil and
natural gas wells. We divested the majority of our Bakken
project acreage in late 2007 (See Note 13, Sale of Oil and Gas
Properties, to our accompanying consolidated financial statements
included in this report). Our remaining leasehold encompasses
two project areas in Burke County and encompasses approximately 75,100
gross acres with approximately 46,300 net undeveloped acres remaining for
development as of December 31, 2008. The eastern area acreage
is prospective for development of oil and gas reserves in the Nesson
Formation. Nesson development wells are approximately 6,000
feet in depth with single or multiple horizontal legs to 4,000 feet or
more in length for a measured length of 10,000 feet or more per
leg. The westernmost acreage block is undeveloped and includes
approximately 23,600 gross, 16,200 net acres. The western
project targets exploratory horizontal
drilling to the Midale/Nesson Formation at depths of approximately
6,800 feet with a lateral leg component of up to 6,100 feet. In
2009, we plan to drill up to four exploratory wells on our acreage with
funding from an unrelated third party in exchange for an interest
in our acreage position.
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Appalachian Basin. We have conducted operations in the
Appalachian Basin since 1969. Our leasehold position encompasses
approximately 140,300 gross acres with approximately 19,400 net undeveloped
acres remaining for development as of December 31, 2008. We own an
interest in approximately 2,090 gross, 1,566.5 net, oil and natural gas wells in
West Virginia, Pennsylvania and Tennessee. We drilled 63 gross/net
wells in the area in 2008 and produced
approximately 3.9 Bcfe net to our interests. The majority of our
Appalachian leasehold is developed on approximately 40 acre
spacing. Wells located in this area are approximately 4,500 feet deep
and target predominantly gas reserves in Devonian and Mississippian aged tight
sandstone reservoirs. We are currently
evaluating the potential of the Marcellus Formation in West Virginia and
Pennsylvania and have drilled three tests to date in West Virginia, two of which
are in line.
Michigan Basin. We began
operations in the Michigan Basin in 1997 with the bulk of drilling activity
occurring prior to 2002. We own an interest in approximately 210
gross, 146.5 net, oil and natural gas wells that produced 1.6 Bcfe net to our
interest in 2008. Wells in the area range from 1,000 to 2,500 feet in
depth and produce gas from the Antrim Shale. We drilled 2 gross, 1.6
net, exploratory wells in 2008.
Fort
Worth Basin. In addition to those operating areas above, we
have an interest in approximately 12,500 gross, 9,100 net undeveloped acres, in
Fort Worth Basin, northeastern Erath County, Texas. The leasehold
acreage is prospective for the development of oil and natural gas reserves in
the Barnett Shale formation at depths of approximately 5,000
feet. Development is typically with a horizontal component of
approximately 3,000 feet or more, resulting in an approximate measured length of
up to 8,000 feet or more in this area. In 2008, we commenced drilling
operations and drilled three exploratory Barnett wells. These wells
generated less than 1% of our 2008 production. Based on these
results, we recorded impairments of both proved and unproved properties in this
area in 2008. We are currently evaluating our future plans in this
area and currently have no drilling activity planned in 2009.
The table below sets forth our productive wells by operating area at December
31, 2008.
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Productive
Wells
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Gas
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Oil
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Total
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Location
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Appalachian
Basin
|
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2,051 |
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1,551.0 |
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39 |
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15.4 |
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2,090 |
|
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|
1,566.4 |
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Michigan
Basin
|
|
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203 |
|
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143.8 |
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|
|
7 |
|
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2.7 |
|
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210 |
|
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146.5 |
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Rocky
Mountain Region
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|
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Wattenberg
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1,365 |
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856.0 |
|
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25 |
|
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19.3 |
|
|
|
1,390 |
|
|
|
875.3 |
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Grand
Valley
|
|
|
285 |
|
|
|
158.3 |
|
|
|
- |
|
|
|
- |
|
|
|
285 |
|
|
|
158.3 |
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NECO
Area
|
|
|
717 |
|
|
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504.0 |
|
|
|
- |
|
|
|
- |
|
|
|
717 |
|
|
|
504.0 |
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North
Dakota
|
|
|
4 |
|
|
|
0.4 |
|
|
|
9 |
|
|
|
3.3 |
|
|
|
13 |
|
|
|
3.7 |
|
Wyoming
|
|
|
- |
|
|
|
- |
|
|
|
3 |
|
|
|
0.7 |
|
|
|
3 |
|
|
|
0.7 |
|
Total
Rocky Mountain Region
|
|
|
2,371 |
|
|
|
1,518.7 |
|
|
|
37 |
|
|
|
23.3 |
|
|
|
2,408 |
|
|
|
1,542.0 |
|
Fort
Worth Basin
|
|
|
4 |
|
|
|
4.0 |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
4.0 |
|
Total
Productive Wells
|
|
|
4,629 |
|
|
|
3,217.5 |
|
|
|
83 |
|
|
|
41.4 |
|
|
|
4,712 |
|
|
|
3,258.9 |
|
Operations
Prospect
Generation
Our staff of professional geologists is responsible for identifying areas with
potential for economic production of natural gas and oil. They
utilize results from logs, seismic data and other tools to evaluate existing
wells and to predict the location of economically attractive new natural gas and
oil reserves. To further this process, we have collected and continue
to collect logs, core data, production information and other raw data available
from state and private agencies, other companies and individuals actively
drilling in the regions being evaluated. From this information, the
geologists develop models of the subsurface structures and formations that are
used to predict areas for prospective economic development.
On the basis of these models, our land department obtains available natural gas
and oil leaseholds, farmouts and other development rights in these prospective
areas. In most cases, to secure a lease, we pay a lease bonus and
annual rental payments, converting, upon initiation of production, to a royalty. In
addition, overriding royalty payments may be granted to third parties in
conjunction with the acquisition of drilling rights initially leased by
others. As of December 31, 2008, we had leasehold rights to
approximately 224,800 acres available for development.
Drilling
Activities
The following table summarizes our development and exploratory drilling activity
for the last three years. There is no correlation between the number
of productive wells completed during any period and the aggregate reserves
attributable to those wells. Productive wells consist of producing
wells and wells capable of commercial production.
|
|
Drilling
Activity
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
(1)
|
|
|
349 |
|
|
|
303.8 |
|
|
|
327 |
|
|
|
258.9 |
|
|
|
216 |
|
|
|
129.8 |
|
Dry
|
|
|
8 |
|
|
|
8.0 |
|
|
|
11 |
|
|
|
9.7 |
|
|
|
6 |
|
|
|
4.6 |
|
Total
development
|
|
|
357 |
|
|
|
311.8 |
|
|
|
338 |
|
|
|
268.6 |
|
|
|
222 |
|
|
|
134.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
(1)
|
|
|
7 |
|
|
|
7.0 |
|
|
|
1 |
|
|
|
0.2 |
|
|
|
8 |
|
|
|
2.8 |
|
Dry
|
|
|
10 |
|
|
|
9.6 |
|
|
|
7 |
|
|
|
4.5 |
|
|
|
1 |
|
|
|
0.5 |
|
Pending
determination
|
|
|
5 |
|
|
|
5.0 |
|
|
|
3 |
|
|
|
3.0 |
|
|
|
- |
|
|
|
- |
|
Total
exploratory
|
|
|
22 |
|
|
|
21.6 |
|
|
|
11 |
|
|
|
7.7 |
|
|
|
9 |
|
|
|
3.3 |
|
Total
Drilling Activity
|
|
|
379 |
|
|
|
333.4 |
|
|
|
349 |
|
|
|
276.3 |
|
|
|
231 |
|
|
|
137.7 |
|
______________
(1)
As
of December 31, 2008, 94 of the 356 productive wells were awaiting gas pipeline
connection, of which 38 were connected and turned in line by February 13,
2009.
The following table sets forth the wells we drilled by operating area during the
periods indicated.
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Appalachian
Basin
|
|
|
63 |
|
|
|
63.0 |
|
|
|
8 |
|
|
|
8.0 |
|
|
|
- |
|
|
|
- |
|
Michigan
Basin
|
|
|
2 |
|
|
|
1.6 |
|
|
|
3 |
|
|
|
3.0 |
|
|
|
1 |
|
|
|
1.0 |
|
Rocky
Mountain Region
|
|
|
311 |
|
|
|
265.8 |
|
|
|
337 |
|
|
|
264.3 |
|
|
|
230 |
|
|
|
136.7 |
|
Fort
Worth Basin
|
|
|
3 |
|
|
|
3.0 |
|
|
|
1 |
|
|
|
1.0 |
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
379 |
|
|
|
333.4 |
|
|
|
349 |
|
|
|
276.3 |
|
|
|
231 |
|
|
|
137.7 |
|
We plan to drill approximately 166 gross wells, excluding exploratory wells, in
2009: 12 in the Appalachian Basin and 154 in the Rocky Mountain
Region.
Much of the work associated with drilling, completing and connecting wells,
including drilling, fracturing, logging and pipeline construction is performed
under our direction by subcontractors specializing in those operations, as is
common in the industry. When judged advantageous, material and
services we use in the development process are acquired through competitive
bidding by approved vendors. We also directly negotiate rates and
costs for services and supplies when conditions indicate that such an approach
is warranted.
Financing
of Company Drilling and Development Activities
We
conduct development drilling activities for our own account and act
as operator for other
oil and gas owners. When conducting activities for our own account,
we have historically funded our operations through our cash flows from
operations, capital provided from our long term credit facility and, in 2008, from our senior notes
issuance. In the future, we expect to continue to use these same
sources, but may also use other sources of funding, including, but not limited
to, asset sales, volumetric production payments, debt securities, convertible
debt securities and equity offerings.
Drilling
and Development Activities Conducted for Company Sponsored
Partnerships
We began
sponsoring drilling partnerships in 1984, and had sponsored one or more every
year through 2007. For many years, our drilling partners were
primarily the public and private partnerships we sponsored. At
closing, we contribute a cash investment to purchase an interest in the drilling
and development activities of the partnership and then serve as the managing
general partner. As wells produce for a number of years, we continue
to serve as operator for 33 partnerships, as well as for other unaffiliated
parties.
When developing wells for our partnerships or others, we enter into a
development agreement with the investor partner, pursuant to which we agree to
sell some or all of our rights in a well to be drilled to the partnership or
other entity. The partnership or other entity thereby becomes owner
of a working interest in the well. In our financial reporting, we
report only our proportionate share of oil and gas reserves, production, oil and
gas sales and costs associated with wells in which other investors
participate.
In January 2008, we announced that we did not plan to sponsor new drilling
partnerships in 2008 in order to focus our effort on continuing our growth
through drilling and exploration. Currently, we have no plans to
sponsor a partnership in 2009.
Purchases
of Producing Properties
In addition to drilling new wells, we continue to pursue opportunities to
purchase existing wells and development rights from other owners, as well as
greater ownership interests in the wells we operate. Generally,
outside interests purchased include a majority interest in the wells and the
right to operate the wells. In January 2007, we completed the
purchase from an unrelated party of approximately 144 oil and gas wells and
8,160 acres of leaseholds in the Wattenberg Field. Also in January
2007, we purchased the outside partnership interests in 44 partnerships which we
sponsored and formed primarily in the late 1980s and 1990s. These
interests constituted the majority of the interests in 718 wells, primarily in
the Appalachian and Michigan Basins. In February 2007, we acquired
from an unrelated party 28 producing wells and associated undeveloped acreage in
Colorado. In October 2007, we purchased from unrelated parties a
majority working interest of 762 natural gas wells located in southwestern
Pennsylvania. The purchase also included associated pipelines,
equipment, real estate and undeveloped acreage. No significant
acquisitions were made in 2008.
Production, Sales, Prices and Lifting
Costs
The following table sets forth information regarding our production volumes, oil
and natural gas sales, average sales price received and average lifting cost
incurred for the periods indicated.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Production (1)
|
|
|
|
|
|
|
|
|
|
Oil
(Bbls)
|
|
|
1,160,408 |
|
|
|
910,052 |
|
|
|
631,395 |
|
Natural
gas (Mcf)
|
|
|
31,759,792 |
|
|
|
22,513,306 |
|
|
|
13,160,784 |
|
Natural
gas equivalent (Mcfe) (2)
|
|
|
38,722,240 |
|
|
|
27,973,618 |
|
|
|
16,949,154 |
|
Oil and Gas Sales (in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
sales
|
|
$ |
104,168 |
|
|
$ |
55,196 |
|
|
$ |
37,460 |
|
Gas
sales
|
|
|
221,734 |
|
|
|
119,991 |
|
|
|
77,729 |
|
Royalty
litigation provision
|
|
|
(4,025 |
) |
|
|
- |
|
|
|
- |
|
Total
oil and gas sales
|
|
$ |
321,877 |
|
|
$ |
175,187 |
|
|
$ |
115,189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gain (Loss) on
Derivatives, net (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
derivatives - realized loss
|
|
$ |
(3,145 |
) |
|
$ |
(177 |
) |
|
$ |
- |
|
Natural
gas derivatives - realized gain
|
|
|
12,632 |
|
|
|
7,350 |
|
|
|
1,895 |
|
Total
realized gain on derivatives, net
|
|
$ |
9,487 |
|
|
$ |
7,173 |
|
|
$ |
1,895 |
|
Average
Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl) (3)
|
|
$ |
89.77 |
|
|
$ |
60.65 |
|
|
$ |
59.33 |
|
Natural
gas (per Mcf) (3)
|
|
$ |
6.98 |
|
|
$ |
5.33 |
|
|
$ |
5.91 |
|
Natural
gas equivalent (per Mcfe)
|
|
$ |
8.42 |
|
|
$ |
6.26 |
|
|
$ |
6.80 |
|
Average
Sales Price (including realized gain (loss) on
derivatives)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
87.06 |
|
|
$ |
60.46 |
|
|
$ |
59.33 |
|
Natural
gas (per Mcf)
|
|
$ |
7.38 |
|
|
$ |
5.66 |
|
|
$ |
6.05 |
|
Natural
gas equivalent (per Mcfe)
|
|
$ |
8.66 |
|
|
$ |
6.52 |
|
|
$ |
6.91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Production Cost (Lifting Cost) per Mcfe (4)
|
|
$ |
1.07 |
|
|
$ |
0.90 |
|
|
$ |
0.76 |
|
_____________
|
(1)
|
Production
is net and determined by multiplying the gross production volume of
properties in which we have an interest by the percentage of the leasehold
or other property interest we own.
|
|
(2)
|
A ratio of energy content of
natural gas and oil (six Mcf of natural gas equals one
Bbl of oil) was used to obtain a
conversion factor to convert oil production into equivalent Mcf of natural
gas.
|
|
(3)
|
We
utilize commodity based derivative instruments to manage a portion of our
exposure to price volatility of our natural gas and oil
sales. This amount excludes realized and unrealized gains and
losses on commodity based derivative
instruments.
|
|
(4)
|
Production
costs represent oil and natural gas operating expenses which exclude
production taxes.
|
Oil
and Natural Gas Reserves
All of our natural gas and oil reserves are located in the U.S. We
utilized the services of independent petroleum engineers to estimate our oil and
gas reserves. For the years ended December 31, 2008 and 2007, our
reserve estimates for the Appalachian and Michigan Basins are based on reserve
reports prepared by Wright & Company and for the Rocky Mountain Region,
reserve estimates are based on reserve reports prepared by Ryder Scott Company,
L.P. For the year ended December 31, 2006, our reserve estimates for
the Appalachian and Michigan Basins and NECO Area were based on reserve reports
prepared by Wright & Company and our reserve estimates for the Rocky
Mountain Region, with the exception of the NECO properties, were based on
reserve reports prepared by Ryder Scott. The independent engineers'
estimates are made using available geological and reservoir data as well as
production performance data. The estimates are prepared with respect
to reserve categorization, using the definitions for proved reserves set forth
in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and
guidance. When preparing our reserve estimates, the independent
engineers did not independently verify the accuracy and completeness of
information and data furnished by us with respect to ownership interests, oil
and natural gas production, well test data, historical costs of operations and
developments, product prices, or any agreements relating to current and future
operations of properties and sales of production. Our independent
reserve estimates are reviewed and approved by our internal engineering staff
and management.
The tables below set forth information regarding our estimated proved
reserves. Reserves cannot be measured exactly, because reserve
estimates involve subjective judgments. The estimates must be
reviewed periodically and adjusted to reflect additional information gained from
reservoir performance, new geological and geophysical data and economic
changes. Neither the present value of estimated future net cash flows
nor the standardized measure is intended to represent the current market value
of the estimated oil and natural gas reserves we own.
|
|
Proved
Reserves as of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Oil
(MBbl)
|
|
|
15,037 |
|
|
|
15,338 |
|
|
|
7,272 |
|
Natural
gas (MMcf)
|
|
|
662,857 |
|
|
|
593,563 |
|
|
|
279,078 |
|
Total
proved reserves (MMcfe)
|
|
|
753,079 |
|
|
|
685,591 |
|
|
|
322,710 |
|
Proved
developed reserves (MMcfe)
|
|
|
329,669 |
|
|
|
317,884 |
|
|
|
165,690 |
|
Estimated
future net cash flows (in
thousands) (1)
|
|
$ |
1,056,890 |
|
|
$ |
1,847,485 |
|
|
$ |
525,454 |
|
Standardized
measure (in thousands) (1)(2)
|
|
$ |
356,805 |
|
|
$ |
753,071 |
|
|
$ |
215,662 |
|
______________
|
(1)
|
Estimated
future net cash flow represents the estimated future gross revenue to be
generated from the production of proved reserves, net of estimated
production costs, future development costs and income tax expense, using
prices and costs in effect at December 31for each respective
year. For the weighted average wellhead prices used in our
reserve reports, see Note 18,
“Supplemental Oil and Gas Information,” of our consolidated financial
statements included in this report. These prices should not be
interpreted as a prediction of future prices, nor do they reflect the
value of our commodity hedges in place at December 31for each respective
year. The amounts shown do not give effect to non-property
related expenses, such as corporate general and administrative expenses
and debt service, or to depreciation, depletion and
amortization.
|
|
(2)
|
The
standardized
measure of discounted future net cash flow is calculated in
accordance with Statement of Financial Accounting Standards (“SFAS”) No.
69, which requires the future cash flows to be discounted. The
discount rate used was 10%. Additional information on this
measure, including a description of changes in this measure from year to
year, is presented in Note 18,
“Supplemental Oil and Gas Information,” of our consolidated financial
statements included in this report.
|
|
|
Proved
Reserves as of
|
|
|
|
December 31,
2008
|
|
|
|
Oil
(MBbl)
|
|
|
Gas
(MMcf)
|
|
|
Gas
Equivalent
(MMcfe)
|
|
|
Percent
|
|
Proved
developed
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
29 |
|
|
|
73,447 |
|
|
|
73,621 |
|
|
|
22 |
% |
Michigan
Basin
|
|
|
40 |
|
|
|
19,784 |
|
|
|
20,024 |
|
|
|
6 |
% |
Rocky
Mountain Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
|
|
|
5,079 |
|
|
|
50,005 |
|
|
|
80,479 |
|
|
|
25 |
% |
Grand
Valley
|
|
|
173 |
|
|
|
111,310 |
|
|
|
112,348 |
|
|
|
34 |
% |
NECO
|
|
|
- |
|
|
|
42,042 |
|
|
|
42,042 |
|
|
|
13 |
% |
North
Dakota
|
|
|
105 |
|
|
|
114 |
|
|
|
744 |
|
|
|
0 |
% |
Wyoming
|
|
|
8 |
|
|
|
- |
|
|
|
48 |
|
|
|
0 |
% |
Total
Rocky Mountain Region
|
|
|
5,365 |
|
|
|
203,471 |
|
|
|
235,661 |
|
|
|
72 |
% |
Fort
Worth Basin
|
|
|
4 |
|
|
|
339 |
|
|
|
363 |
|
|
|
0 |
% |
Total
proved developed
|
|
|
5,438 |
|
|
|
297,041 |
|
|
|
329,669 |
|
|
|
100 |
% |
Proved
undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
- |
|
|
|
39,380 |
|
|
|
39,380 |
|
|
|
9 |
% |
Rocky
Mountain Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
|
|
|
9,340 |
|
|
|
62,284 |
|
|
|
118,324 |
|
|
|
28 |
% |
Grand
Valley
|
|
|
259 |
|
|
|
258,824 |
|
|
|
260,378 |
|
|
|
62 |
% |
NECO
|
|
|
- |
|
|
|
5,328 |
|
|
|
5,328 |
|
|
|
1 |
% |
Total
Rocky Mountain Region
|
|
|
9,599 |
|
|
|
326,436 |
|
|
|
384,030 |
|
|
|
91 |
% |
Total
proved undeveloped
|
|
|
9,599 |
|
|
|
365,816 |
|
|
|
423,410 |
|
|
|
100 |
% |
Proved
reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
29 |
|
|
|
112,827 |
|
|
|
113,001 |
|
|
|
15 |
% |
Michigan
|
|
|
40 |
|
|
|
19,784 |
|
|
|
20,024 |
|
|
|
3 |
% |
Rocky
Mountain Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
|
|
|
14,419 |
|
|
|
112,289 |
|
|
|
198,803 |
|
|
|
27 |
% |
Grand
Valley
|
|
|
432 |
|
|
|
370,134 |
|
|
|
372,726 |
|
|
|
49 |
% |
NECO
|
|
|
- |
|
|
|
47,370 |
|
|
|
47,370 |
|
|
|
6 |
% |
North
Dakota
|
|
|
105 |
|
|
|
114 |
|
|
|
744 |
|
|
|
0 |
% |
Wyoming
|
|
|
8 |
|
|
|
- |
|
|
|
48 |
|
|
|
0 |
% |
Total
Rocky Mountain Region
|
|
|
14,964 |
|
|
|
529,907 |
|
|
|
619,691 |
|
|
|
82 |
% |
Fort
Worth Basin
|
|
|
4 |
|
|
|
339 |
|
|
|
363 |
|
|
|
0 |
% |
Total
proved reserves
|
|
|
15,037 |
|
|
|
662,857 |
|
|
|
753,079 |
|
|
|
100 |
% |
Acreage
The following table sets forth by operating area leased acres as of December 31,
2008.
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
Location
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
117,800 |
|
|
|
113,000 |
|
|
|
22,500 |
|
|
|
19,400 |
|
|
|
140,300 |
|
|
|
132,400 |
|
Michigan
Basin
|
|
|
16,800 |
|
|
|
14,800 |
|
|
|
10,000 |
|
|
|
8,400 |
|
|
|
26,800 |
|
|
|
23,200 |
|
Rocky
Mountain Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
|
|
|
45,800 |
|
|
|
43,400 |
|
|
|
30,100 |
|
|
|
24,000 |
|
|
|
75,900 |
|
|
|
67,400 |
|
Grand
Valley
|
|
|
2,700 |
|
|
|
2,700 |
|
|
|
5,200 |
|
|
|
5,200 |
|
|
|
7,900 |
|
|
|
7,900 |
|
NECO
|
|
|
23,200 |
|
|
|
19,300 |
|
|
|
118,400 |
|
|
|
93,200 |
|
|
|
141,600 |
|
|
|
112,500 |
|
North
Dakota
|
|
|
8,300 |
|
|
|
4,800 |
|
|
|
66,800 |
|
|
|
46,300 |
|
|
|
75,100 |
|
|
|
51,100 |
|
Wyoming
|
|
|
300 |
|
|
|
100 |
|
|
|
19,200 |
|
|
|
19,200 |
|
|
|
19,500 |
|
|
|
19,300 |
|
Total
Rocky Mountain Region
|
|
|
80,300 |
|
|
|
70,300 |
|
|
|
239,700 |
|
|
|
187,900 |
|
|
|
320,000 |
|
|
|
258,200 |
|
Fort
Worth Basin
|
|
|
400 |
|
|
|
400 |
|
|
|
12,100 |
|
|
|
9,100 |
|
|
|
12,500 |
|
|
|
9,500 |
|
Total
Acreage
|
|
|
215,300 |
|
|
|
198,500 |
|
|
|
284,300 |
|
|
|
224,800 |
|
|
|
499,600 |
|
|
|
423,300 |
|
Title
to Properties
We
believe that we hold good and defensible title to our developed properties, in
accordance with standards generally accepted in the oil and natural gas
industry. As is customary in the industry, a preliminary title
examination is conducted at the time the undeveloped properties are
acquired. Prior to the commencement of drilling operations, a title
examination is conducted and curative work is performed with respect to
discovered defects which we deem to be significant. Title
examinations have been performed with respect to substantially all of our
producing properties. Two properties in our Grand Valley Field
represent 49% of our total proved reserves.
The
properties we own are subject to royalty, overriding royalty and other
outstanding interests customary to the industry. The properties may
also be subject to additional burdens, liens or encumbrances customary to the
industry, including items such as operating agreements, current taxes,
development obligations under natural gas and oil leases, farm-out agreements
and other restrictions. We do not believe that any of these burdens
will materially interfere with the use of the properties.
Natural
Gas Sales
We
generally sell the natural gas that we produce under contracts with indexed
monthly pricing provisions. Virtually all of our contracts include
provisions wherein prices change monthly with changes in the market, for which
certain adjustments may be made based on whether a well delivers to a gathering
or transmission line, quality of natural gas and prevailing supply and demand
conditions, so that the price of the natural gas fluctuates to remain
competitive with other available natural gas supplies. As a result,
our revenues from the sale of natural gas will suffer if market prices decline
and benefit if they increase. We believe that the pricing provisions
of our natural gas contracts are customary in the industry. We also
enter into financial derivatives such as puts, collars and swaps in order to
reduce the impact of possible price instability regarding the physical sales
market. See Item 7, Management’s Discussion and Analysis
of Financial Condition and Results of Operation: Results of Operations - Oil and
Gas Price Risk Management, Net, Oil and Gas Derivative Activities and
Note 3, Derivative Financial
Instruments, to our consolidated financial statements included in this
report.
We
sell our natural gas to other gas marketers, utilities, industrial end-users and
other wholesale gas purchasers. During 2008, the natural gas we
produced was sold at prices ranging from $2.77 to $13.85 per Mcf, depending upon
well location, the date of the sales contract and other factors. Our
weighted net average price of natural gas sold in 2008 was $6.98 per
Mcf.
In
general, we have been and expect to continue to be able to produce and sell
natural gas from our wells without significant curtailment and at competitive
prices. We do experience limited curtailments from time to time due
to pipeline maintenance and operating issues. For instance, we
experienced an approximate 10% to 15% curtailment of production volumes,
approximately 10,000 Mcf per day, in the Piceance Basin due to limited
compression and pipeline capacity throughout most of the fourth quarter in
2008. This interruption, due to third party infrastructure, was
corrected in early 2009. Open access transportation through the
country's interstate pipeline system gives us access to a broad range of
markets. Whenever feasible, we obtain access to multiple pipelines
and markets from each of our gathering systems seeking the best available market
for our natural gas at any point in time.
Oil
Sales
The
majority of our wells in the Wattenberg Field in Colorado and our wells in North
Dakota produce oil in addition to natural gas. As of December 31,
2008, oil represented 12% of our total equivalent reserves and accounted for
approximately 32% of our oil and gas sales revenue for the year ended December
31, 2008.
We are
currently able to sell all the oil that we can produce under existing sales
contracts with petroleum refiners and marketers. We do not refine any
of our oil production. Our crude oil production is sold to purchasers
at or near our wells under both short and long-term purchase contracts with
monthly pricing provisions. During 2008, oil we produced sold at
prices ranging from $19.82 to $132.38 per Bbl, depending upon the location and
quality of oil. Our weighted net average price per Bbl of oil sold in
2008 was $89.77.
Natural
Gas Marketing
Our
natural gas marketing activities involve the purchase of natural gas from other
producers and the sale of that natural gas along with the natural gas we produce
for our own interest and that of our affiliated partnerships. A
variety of factors affect the market for natural gas,
including:
|
·
|
the
availability of other domestic
production;
|
|
·
|
the
availability and price of alternative
fuels;
|
|
·
|
the
proximity and capacity of natural gas
pipelines;
|
|
·
|
general
fluctuations in the supply and demand for natural gas;
and
|
|
·
|
the
effects of state and federal regulations on natural gas production and
sales.
|
The
natural gas industry also competes with other industries in supplying the energy
and fuel requirements of industrial, commercial and individual
customers.
RNG
specializes in the purchase, aggregation and sale of natural gas production in
our Eastern operating areas. RNG markets the natural gas we produce
and also purchases natural gas in the Appalachian Basin from other producers and
resells it to other marketers, utilities or end users. RNG's
employees have extensive knowledge of natural gas markets in our areas of
operations. Such knowledge assists us in maximizing our prices as we
market natural gas from PDC-operated wells. The gas is marketed to
other marketers, natural gas utilities, as well as industrial and commercial
customers, either directly through our gathering system, or through
transportation services provided by regulated interstate pipeline
companies.
We have
entered into various sales, transportation and processing agreements with
unrelated third parties which we sell to or who transports our natural
gas. The following table sets forth information about long-term firm
sales, processing and transportation agreements for pipeline capacity, which
require a demand charge whether volumes are delivered or not.
Type
of Arrangement
|
|
Location
|
|
Average
Annual
Volume
(MMbtu)
|
|
Expiration
Date
|
|
|
|
|
|
|
|
Firm
sales and processing
|
|
Grand
Valley
|
|
23,218,287
|
|
May
2016
|
Firm
transportation
|
|
NECO
Area
|
|
1,825,000
|
|
December
2010
|
Firm
transportation
|
|
NECO
Area
|
|
1,825,000
|
|
December
2016
|
Firm
transportation (1)
|
|
Appalachian
Basin
|
|
12,230,785
|
|
December
2022
|
(1) Contract is a precedent
agreement and becomes effective when the planned pipeline is placed in service,
estimated at this time to be 2012. Contract is null and void if pipeline
is not
completed.
Commodity
Risk Management Activities
We
utilize commodity based derivative instruments to manage a portion of our
exposure to price volatility with regard to our oil and natural gas sales and
marketing activities. These instruments consist of NYMEX-traded
natural gas over-the-counter swaps, futures and option contracts for Appalachian
and Michigan production, CIG and PEPL-based contracts for Colorado
natural gas production and NYMEX-traded over-the-counter oil swaps and option
contracts for Colorado oil production. We may utilize derivatives
based on other indices or markets where appropriate. The contracts
economically provide price stability for committed and anticipated oil and
natural gas purchases and sales, generally forecasted to occur within the next
two to three-year period, but no longer than five years beyond the derivative
transaction date. Our policies prohibit the use of oil and natural
gas futures, swaps or options for speculative purposes and permit utilization of
derivatives only if there is an underlying physical position.
RNG has
extensive experience with the use of derivatives to reduce the risk and effect
of natural gas price changes. RNG uses these financial derivatives to
coordinate fixed purchases and sales. We use financial derivatives to
establish “floors” and “ceilings” or “collars” on the possible range of the
prices realized for the sale of natural gas and oil in addition to fixing prices
by using swaps. RNG also enters into back-to-back fixed-price
purchases and sales contracts with counterparties. These fixed
physical contracts meet the SFAS No. 133, Accounting for Derivative
Instruments and Certain Hedging Activities, definition of a
derivative. Both types of derivatives (i.e., the physical deals and
the cash settled contracts) are carried on the balance sheet at fair value with
changes in fair values recognized currently in the statement of
operations.
We are
subject to price fluctuations for natural gas sold in the spot market and under
market index contracts. RNG does not always hedge the area basis risk
for third party trades with back-to-back fixed price purchases and
sales. We continue to evaluate the potential for reducing these risks
by entering into derivative transactions. In addition, we may close
out any portion of derivatives that may exist from time to time which may result
in a realized gain or loss on that derivative transaction. We manage
price risk on only a portion of our anticipated production, so the remaining
portion of our production is subject to the full fluctuation of market
pricing.
Well
Operations
As of
December 31, 2008, we had an interest in approximately 2,412 wells in the Rocky
Mountain Region, 2,090 wells in the Appalachian Basin, and 210 wells in the
Michigan Basin. On average, our interest ownership in these wells was
approximately 69.2%.
We are
paid a monthly operating fee for the portion of each well we operate that is
owned by others, including our sponsored partnerships. The fee is
competitive with rates charged by other operators in the area. The
fee covers monthly operating and accounting costs, insurance and other recurring
costs. If we purchase well interests belonging to investors in our
sponsored partnerships, we then account for the purchased interests as being
owned by us, which results in a decrease in well operations income.
Transportation
and Gathering
We
develop, own and operate gathering systems in some of our areas of
operations. We also continue to construct new trunk lines as
necessary to provide for the marketing of natural gas being developed from new
areas and to enhance or maintain our existing systems. Pipelines and
related facilities can represent a significant portion of the capital costs of
developing wells, particularly in new areas located at a distance from existing
pipelines. We consider these costs in our evaluation of our leasing,
development and acquisition opportunities.
Our
natural gas and oil are transported through our own and third party gathering
systems and pipelines, and we incur processing, gathering and transportation
expenses to move our natural gas from the wellhead to a purchaser-specified
delivery point. These expenses vary based on the volume and distance
shipped, and the fee charged by the third-party processor or
transporter. Capacity on these gathering systems and pipelines is
occasionally limited and at times unavailable because of repairs or
improvements, or as a result of priority transportation agreements with other
gas transporters. While our ability to market our natural gas has
been only infrequently limited or delayed, if transportation space is restricted
or is unavailable, our cash flow from the affected properties could be adversely
affected. In certain instances, we enter into firm transportation
agreements to provide for pipeline capacity to flow and sell a portion of our
gas volumes. In order to meet pipeline specifications, we are
required, in some cases, to process our gas before we can transport
it. We typically contract with third parties in the Grand Valley and
NECO areas of our Rocky Mountain Region and Appalachian Basin for firm
transportation of our natural gas. We also may enter into firm sales
agreements to ensure that we are selling to a purchaser who has contracted for
pipeline capacity. These agreements are subject to the same
limitations discussed above in this paragraph.
Governmental
Regulation
While the
prices of oil and natural gas are set by the market, other aspects of our
business and the oil and natural gas industry in general are heavily
regulated. The availability of a ready market for oil and natural gas
production depends on several factors beyond our control. These
factors include regulation of production, federal and state regulations
governing environmental quality and pollution control, the amount of oil and
natural gas available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive
fuels. State and federal regulations generally are intended to
protect consumers from unfair treatment and oppressive control, to reduce the
risk to the public and workers from the drilling, completion, production and
transportation of oil and natural gas, to prevent waste of oil and natural gas,
to protect rights among owners in a common reservoir and to control
contamination of the environment. Pipelines are subject to the
jurisdiction of various federal, state and local agencies. In the
western part of the U.S., the federal and state governments own a large
percentage of the land and the rights to develop oil and natural
gas. Generally, government leases are subject to additional
regulations and controls not commonly seen on private leases. We take
the steps necessary to comply with applicable regulations, both on our own
behalf and as part of the services we provide to our drilling
partnerships. We believe that we are in compliance with such
statutes, rules, regulations and governmental orders, although there can be no
assurance that this is or will remain the case. The following summary
discussion of the regulation of the U.S. oil and natural gas industry is not
intended to constitute a complete discussion of the various statutes, rules,
regulations and environmental orders to which our operations may be
subject.
Regulation
of Oil and Natural Gas Exploration and Production
Our
exploration and production business is subject to various federal, state and
local laws and regulations on the taxation of oil and natural gas, the
development, production and marketing of oil and natural gas and environmental
and safety matters. Many laws and regulations require drilling
permits and govern the spacing of wells, rates of production, water discharge,
prevention of waste and other matters. Prior to commencing drilling
activities for a well, we must procure permits and/or approvals for the various
stages of the drilling process from the applicable state and local agencies in
the state in which the area to be drilled is located. The permits and
approvals include those for the drilling of wells. Additionally,
other regulated matters include:
|
·
|
bond
requirements in order to drill or operate
wells;
|
|
·
|
the
method of drilling and casing
wells;
|
|
·
|
the
surface use and restoration of well
properties;
|
|
·
|
the
plugging and abandoning of wells;
and
|
|
·
|
the
disposal of fluids.
|
Our
operations are also subject to various conservation laws and
regulations. These include the regulation of the size of drilling and
spacing units or proration units, the density of wells which may be drilled and
the unitization or pooling of properties. In this regard, some states
allow the forced pooling or integration of tracts to facilitate exploration
while other states rely primarily or exclusively on voluntary pooling of lands
and leases. In areas where pooling is voluntary, it may be more
difficult to form units, and therefore, more difficult to develop a project if
the operator owns less than 100% of the leasehold. In addition, state
conservation laws may establish maximum rates of production from oil and natural
gas wells, generally prohibiting the venting or flaring of natural gas and
imposing certain requirements regarding the ratability of
production. Where wells are to be drilled on state or federal leases,
additional regulations and conditions may apply. The effect of these
regulations may limit the amount of oil and natural gas we can produce from our
wells and may limit the number of wells or the locations at which we can
drill. Such laws and regulations may increase the costs of planning,
designing, drilling, installing, operating and abandoning our oil and natural
gas wells and other facilities. In addition, these laws and
regulations, and any others that are passed by the jurisdictions where we have
production, could limit the total number of wells drilled or the allowable
production from successful wells, which could limit our reserves. As
a result, we are unable to predict the future cost or effect of complying with
such regulations.
Regulation
of Sales and Transportation of Natural Gas
Historically,
the price of natural gas was subject to limitation by federal
legislation. The Natural Gas Wellhead Decontrol Act removed, as of
January 1, 1993, all remaining federal price controls from natural gas sold in
“first sales” on or after that date. The Federal Energy Regulatory
Commission's, or FERC, jurisdiction over natural gas transportation was
unaffected by the Decontrol Act.
We move
natural gas through pipelines owned by other companies, and sell natural gas to
other companies that also utilize common carrier pipeline
facilities. Natural gas pipeline interstate transmission and storage
activities are subject to regulation by the FERC under the Natural Gas Act of
1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates
and charges for the transportation of natural gas in interstate commerce,
accounting, and the extension, enlargement or abandonment of its jurisdictional
facilities, among other things, are subject to regulation. Each
natural gas pipeline company holds certificates of public convenience and
necessity issued by the FERC authorizing ownership and operation of all
pipelines, facilities and properties for which certificates are required under
the NGA. Each natural gas pipeline company is also subject to the
Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety
requirements in the design, construction, operation and maintenance of
interstate natural gas transmission facilities. FERC regulations
govern how interstate pipelines communicate and do business with their
affiliates. Interstate pipelines may not operate their pipeline
systems to preferentially benefit their marketing affiliates.
Each
interstate natural gas pipeline company establishes its rates primarily through
the FERC’s ratemaking process. Key determinants in the ratemaking
process are:
|
•
|
costs
of providing service, including depreciation
expense;
|
|
•
|
allowed
rate of return, including the equity component of the capital structure
and related income taxes; and
|
|
•
|
volume
throughput assumptions.
|
The
availability, terms and cost of transportation affect our natural gas
sales. In the past, FERC has undertaken various initiatives to
increase competition within the natural gas industry. As a result of
initiatives like FERC Order No. 636, issued in April 1992, the interstate
natural gas transportation and marketing system was substantially restructured
to remove various barriers and practices that historically limited non-pipeline
natural gas sellers, including producers, from effectively competing with
interstate pipelines for sales to local distribution companies and large
industrial and commercial customers. The most significant provisions
of Order No. 636 require that interstate pipelines provide transportation
separate or “unbundled” from their sales service, and require that pipelines
provide firm and interruptible transportation service on an open access basis
that is equal for all natural gas suppliers. In many instances, the
result of Order No. 636 and related initiatives has been to substantially reduce
or eliminate the interstate pipelines' traditional role as wholesalers of
natural gas in favor of providing only storage and transportation
services. Another effect of regulatory restructuring is greater
access to transportation on interstate pipelines. In some cases,
producers and marketers have benefited from this
availability. However, competition among suppliers has greatly
increased and traditional long-term producer-pipeline contracts are
rare. Furthermore, gathering facilities of interstate pipelines are
no longer regulated by FERC, thus allowing gatherers to charge higher gathering
rates. Historically, producers were able to flow supplies into
interstate pipelines on an interruptible basis; however, recently we have seen
the increased need to acquire firm transportation on pipelines in order to avoid
curtailments or shut-in-gas, which could adversely affect cash flows from the
affected area.
Additional
proposals and proceedings that might affect the natural gas industry occur
frequently in Congress, FERC, state commissions, state legislatures, and the
courts. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by FERC and Congress will continue. We
cannot determine to what extent our future operations and earnings will be
affected by new legislation, new regulations, or changes in existing regulation,
at federal, state or local levels.
Environmental
Regulations
Our
operations are subject to numerous laws and regulations governing the discharge
of materials into the environment or otherwise relating to environmental
protection. Public interest in the protection of the environment has
increased dramatically in recent years. The trend of more expansive
and tougher environmental legislation and regulations could
continue. To the extent laws are enacted or other governmental action
is taken that restricts drilling or imposes environmental protection
requirements that result in increased costs and reduced access to the natural
gas industry in general, our business and prospects could be adversely
affected.
We
generate wastes that may be subject to the Federal Resource Conservation and
Recovery Act, or RCRA, and comparable state statutes. The U.S.
Environmental Protection Agency, or EPA, and various state agencies have limited
the approved methods of disposal for certain hazardous and non-hazardous
wastes. Furthermore, certain wastes generated by our operations that
are currently exempt from treatment as “hazardous wastes” may in the future be
designated as “hazardous wastes,” and therefore be subject to more rigorous and
costly operating and disposal requirements.
We
currently own or lease numerous properties that for many years have been used
for the exploration and production of oil and natural gas. Although
we believe that we have utilized good operating and waste disposal practices,
and when necessary, appropriate remediation techniques, prior owners and
operators of these properties may not have utilized similar practices and
techniques, and hydrocarbons or other wastes may have been disposed of or
released on or under the properties that we own or lease or on or under
locations where such wastes have been taken for disposal. These
properties and the wastes disposed thereon may be subject to the Comprehensive
Environmental Response, Compensation and Liability Act, or CERCLA, RCRA and
analogous state laws, as well as state laws governing the management of oil and
natural gas wastes. Under such laws, we could be required to remove
or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
CERCLA
and similar state laws impose liability, without regard to fault or the legality
of the original conduct, on certain classes of persons that are considered to
have contributed to the release of a “hazardous substance” into the
environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed of
or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for release of hazardous
substances under CERCLA may be subject to full liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and 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. As an owner and operator of oil and natural gas
wells, we may be liable pursuant to CERCLA and similar state laws.
Our
operations may be subject to the Clean Air Act, or CAA, and comparable state and
local requirements. Amendments to the CAA were adopted in 1990 and
contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. The EPA and states have been developing regulations to
implement these requirements. We may be required to incur certain
capital expenditures in the next several years for air pollution control
equipment in connection with maintaining or obtaining operating permits and
approvals addressing other air emission-related issues. The State of
Colorado has also indicated it intends to implement new air regulations in 2009,
which affect the oil and gas industry, including our operations, related to air
emissions.
The
Federal Clean Water Act, or CWA, and analogous state laws impose strict controls
against the discharge of pollutants, including spills and leaks of oil and other
substances. The CWA also regulates storm water run-off from oil and
gas facilities and requires a storm water discharge permit for certain
activities. Spill prevention, control, and countermeasure
requirements of the CWA require appropriate containment terms and similar
structures to help prevent the contamination of navigable waters in the event of
a petroleum hydrocarbon tank spill, rupture, or leak.
Oil
production is subject to many of the same operating hazards and environmental
concerns as natural gas production, but is also subject to the risk of oil
spills. Federal regulations require certain owners or operators of
facilities that store or otherwise handle oil, including us, to procure and
implement Spill Prevention, Control and Counter-measures plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act
of 1990, or OPA, subjects owners of facilities to strict joint and several
liability for all containment and cleanup costs and certain other damages
arising from oil spills. Noncompliance with OPA may result in varying
civil and criminal penalties and liabilities. We are also subject to
the CWA and analogous state laws relating to the control of water pollution,
which laws provide varying civil and criminal penalties and liabilities for
release of petroleum or its derivatives into surface waters or into the
ground. Historically, we have not experienced any significant oil
discharge or oil spill problems.
In
December 2008, the State of Colorado’s Oil and Gas Conservation Commission
finalized new broad-based environmental regulations for the oil and natural gas
industry. These regulations will increase our costs and may
ultimately limit some drilling locations. Our expenses relating to
preserving the environment have risen over the past few years and are expected
to continue to rise in 2009 and beyond. Environmental regulations
have had no materially adverse effect on our operations to date, but no
assurance can be given that environmental regulations or interpretations of such
regulations will not, in the future, result in a curtailment of production or
otherwise have a materially adverse effect on our business, financial condition
or results of operations. See Note 8, Commitments and Contingencies –
Litigation, Colorado Stormwater Permit, to our accompanying consolidated
financial statements included in this report.
Operating
Hazards and Insurance
Our
exploration and production operations include a variety of operating risks,
including, but not limited to, the risk of fire, explosions, blowouts,
cratering, pipe failure, casing collapse, abnormally pressured formations, and
environmental hazards such as gas leaks, ruptures and discharges of toxic
gas. The occurrence of any of these could result in substantial
losses to us due to injury and loss of life, severe damage to and destruction of
property, natural resources and equipment, pollution and other environmental
damage, clean-up responsibilities, regulatory investigation and penalties and
suspension of operations. Our pipeline, gathering and distribution
operations are subject to the many hazards inherent in the natural gas
industry. These hazards include damage to wells, pipelines and other
related equipment, damage to property caused by hurricanes, floods, fires and
other acts of God, inadvertent damage from construction equipment, leakage of
natural gas and other hydrocarbons, fires and explosions and other hazards that
could also result in personal injury and loss of life, pollution and suspension
of operations.
Any
significant problems related to our facilities could adversely affect our
ability to conduct our operations. In accordance with customary
industry practice, we maintain insurance against some, but not all, potential
risks; however, there can be no assurance that such insurance will be adequate
to cover any losses or exposure for liability. The occurrence of a
significant event not fully insured against could materially adversely affect
our operations and financial condition. We cannot predict whether
insurance will continue to be available at premium levels that justify our
purchase or whether insurance will be available at all. Furthermore,
we are not insured against our economic losses resulting from damage or
destruction to third party property, such as the Rockies Express pipeline; such
an event could result in significantly lower regional prices or our inability to
deliver gas.
Competition
We
believe that our exploration, drilling and production capabilities and the
experience of our management and professional staff generally enable us to
compete effectively. We encounter competition from numerous other oil
and natural gas companies, drilling and income programs and partnerships in all
areas of operations, including drilling and marketing oil and natural gas and
obtaining desirable oil and natural gas leases on producing
properties. Many of these competitors possess larger staffs and
greater financial resources than we do, which may enable them to identify and
acquire desirable producing properties and drilling prospects more
economically. Our ability to explore for oil and natural gas
prospects and to acquire additional properties in the future depends upon our
ability to conduct our operations, to evaluate and select suitable properties
and to consummate transactions in this highly competitive
environment. We also face intense competition in the marketing of
natural gas from competitors including other producers as well as marketing
companies. Also, international developments and the possible improved
economics of domestic natural gas exploration may influence other companies to
increase their domestic oil and natural gas exploration. Furthermore,
competition among companies for favorable prospects can be expected to continue,
and it is anticipated that the cost of acquiring properties may increase in the
future. During 2008, our industry experienced continued strong demand
for drilling services and supplies which resulted in increasing
costs. In 2009, due to industry slowdown, we are experiencing overall
reductions in our operating and drilling costs. Factors affecting
competition in the oil and natural gas industry include price, location of
drilling, availability of drilling prospects and drilling rigs, pipeline
capacity, quality of production and volumes produced. We believe that
we can compete effectively in the oil and natural gas industry in each of the
listed areas. Nevertheless, our business, financial condition and
results of operations could be materially adversely affected by
competition. We also compete with other oil and gas companies as well
as companies in other industries for the capital we need to conduct our
operations. Recently, turmoil in the capital markets has made
financing more expensive and difficult to obtain. In the event that
we do not have adequate capital to execute our business plan, we may be forced
to curtail our drilling and acquisition activities.
Employees
As of
December 31, 2008, we had 317 employees, including 205 in production, 8 in
natural gas marketing, 28 in exploration and development, 49 in finance,
accounting and data processing, and 27 in administration. Our
engineers, supervisors and well tenders are responsible for the day-to-day
operation of wells and some pipeline systems. In addition, we retain
subcontractors to perform drilling, fracturing, logging, and pipeline
construction functions at drilling sites, with our employees supervising the
activities of the subcontractors. In 2008, the total number of
Company employees increased by 61.
Our
employees are not covered by a collective bargaining agreement. We
consider relations with our employees to be very good.
You
should carefully consider the following risk factors in addition to the other
information included in this report. Each of these risk factors could
adversely affect our business, operating results and financial condition, as
well as adversely affect the value of an investment in our common stock or other
securities.
Risks
Related to the Global Economic Environment
The
current global economic environment may increase the magnitude and the
likelihood of the occurrence of the negative consequences discussed in many of
the risks factors that follow.
In
particular, consider the risks related to (1) the rapid deterioration of demand
for oil and natural gas resulting from the economic environment and the related
negative effects on oil and gas pricing, and (2) the effect of the credit
constraints on our business, including the severe reduction in the availability
of credit for drilling or to finance acquisitions. Also consider the
interplay between these two risks: decline in oil and gas prices can lead to a
reduction in the borrowing base for our credit line, and hence a reduction in
our credit available for drilling. Similarly, further reductions in
oil and gas prices could result in some of our assets becoming uneconomic to
exploit, which would reduce our reserves, which in turn would reduce our
borrowing base and the credit available to us. These factors could
result in less drilling and production by us, and could thereby adversely affect
our profitability and could limit our ability to execute our business
plan. These factors could also make it impossible or extremely
expensive to extend the term of our revolving credit line. The global
economic environment also increases the counterparty failure risk for both the
banks which are parties to our oil and gas derivative holdings and for payments
from purchasers of our oil and gas. Lastly, inability to ascertain
the ultimate depth and duration of the economic environment could cause us to
refrain from capital expenditures in order to maintain higher liquidity; our
uncertainty and caution could result in significantly reduced drilling and hence
reduced future production. All these risks could have a significant
adverse effect on our business and our financial results. Any
additional deterioration in the domestic or global economic conditions will
further amplify these risks.
Recent
disruptions in the global financial markets and the related economic environment
may further decrease the demand for oil and gas and the prices of oil and gas,
thereby limiting our future drilling and production, and thereby adversely
affecting our profitability.
During
the second half of 2008 and to date, prices for oil and gas decreased over
70%. The well-publicized global financial market disruptions and the
related economic environment may further decrease demand for oil and gas and
therefore lower oil and gas prices. If there is such an additional reduction in
demand, the continued production of gas may increase current oversupply and
result in still lower gas prices. There is no certainty how long this
low price environment will continue. We operate in a highly
competitive industry, and certain competitors may have lower operating costs in
such an environment. Furthermore, as a result of these disruptions in
the financial markets, it is possible that in future years we would not be able
to borrow sufficient funds to sustain or increase capital expenditures relative
to 2008 expenditures, should we wish to make expenditures at those
levels. Such market conditions may also make it more difficult or
impossible for us to finance acquisitions, through either equity or debt;
acquisitions have historically been a major source of growth for
us. We may also have difficulty finding partners to develop new
drilling prospects and to build the pipeline systems needed to transport our
gas. Inability of third parties to finance and build additional
pipelines out of the Rockies and elsewhere could cause significant negative
pricing effects. Any of the above factors could adversely affect our
operating results.
Risks
Related to Our Business and the Natural Gas and Oil Industry
Natural
gas and oil prices fluctuate unpredictably and a decline in natural gas and oil
prices can significantly affect the value of our assets, our financial results
and impede our growth.
Our
revenue, profitability and cash flow depend in large part upon the prices and
demand for natural gas and oil. The markets for these commodities are
very volatile, and even relatively modest drops in prices can significantly
affect our financial results and impede our growth. Changes in
natural gas and oil prices have a significant effect on our cash flow and on the
value of our reserves, which can in turn reduce our borrowing base under our
senior credit agreement. Prices for natural gas and oil may fluctuate
widely in response to relatively minor changes in the supply of and demand for
natural gas and oil, market uncertainty and a variety of additional factors that
are beyond our control, including national and international economic and
political factors and federal and state legislation. The prices from the fourth
quarter of 2008 to date have been too low to economically justify many drilling
operations, and it is uncertain how long such low pricing shall
persist.
The
prices of natural gas and oil are volatile, often fluctuating
greatly. Lower natural gas and oil prices may not only reduce our
revenues, but also may reduce the amount of natural gas and oil that we can
produce economically. As a result, we may have to make substantial
additional downward adjustments to our estimated proved reserves. If
this occurs or if our estimates of development costs increase, production data
factors change or our exploration results deteriorate, accounting rules may
require us to write-down operating assets to fair value, as a non-cash charge to
earnings. We assess impairment of capitalized costs of proved natural
gas and oil properties by comparing net capitalized costs to estimated
undiscounted future net cash flows on a field-by-field basis using estimated
production based upon prices at which management reasonably estimates such
products may be sold. In 2008, we recorded an impairment charge of
$7.5 million primarily related to our Texas Barnett Shale wells, and in 2006, we
recorded an impairment charge of $1.5 million related to our Nesson field in
North Dakota. There were no impairments during 2007. We
may incur impairment charges in the future, which could have a material adverse
effect on the results of our operations.
A
substantial part of our natural gas and oil production is located in the Rocky
Mountain Region, making it vulnerable to risks associated with operating
primarily in a single geographic area.
Our
operations have been focused on the Rocky Mountain Region, which means our
current producing properties and new drilling opportunities are geographically
concentrated in that area. Because our operations are not as
diversified geographically as many of our competitors, the success of our
operations and our profitability may be disproportionately exposed to the affect
of any regional events, including fluctuations in prices of natural gas and oil
produced from the wells in the region, natural disasters, restrictive
governmental regulations, transportation capacity constraints, curtailment of
production or interruption of transportation, and any resulting delays or
interruptions of production from existing or planned new wells.
During
the last four months of 2008, natural gas prices in the Rocky Mountain Region
fell disproportionately when compared to other markets, due in part to
continuing constraints in transporting natural gas from producing properties in
the region. Because of the concentration of our operations in the
Rocky Mountain Region, and although, in late 2008 we entered into a significant
multi-year basis hedge in order to minimize the price risk of our concentration
in the Rocky Mountain Region, such price decreases are more likely to have a
material adverse effect on our revenue, profitability and cash flow than those
of our more geographically diverse competitors.
Our
estimated natural gas and oil reserves are based on many assumptions that may
turn out to be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions may materially affect the quantities and
present value of our reserves.
Natural
gas and oil reserve engineering requires subjective estimates of underground
accumulations of natural gas and oil and assumptions concerning future natural
gas and oil prices, production levels, and operating and development costs over
the economic life of the properties. As a result, estimated
quantities of proved reserves and projections of future production rates and the
timing of development expenditures may be inaccurate. Independent
petroleum engineers prepare our estimates of natural gas and oil reserves using
pricing, production, cost, tax and other information that we
provide. The reserve estimates are based on certain assumptions
regarding future natural gas and oil prices, production levels, and operating
and development costs that may prove incorrect. Any significant
variance from these assumptions to actual figures could greatly
affect:
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the
estimates of reserves;
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the
economically recoverable quantities of natural gas and oil attributable to
any particular group of properties;
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future
depreciation, depletion and amortization rates and
amounts;
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impairments
in the value of our assets;
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the
classifications of reserves based on risk of
recovery;
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estimates
of the future net cash flows; and
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timing
of our capital
expenditures.
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Some of
our reserve estimates must be made with limited production history, which
renders these reserve estimates less reliable than estimates based on a longer
production history. Numerous changes over time to the assumptions on
which the reserve estimates are based, as described above, often result in the
actual quantities of natural gas and oil recovered being different from earlier
reserve estimates.
The
present value of our estimated future net cash flows from proved reserves is not
necessarily the same as the current market value of our estimated natural gas
and oil reserves (the SEC requires the use of year end prices). The
estimated discounted future net cash flows from proved reserves are based on
selling prices in effect on the day of estimate (year end). However,
factors such as actual prices we receive for natural gas and oil and hedging
instruments, the amount and timing of actual production, amount and timing of
future development costs, supply of and demand for natural gas and oil, and
changes in governmental regulations or taxation also affect our actual future
net cash flows from our natural gas and oil properties.
The
timing of both our production and incurrence of expenses in connection with the
development and production of natural gas and oil properties will affect the
timing of actual future net cash flows from proved reserves, and thus their
actual present value. In addition, the 10% discount factor (the rate
required by the SEC) we use when calculating discounted future net cash flows
may not be the most appropriate discount factor based on interest rates
currently in effect and risks associated with our natural gas and oil properties
or the natural gas and oil industry in general.
Unless
natural gas and oil reserves are replaced as they are produced, our reserves and
production will decline, which would adversely affect our future business,
financial condition and results of operations.
Producing
natural gas and oil reservoirs generally is characterized by declining
production rates that vary depending upon reservoir characteristics and other
factors. The rate of decline will change if production from existing
wells declines in a different manner than we estimated and the rate can change
due to other circumstances. Thus, our future natural gas and oil
reserves and production and, therefore, our cash flow and income, are highly
dependent on efficiently developing and exploiting our current reserves and
economically finding or acquiring additional recoverable reserves. We
may not be able to develop, discover or acquire additional reserves to replace
our current and future production at acceptable costs. As a result,
our future operations, financial condition and results of operations would be
adversely affected.
Acquisitions
are subject to the uncertainties of evaluating recoverable reserves and
potential liabilities.
Acquisitions
of producing properties and undeveloped properties have been an important part
of our historical growth. We expect acquisitions will also contribute
to our future growth. Successful acquisitions require an assessment
of a number of factors, many of which are beyond our control. These
factors include recoverable reserves, development potential, future natural gas
and oil prices, operating costs and potential environmental and other
liabilities. Such assessments are inexact and their accuracy is
inherently uncertain. In connection with our assessments, we perform
engineering, geological and geophysical reviews of the acquired properties,
which we believe is generally consistent with industry
practices. However, such reviews are not likely to permit us to
become sufficiently familiar with the properties to fully assess their
deficiencies and capabilities. We do not inspect every well prior to
an acquisition and our ability to evaluate undeveloped acreage is inherently
imprecise. Even when we inspect a well, we do not always discover
structural, subsurface and environmental problems that may exist or
arise. In some cases, our review prior to signing a definitive
purchase agreement may be even more limited.
Our focus
on acquiring producing natural gas and oil properties may increase our potential
exposure to liabilities and costs for environmental and other problems existing
on acquired properties. Often we are not entitled to contractual
indemnification associated with acquired properties. Normally, we
acquire interests in properties on an “as is” basis with no or limited remedies
for breaches of representations and warranties, as was the case in the
acquisitions of assets from EXCO Resources Inc. and Castle Gas Company, as well
as the acquisition of all shares of Unioil, Inc. We could incur
significant unknown liabilities, including environmental liabilities, or
experience losses due to title defects, in our acquisitions for which we have
limited or no contractual remedies or insurance coverage.
Additionally,
significant acquisitions can change the nature of our operations depending upon
the character of the acquired properties, which may have substantially different
operating and geological characteristics or be in different geographic locations
than our existing properties. For example, in the Castle acquisition,
we acquired interests in wells which we will need to operate together with other
partners, we acquired pipelines that we will need to operate and expect we will
need to commit to drilling in the acquired areas to achieve the expected
benefits. Consequently, we may not be able to efficiently realize the
assumed or expected economic benefits of properties that we acquire, if at
all.
When
drilling prospects, we may not yield natural gas or oil in commercially viable
quantities.
A
prospect is a property on which our geologists have identified what they
believe, based on available information, to be indications of natural gas or oil
bearing rocks. However, our geologists cannot know conclusively prior
to drilling and testing whether natural gas or oil will be present or, if
present, whether natural gas or oil will be present in sufficient quantities to
repay drilling or completion costs and generate a profit given the available
data and technology. If a well is determined to be dry or uneconomic,
which can occur even though it contains some oil or natural gas, it is
classified as a dry
hole and must be plugged and abandoned in accordance with applicable
regulations. This generally results in the loss of the entire cost of
drilling and completion to that point, the cost of plugging, and lease costs
associated with the prospect. Even wells that are completed and
placed into production may not produce sufficient natural gas and oil to be
profitable. If we drill a dry hole or unprofitable well on current
and future prospects, the profitability of our operations will decline and our
value will likely be reduced. In sum, the cost of drilling,
completing and operating any well is often uncertain and new wells may not be
productive. Our recent uneconomic drilling in the Texas Barnett Shale
illustrates this risk.
We
may not be able to identify enough attractive prospects on a timely basis to
meet our development needs, which could limit our future development
opportunities.
Our
geologists have identified a number of potential drilling locations on our
existing acreage. These drilling locations must be replaced as they
are drilled for us to continue to grow our reserves and
production. Our ability to identify and acquire new drilling
locations depends on a number of uncertainties, including the availability of
capital, regulatory approvals, natural gas and oil prices, competition, costs,
availability of drilling rigs, drilling results and the ability of our
geologists to successfully identify potentially successful new areas to
develop. Because of these uncertainties, our profitability and growth
opportunities may be limited by the timely availability of new drilling
locations. As a result, our operations and profitability could be
adversely affected.
Drilling
for and producing natural gas and oil are high risk activities with many
uncertainties that could adversely affect our business, financial condition and
results of operations.
Drilling
activities are subject to many risks, including the risk that we will not
discover commercially productive reservoirs. Drilling for natural gas and oil
can be unprofitable, not only due to dry holes, but also due to curtailments,
delays or cancellations as a result of other factors, including:
• unusual
or unexpected geological formations;
•
pressures;
•
fires;
•
blowouts;
• loss of
drilling fluid circulation;
• title
problems;
•
facility or equipment malfunctions;
•
unexpected operational events;
•
shortages or delivery delays of equipment and services;
•
compliance with environmental and other governmental requirements;
and
• adverse
weather conditions.
Any of
these risks can cause substantial losses, including personal injury or loss of
life, damage to or destruction of property, natural resources and equipment,
pollution, environmental contamination or loss of wells and regulatory
penalties. We maintain insurance against various losses and
liabilities arising from operations; however, insurance against all operational
risks is not available. Additionally, our management may elect not to
obtain insurance if the cost of available insurance is excessive relative to the
perceived risks presented. Thus, losses could occur for uninsurable or uninsured
risks or in amounts in excess of existing insurance coverage. The
occurrence of an event that is not fully covered by insurance could have a
material adverse effect on our business activities, financial condition and
results of operations.
Our
oil and gas well drilling operations segment has historically received most of
its revenue from the partnerships we sponsor, and a reduction or loss of that
business could reduce or eliminate the revenue, profit and cash flow associated
with those activities.
Our oil
and gas well drilling operations segment has, prior to 2008, received most of
its revenue from the partnerships we sponsor. We sponsor oil and
natural gas partnerships through a network of non-affiliated FINRA broker
dealers. We did not offer a partnership in 2008 and do not
anticipate offering a partnership in 2009. There can be no assurance
that the network of brokers will be available or can be recreated if we wish to
use partnerships to raise funds in future years. In that situation,
our operations and profitability could be adversely
affected.
Under
the “successful efforts” accounting method that we use, unsuccessful exploratory
wells must be expensed in the period when they are determined to be
non-productive, which reduces our net income in such periods and could have a
negative effect on our profitability.
We have
conducted exploratory drilling and plan to continue exploratory drilling in 2009
in order to identify additional opportunities for future
development. Under the “successful efforts” method of accounting that
we use, the cost of unsuccessful exploratory wells must be charged to expense in
the period when they are determined to be unsuccessful. In addition,
lease costs for acreage condemned by the unsuccessful well must also be
expensed. In contrast, unsuccessful development wells are capitalized
as a part of the investment in the field where they are
located. Because exploratory wells generally are more likely to be
unsuccessful than development wells, we anticipate that some or all of our
exploratory wells may not be productive. The costs of such
unsuccessful exploratory wells could result in a significant reduction in our
profitability in periods when the costs are required to be expensed and these
increased costs could reduce our net income and have a negative effect on our
profitability and ability to repay or refinance our
indebtedness.
Increasing finding and development
costs may impair our profitability.
In order
to continue to grow and maintain our profitability, we must annually add new
reserves that exceed our yearly production at a finding and development cost
that yields an acceptable operating margin and depreciation, depletion and
amortization rate. Without cost effective exploration, development or
acquisition activities, our production, reserves and profitability will decline
over time. Given the relative maturity of most natural gas and oil
basins in North America and the high level of activity in the industry, the cost
of finding new reserves through exploration and development operations has been
increasing. The acquisition market for natural gas and oil properties
has become extremely competitive among producers for additional production and
expanded drilling opportunities in North America. Acquisition values
climbed toward historic highs during 2007 and 2008 on a per unit basis,
particularly in the Rocky Mountain Region, and these values may continue to
increase in the future. This increase in finding and development
costs results in higher depreciation, depletion and amortization
rates. If the upward trend in finding and development costs
continues, we will be exposed to an increased likelihood of a write-down in
carrying value of our natural gas and oil properties in response to falling
commodity prices and reduced profitability of our operations.
Our
development and exploration operations require substantial capital, and we may
be unable to obtain needed capital or financing on satisfactory terms, which
could lead to a loss of properties and a decline in our natural gas and oil
reserves, and ultimately our profitability.
The
natural gas and oil industry is capital intensive. We expect to
continue to make substantial capital expenditures in our business and operations
for the exploration, development, production and acquisition of natural gas and
oil reserves. To date, we have financed capital expenditures
primarily with bank borrowings, cash generated by operations and our 2008 public
note issuance. We intend to finance our future capital expenditures
with cash flow from operations and our existing and planned financing
arrangements. Our cash flow from operations and access to capital is
subject to a number of variables, including:
• our
proved reserves;
• the
amount of natural gas and oil we are able to produce from existing
wells;
• the
prices at which natural gas and oil are sold;
• the
costs to produce oil and natural gas; and
• our
ability to acquire, locate and produce new reserves.
If our
revenues or the borrowing base under our credit facility decreases as a result
of lower natural gas and oil prices, operating difficulties, declines in
reserves or for any other reason, then we may have limited ability to obtain the
capital necessary to sustain our operations at current levels. We
may, from time to time, need to seek additional financing. There can
be no assurance as to the availability or terms of any additional
financing.
If
our revenues or the borrowing base under our revolving credit facility decrease
as a result of lower natural gas and oil prices, or we incur operating
difficulties, declines in reserves or for any other reason, we may have limited
ability to obtain the capital necessary to sustain our operations at planned
levels, and our profitability may be adversely affected.
If
additional capital is needed, we may not be able to obtain debt or equity
financing on favorable terms, or at all. If cash generated by our
operations or sale of drilling partnerships or available under our revolving
credit facility is not sufficient to meet our capital requirements, failure to
obtain additional financing could result in a curtailment of the exploration and
development of our prospects, which in turn could lead to a possible loss of
properties, decline in natural gas and oil reserves and a decline in our
profitability.
Seasonal
weather conditions and lease stipulations adversely affect our ability to
conduct drilling activities in some of the areas where we operate.
Seasonal
weather conditions and lease stipulations designed to protect various wildlife
affect natural gas and oil operations in the Rocky Mountains. In
certain areas, including parts of the Piceance Basin in Colorado, drilling and
other natural gas and oil activities are restricted or prohibited by lease
stipulations, or prevented by weather conditions, for up to six months out of
the year. This limits our operations in those areas and can intensify
competition during those months for drilling rigs, oil field equipment,
services, supplies and qualified personnel, which may lead to periodic
shortages. These constraints and the resulting shortages or high
costs could delay our operations and materially increase operating and capital
costs and therefore adversely affect our profitability.
We
have limited control over activities on properties in which we own an interest
but we do not operate, which could reduce our production and
revenues.
We
operate most of the wells in which we own an interest. However, there
are some wells we do not operate because we participate through joint operating
agreements under which we own partial interests in natural gas and oil
properties operated by other entities. If we do not operate the
properties in which we own an interest, we do not have control over normal
operating procedures, expenditures or future development of underlying
properties. The failure of an operator to adequately perform
operations, or an operator’s breach of the applicable agreements, could reduce
production and revenues and affect our profitability. The success and
timing of drilling and development activities on properties operated by others
therefore depends upon a number of factors outside of our control, including the
operator’s timing and amount of capital expenditures, expertise (including
safety and environmental compliance) and financial resources, inclusion of other
participants in drilling wells, and use of technology.
Market
conditions or operational impediments could hinder our access to natural gas and
oil markets or delay production.
Market
conditions or the unavailability of satisfactory natural gas and oil
transportation arrangements may hinder our access to natural gas and oil markets
or delay our production. The availability of a ready market for
natural gas and oil production depends on a number of factors, including the
demand for and supply of natural gas and oil and the proximity of reserves to
pipelines and terminal facilities. Our ability to market our
production depends in substantial part on the availability and capacity of
gathering systems, pipelines and processing facilities owned and operated by
third parties. Failure to obtain such services on acceptable terms
could materially harm our business. We may be required to shut in
wells for lack of market or because of inadequacy, unavailability or the pricing
associated with natural gas pipeline, gathering system capacity or processing
facilities. If that were to occur, we would be unable to realize
revenue from those wells until we made production arrangements to deliver the
product to market. Thus, our profitability would be adversely
affected.
Our
derivative activities could result in financial losses or reduced income from
failure to perform by our counterparties or from changes in
prices.
We use
derivatives for a portion of our natural gas and oil production from our own
wells, our partnerships and for natural gas purchases and sales by our marketing
subsidiary to achieve a more predictable cash flow, to reduce exposure to
adverse fluctuations in the prices of natural gas and oil, and to allow our
natural gas marketing company to offer pricing options to natural gas sellers
and purchasers. These arrangements expose us to the risk of financial loss in
some circumstances, including when purchases or sales are different than
expected, the counter-party to the derivative contract defaults on its contract
obligations, or when there is a change in the expected differential between the
underlying price in the derivative agreement and actual prices that we
receive.
In
addition, derivative arrangements may limit the benefit from changes in the
prices for natural gas and oil and may require the use of our resources to meet
cash margin requirements. Since our derivatives do not currently
qualify for use of hedge accounting, changes in the fair value of derivatives
are recorded in our income statements, and our net income is subject to greater
volatility than if our derivative instruments qualified for hedge
accounting. For instance, if oil and gas prices rise significantly,
it could result in significant non-cash charges each quarter, which could have a
material negative effect on our net income.
The
inability of one or more of our customers to meet their obligations may
adversely affect our financial results.
Substantially
all of our accounts receivable result from natural gas and oil sales or joint
interest billings to a small number of third parties in the energy
industry. This concentration of customers and joint interest owners
may affect our overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions. In addition,
our natural gas and oil derivatives as well as the derivatives used by our
marketing subsidiary expose us to credit risk in the event of nonperformance by
counterparties.
Terrorist
attacks or similar hostilities may adversely affect our results of
operations.
Increasing
terrorist attacks around the world have created many economic and political
uncertainties, some of which may materially adversely affect our
business. Uncertainty surrounding military strikes or a sustained
military campaign may affect our operations in unpredictable ways, including
disruptions of fuel supplies and markets, particularly oil, and the possibility
that infrastructure facilities, including pipelines, production facilities,
processing plants and refineries, could be direct targets of, or indirect
casualties of, an act of terror or war. The continuation of these
attacks may subject our operations to increased risks and, depending on their
ultimate magnitude, could have a material adverse effect on our business,
results of operations, financial condition and prospects.
Our
insurance coverage may not be sufficient to cover some liabilities or losses
that we may incur.
The
occurrence of a significant accident or other event not fully covered by
insurance could have a material adverse effect on our operations and financial
condition. Insurance does not protect us against all operational
risks. We do not carry business interruption insurance at levels that
would provide enough funds for us to continue operating without access to other
funds. For some risks, such as drilling blow-out insurance, we may
not obtain insurance if we believe the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and
environmental risks that we are subject to are generally not fully
insurable.
We
may not be able to keep pace with technological developments in our
industry.
The
natural gas and oil industry is characterized by rapid and significant
technological advancements and introductions of new products and services using
new technologies. As our competitors use or develop new technologies,
we may be placed at a competitive disadvantage, and competitive pressures may
force us to implement those new technologies at substantial cost. In
addition, other natural gas and oil companies may have greater financial,
technical and personnel resources that allow them to enjoy technological
advantages and may in the future allow them to implement new technologies before
we can. We may not be able to respond to these competitive pressures
and implement new technologies on a timely basis or at an acceptable
cost. If one or more of the technologies we use now or in the future
were to become obsolete or if we were unable to use the most advanced
commercially available technology, our business, financial condition and results
of operations could be materially adversely affected.
Competition
in the natural gas and oil industry is intense, which may adversely affect our
ability to succeed.
The
natural gas and oil industry is intensely competitive, and we compete with other
companies that have greater resources. Many of these companies not
only explore for and produce natural gas and oil, but also carry on refining
operations and market petroleum and other products on a regional, national or
worldwide basis. These companies may be able to pay more for
productive natural gas and oil properties and exploratory prospects or define,
evaluate, bid for and purchase a greater number of properties and prospects than
we can. In addition, these companies may have a greater ability to
continue exploration activities during periods of low natural gas and oil market
prices. Larger competitors may be able to absorb the burden of
present and future federal, state, local and other laws and regulations more
easily than we can, which can adversely affect our competitive
position. Our ability to acquire additional properties and to
discover reserves in the future will be dependent upon our ability to evaluate
and select suitable properties and to consummate transactions in a highly
competitive environment. In addition, because many companies in our
industry have greater financial and human resources, we may be at a disadvantage
in bidding for exploratory prospects and producing natural gas and oil
properties. These factors could adversely affect the success of our
operations and our profitability.
We
are subject to complex federal, state, local and other laws and regulations that
could adversely affect the cost, manner or feasibility of doing
business.
Our
exploration, development, production and marketing operations are regulated
extensively at the federal, state and local levels. Environmental and other
governmental laws and regulations have increased the costs to plan, design,
drill, install, operate and abandon natural gas and oil wells. Under
these laws and regulations, we could also be liable for personal injuries,
property damage and other damages. Failure to comply with these laws
and regulations may result in the suspension or termination of operations and
subject us to administrative, civil and criminal penalties. Moreover,
public interest in environmental protection has increased in recent years, and
environmental organizations have opposed, with some success, certain drilling
projects.
Part of
the regulatory environment includes federal requirements for obtaining
environmental assessments, environmental impact studies and/or plans of
development before commencing exploration and production
activities. In addition, our activities are subject to the regulation
by natural gas and oil-producing states of conservation practices and protection
of correlative rights. These regulations affect our operations,
increase our costs of exploration and production and limit the quantity of
natural gas and oil that we can produce and market. A major risk
inherent in our drilling plans is the need to obtain drilling permits from state
and local authorities. Delays in obtaining regulatory approvals,
drilling permits, the failure to obtain a drilling permit for a well or the
receipt of a permit with unreasonable conditions or costs could have a material
adverse effect on our ability to explore on or develop our
properties. Additionally, the natural gas and oil regulatory
environment could change in ways that might substantially increase our financial
and managerial costs to comply with the requirements of these laws and
regulations and, consequently, adversely affect our
profitability. Furthermore, these additional costs may put us at a
competitive disadvantage compared to larger companies in the industry which can
spread such additional costs over a greater number of wells and larger operating
staff.
Illustrative
of these risks are regulations recently enacted by the State of Colorado which
focus on the oil and gas industry. These multi-faceted proposed
regulations significantly enhance requirements regarding oil and gas permitting,
environmental requirements, and wildlife protection. Permitting
delays and increased costs could result from these final
regulations.
Litigation
has been commenced against us pertaining to our royalty practices and payments;
the cost of our defending these lawsuits, and any future similar lawsuit, could
be significant and any resulting judgments against us could have a material
adverse effect upon our financial condition.
In recent
years, litigation has commenced against us and several other companies in our
industry regarding royalty practices and payments in jurisdictions where we
conduct business. For more information on the suits that currently
relate to us, see Item
3, Legal
Proceedings. We intend to defend ourselves vigorously in these
cases. Even if the ultimate outcome of this litigation resulted in
our dismissal, defense costs could be significant. These costs would
be reflected in terms of dollar outlay as well as the amount of time, attention
and other resources that our management would have to appropriate to the
defense. Although we cannot predict an eventual outcome of this
litigation, a judgment in favor of a plaintiff could have a material adverse
effect on our financial condition.
Any
future failure to maintain effective internal control over financial reporting
and/or effective disclosure controls and procedures could have a material
adverse effect on the reliability of our financial statements and our ability to
file public reports on time, raise capital and meet our debt
obligations.
Our management assessed the
effectiveness of our internal control over financial reporting as of December
31, 2008, and pursuant to this assessment, concluded that we did maintain
effective internal control over financial reporting as of December 31,
2008. However, for each of the years in the three-year period ended
December 31, 2007, management’s assessment of the effectiveness of our internal
control over financial reporting identified several material weaknesses as
disclosed in our Annual Reports on Form 10-K for each of the years in the
three-year period then ended and filed with the SEC on March 20, 2008, May 23,
2007, and May 31, 2006, respectively. The existence of a material
weakness means there is a deficiency, or a combination of deficiencies, in
internal control over financial reporting, such that there is a reasonable
possibility that a material misstatement of our annual or interim financial
statements will not be prevented or detected on a timely basis.
Any future failure to maintain
effective internal control over financial reporting and/or effective disclosure
controls and procedures could prevent us from being able to prevent fraud and/or
provide reliable financial statements and other public reports. Such
circumstances could harm our business and operating results, cause investors to
lose confidence in the accuracy and completeness of our financial statements and
reports, and have a material adverse effect on the trading price of our debt and
equity securities and our ability to raise capital necessary for our
operations. These failures may also adversely affect our ability to
file our periodic reports with the SEC on time. Being late in
filing our periodic reports with the SEC may result in the delisting of our
common stock from the NASDAQ Stock Market or a default under our senior credit
agreement, the indenture governing our outstanding 12% senior notes due 2018,
and any other instruments governing debt that we may incur in the
future. Ultimately, such defaults could lead to the acceleration of
our debt obligations, and if an acceleration of our debt obligations were to
occur, we may not have sufficient funds to repay those obligations immediately,
and we would be forced to seek alternative repayment arrangements either through
a bankruptcy or an out of court debt restructuring. Consequently, a
future material weakness could lead to significant and negative changes to our
financial condition and the value of our equity and debt
securities.
Risks
Associated with Our Indebtedness
Our
credit facility has substantial restrictions and financial covenants and we may
have difficulty obtaining additional credit, which could adversely affect our
operations. Our lenders can unilaterally reduce our borrowing
availability based on anticipated sustained oil and natural gas
prices.
We depend
on our revolving credit facility for future capital needs. The terms
of the borrowing agreement require us to comply with certain financial covenants
and ratios. Our ability to comply with these restrictions and
covenants in the future is uncertain and will be affected by the levels of cash
flows from operations and events or circumstances beyond our
control. Our failure to comply with any of the restrictions and
covenants under the revolving credit facility or other debt financing could
result in a default under those facilities, which could cause all of our
existing indebtedness to be immediately due and payable.
The
revolving credit facility limits the amounts we can borrow to a borrowing base
amount, determined by the lenders in their sole discretion based upon projected
revenues from the natural gas and oil properties securing their
loan. The lenders can unilaterally adjust the borrowing base and the
borrowings permitted to be outstanding under the revolving credit
facility. Outstanding borrowings in excess of the borrowing base must
be repaid immediately, or we must pledge other natural gas and oil properties as
additional collateral. We do not currently have any substantial unpledged
properties, and we may not have the financial resources in the future to make
any mandatory principal prepayments required under the revolving credit
facility. Our inability to borrow additional funds under our credit
facility could adversely affect our operations.
The
indenture governing our outstanding senior notes and our senior credit agreement
impose (and we anticipate that the indentures governing any other debt
securities we may issue will also impose) restrictions on us that may limit the
discretion of management in operating our business. That, in turn, could impair
our ability to meet our obligations.
The
indenture governing our outstanding senior notes and our senior credit agreement
contain (and we anticipate that the indentures governing any other debt
securities we may issue will also contain) various restrictive covenants that
limit management’s discretion in operating our business. In
particular, these covenants limit our ability to, among other
things:
• 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;
• enter
into transactions with affiliates; and
• merge
or consolidate with another company.
These
covenants could materially and adversely affect our ability to finance our
future operations or capital needs. Furthermore, they may restrict
our ability to expand, to pursue our business strategies and otherwise conduct
our business. Our ability to comply with these covenants may be
affected by circumstances and events beyond our control, such as prevailing
economic conditions and changes in regulations, and we cannot assure you that we
will be able to comply with them. A breach of any of these covenants
could result in a default under the indenture governing our outstanding senior
notes and any other debt securities we may issue in the future and/or our senior
credit agreement. If there were an event of default under our
indenture and/or the senior credit agreement, the affected creditors could cause
all amounts borrowed under these instruments to be due and payable
immediately. Additionally, if we fail to repay indebtedness under our
senior credit agreement when it becomes due, the lenders under the senior credit
agreement could proceed against the assets which we have pledged to them as
security. Our assets and cash flow might not be sufficient to repay
our outstanding debt in the event of a default. The occurrence of
such an event would adversely affect our operations and
profitability.
Our
senior credit agreement also requires us to maintain specified financial ratios
and satisfy certain financial tests. Our ability to maintain or meet
such financial ratios and tests may be affected by events beyond our control,
including changes in general economic and business conditions, and we cannot
assure you that we will maintain or meet such ratios and tests, or that the
lenders under the senior credit agreement will waive any failure to meet such
ratios or tests.
In
addition, upon a change in control, we are required to offer to buy each senior
note for 101% of the principal amount, plus unpaid interest. A change
in control is defined to include: (i) when a majority of the Board of
Directors are not continuing directors; (ii) when one person (or group of
related persons) holds direct or indirect ownership of over 50% of our voting
stock; or (iii) upon sale, transfer or lease of substantially all of our
assets.
We
may incur additional indebtedness to facilitate our acquisition of additional
properties, which would increase our leverage and could negatively affect our
business or financial condition.
Our
business strategy includes the acquisition of additional properties that we
believe would have a positive effect on our current business and
operations. We expect to continue to pursue acquisitions of such
properties and may incur additional indebtedness to finance the
acquisitions. Our incurrence of additional indebtedness would
increase our leverage and our interest expense, which could have a negative
effect on our business or financial condition.
If
we fail to obtain additional financing, we may be unable to refinance our
existing debt, expand our current operations or acquire new businesses. This
could result in our failure to grow in accordance with our plans, or could
result in defaults in our obligations under our senior credit agreement or the
indenture relating to our outstanding senior notes.
In order
to refinance indebtedness, expand existing operations and acquire additional
businesses or properties, we will require substantial amounts of
capital. There can be no assurance that financing, whether from
equity or debt financings or other sources, will be available or, if available,
will be on terms satisfactory to us. If we are unable to obtain such
financing, we will be unable to acquire additional businesses or properties and
may be unable to meet our obligations under our senior credit agreement and the
indenture relating to our outstanding senior notes or any other debt securities
we may issue in the future. Such an event would adversely affect our
operations and profitability.
None.
Information
regarding our wells, production, proved reserves and acreage are included in
Item 1 and in Note
1, Summary of
Significant Accounting Policies, to our consolidated financial statements
included in this report.
Substantially
all of our oil and natural gas properties have been mortgaged or pledged as
security for our credit facility. See Note 6, Long Term Debt, to our
accompanying consolidated financial statements included in this
report.
Facilities
We own
our 32,000 square feet corporate office building located in Bridgeport, West
Virginia. We lease approximately 5,000 and 17,000 square feet of
office space in two buildings near our current corporate office through March
2010 and November 2011, respectively. We lease 15,700 square feet of
office space in downtown Denver, Colorado through March 2012, which effective
March 1, 2009, will become our corporate headquarters.
We own or
lease field operating facilities in the following locations:
|
·
|
West
Virginia: Bridgeport, Glenville and West
Union
|
|
·
|
Colorado: Evans,
Parachute and Wray
|
|
·
|
Pennsylvania: Indiana
and Mahaffey
|
Information regarding our legal proceedings can be found in Note 8, Commitments and Contingencies –
Litigation and Note 17, Subsequent Events, to our
consolidated financial statements included in this report.
None.
PART
II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY,
RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES.
Our
authorized capital stock consists of 100,000,000 shares of common stock, par
value $0.01 per share. Our common stock is traded on the NASDAQ
Global Select Market under the ticker symbol PETD.
The
following table sets forth the range of high and low sales prices for our common
stock as reported on the NASDAQ Global Select Market for the periods indicated
below.
|
|
High
|
|
|
Low
|
|
2008
|
|
|
|
|
|
|
First
Quarter
|
|
$ |
73.92 |
|
|
$ |
50.75 |
|
Second
Quarter
|
|
|
79.09 |
|
|
|
66.37 |
|
Third
Quarter
|
|
|
68.76 |
|
|
|
34.15 |
|
Fourth
Quarter
|
|
|
44.75 |
|
|
|
11.50 |
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
$ |
55.20 |
|
|
$ |
40.53 |
|
Second
Quarter
|
|
|
55.24 |
|
|
|
44.59 |
|
Third
Quarter
|
|
|
51.13 |
|
|
|
35.73 |
|
Fourth
Quarter
|
|
|
61.91 |
|
|
|
41.65 |
|
As of
February 23, 2009, we had approximately 1,107 shareholders of
record.
We
have not paid any dividends on our common stock and currently intend to retain
earnings for use in our business. We do not expect to declare cash
dividends in the foreseeable future.
The
following table presents information about our purchases of our common stock
during the three months ended December 31, 2008.
Period
|
|
Total Number of
Shares Purchased (1)
|
|
|
Average Price Paid per
Share
|
|
|
Total Number of
Shares Purchased as Part of Publicly Announced Plans or
Programs
|
|
|
Maximum Number of Shares that May Yet Be Purchased
Under the Plans or Programs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October
1 - 31, 2008
|
|
|
118 |
|
|
$ |
20.71 |
|
|
|
- |
|
|
|
- |
|
November
1-30, 2008
|
|
|
351 |
|
|
|
15.74 |
|
|
|
- |
|
|
|
- |
|
December
1-31, 2008
|
|
|
827 |
|
|
|
24.88 |
|
|
|
- |
|
|
|
- |
|
Total
fourth quarter purchases
|
|
|
1,296 |
|
|
|
22.02 |
|
|
|
|
|
|
|
|
|
______________
|
(1)
|
Pursuant
to our stock-based compensation plans, the 1,296 shares purchased
during the quarter represent purchases from our employees for their
payment of tax liabilities related to the vesting of
securities.
|
On
October 16, 2006, our Board of Directors approved a share purchase program
authorizing us to purchase up to 10% of our then outstanding common stock
(1,477,109 shares) through April 2008. There were 1,465,089 shares
that were authorized but not yet purchased as of December 31,
2007. Total shares purchased in 2008 pursuant to the program were
64,263 common shares at a cost of $4.4 million ($67.97 average price paid per
share), including 63,756 shares from our executive officers at a cost of $4.3
million ($67.98 price paid per share). Shares purchased from
employees, excluding executive officers, were generally purchased at fair market
value based on the closing price on the date of purchase and were primarily
purchased to satisfy the statutory minimum tax withholding requirement for
restricted stock that vested in 2008. Shares purchased from executive
officers were primarily pursuant to a separation agreement with our former
president and to satisfy the statutory minimum tax withholding requirements for
shares vested in 2008. The authorization to purchase the remaining
1,400,826 shares effectively expired on April 30, 2008. All shares
purchased in accordance with the program have been subsequently
retired.
SHAREHOLDER
PERFORMANCE GRAPH
The
performance graph below compares the cumulative total return of our common stock
over a five year period ended December 31, 2008, with the cumulative total
returns for the same period for a Standard Industrial Code Index, or SIC, and
the Standard and Poor's, or S&P, 500 Index. The SIC Code Index is
a weighted composite of 158 crude petroleum and natural gas
companies. The cumulative total shareholder return assumes that $100
was invested, including reinvestment of dividends, if any, in our common stock
on December 31, 2003, and in the S&P 500 Index and the SIC Code Index on the
same date. The results shown in the graph below are not necessarily
indicative of future performance.
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
PETROLEUM
DEVELOPMENT CORPORATION
|
|
$ |
100 |
|
|
$ |
163 |
|
|
$ |
141 |
|
|
$ |
182 |
|
|
$ |
249 |
|
|
$ |
102 |
|
SIC
CODE INDEX
|
|
|
100 |
|
|
|
127 |
|
|
|
183 |
|
|
|
237 |
|
|
|
334 |
|
|
|
195 |
|
S&P
500 INDEX
|
|
|
100 |
|
|
|
111 |
|
|
|
116 |
|
|
|
135 |
|
|
|
142 |
|
|
|
90 |
|
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(in
thousands, except per share data)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$ |
321,877 |
|
|
$ |
175,187 |
|
|
$ |
115,189 |
|
|
$ |
102,559 |
|
|
$ |
69,492 |
|
Sales
from natural gas marketing activities
|
|
|
140,263 |
|
|
|
103,624 |
|
|
|
131,325 |
|
|
|
121,104 |
|
|
|
94,627 |
|
Oil
and gas well drilling operations (1)
|
|
|
7,615 |
|
|
|
12,154 |
|
|
|
17,917 |
|
|
|
99,963 |
|
|
|
94,076 |
|
Well
operations and pipeline income
|
|
|
11,474 |
|
|
|
9,342 |
|
|
|
10,704 |
|
|
|
8,760 |
|
|
|
7,677 |
|
Oil
and gas price risk management gain (loss), net (2)
|
|
|
127,838 |
|
|
|
2,756 |
|
|
|
9,147 |
|
|
|
(9,368 |
) |
|
|
(3,085 |
) |
Other
|
|
|
293 |
|
|
|
2,172 |
|
|
|
2,221 |
|
|
|
2,180 |
|
|
|
1,696 |
|
Total
revenues
|
|
|
609,360 |
|
|
|
305,235 |
|
|
|
286,503 |
|
|
|
325,198 |
|
|
|
264,483 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas production and well operations costs
|
|
|
78,209 |
|
|
|
49,264 |
|
|
|
29,021 |
|
|
|
20,400 |
|
|
|
17,713 |
|
Cost
of natural gas marketing activities
|
|
|
139,234 |
|
|
|
100,584 |
|
|
|
130,150 |
|
|
|
119,644 |
|
|
|
92,881 |
|
Cost
of oil and gas well drilling operations (1)
|
|
|
2,213 |
|
|
|
2,508 |
|
|
|
12,617 |
|
|
|
88,185 |
|
|
|
77,696 |
|
Exploration
expense
|
|
|
45,105 |
|
|
|
23,551 |
|
|
|
8,131 |
|
|
|
11,115 |
|
|
|
- |
|
General
and administrative expense
|
|
|
37,715 |
|
|
|
30,968 |
|
|
|
19,047 |
|
|
|
6,960 |
|
|
|
4,506 |
|
Depreciation,
depletion and amortization
|
|
|
104,575 |
|
|
|
70,844 |
|
|
|
33,735 |
|
|
|
21,116 |
|
|
|
18,156 |
|
Total
costs and expenses
|
|
|
407,051 |
|
|
|
277,719 |
|
|
|
232,701 |
|
|
|
267,420 |
|
|
|
210,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
on sale of leaseholds (3)
|
|
|
- |
|
|
|
33,291 |
|
|
|
328,000 |
|
|
|
7,669 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from operations
|
|
|
202,309 |
|
|
|
60,807 |
|
|
|
381,802 |
|
|
|
65,447 |
|
|
|
53,531 |
|
Interest
income
|
|
|
591 |
|
|
|
2,662 |
|
|
|
8,050 |
|
|
|
898 |
|
|
|
185 |
|
Interest
expense
|
|
|
(28,132 |
) |
|
|
(9,279 |
) |
|
|
(2,443 |
) |
|
|
(217 |
) |
|
|
(238 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
174,768 |
|
|
|
54,190 |
|
|
|
387,409 |
|
|
|
66,128 |
|
|
|
53,478 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for income taxes
|
|
|
61,459 |
|
|
|
20,981 |
|
|
|
149,637 |
|
|
|
24,676 |
|
|
|
20,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
113,309 |
|
|
$ |
33,209 |
|
|
$ |
237,772 |
|
|
$ |
41,452 |
|
|
$ |
33,228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per common share
|
|
$ |
7.69 |
|
|
$ |
2.25 |
|
|
$ |
15.18 |
|
|
$ |
2.53 |
|
|
$ |
2.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per share
|
|
$ |
7.63 |
|
|
$ |
2.24 |
|
|
$ |
15.11 |
|
|
$ |
2.52 |
|
|
$ |
2.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$ |
1,402,704 |
|
|
$ |
1,050,479 |
|
|
$ |
884,287 |
|
|
$ |
444,361 |
|
|
$ |
329,453 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working
capital (deficit)
|
|
$ |
31,266 |
|
|
$ |
(50,212 |
) |
|
$ |
29,180 |
|
|
$ |
(16,763 |
) |
|
$ |
231 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
$ |
394,867 |
|
|
$ |
235,000 |
|
|
$ |
117,000 |
|
|
$ |
24,000 |
|
|
$ |
21,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders'
equity
|
|
$ |
511,581 |
|
|
$ |
395,526 |
|
|
$ |
360,144 |
|
|
$ |
188,265 |
|
|
$ |
154,021 |
|
______________
(1)
|
In
December 2005, we began entering into cost-plus drilling service
arrangements, which are recorded on a net basis unlike our footage based
arrangements which are recorded on a gross basis. See Note 1,
“Summary of Significant Accounting Policies,” to our accompanying
consolidated financial statements included in this
report. Further, we have not sponsored a drilling program since
August 2007, related revenue continued to be recognized through
2008.
|
(2)
|
See
Note 3,
“Derivative Financial Instruments”, to our accompanying consolidated
financial statements included in this
report.
|
(3)
|
In
July 2006, we sold a portion of our undeveloped leasehold located in Grand
Valley Field, Garfield County, Colorado. See Note 13, “Sale
of Oil and Gas Properties,” to our accompanying consolidated financial
statements included in this
report.
|
The
following discussion and analysis, as well as other sections in this Form 10-K,
should be read in conjunction with our accompanying consolidated financial
statements and related notes to consolidated financial statements included in
this report. Further, we encourage you to revisit Special Note Regarding
Forward-Looking Statements on page 1 of this
report.
2008
Overview
The year
2008 was a year of unprecedented events: oil and natural gas prices soared to
record and near record highs, respectively, through July; then, in the midst of
U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell
to their lowest in four years and natural gas prices dropped almost by
half. Our reaction to these events is one of
caution. While we certainly felt the impact of these events, we
believe that we were successful in managing our operations in such a manner that
we were able to minimize the negative impacts while capitalizing on the positive
impacts. Our strong derivative position eased the impact of the fall
in oil and natural gas prices. We exit 2008 with $7.6 million in net
realized derivative gains, $31.4 million in the fourth quarter
alone. Further, we estimate the net fair value of our derivative
positions, excluding the derivative positions attributed to our affiliated
partnerships, as of December 31, 2008, to be $117.8 million. See
2009 Outlook and Liquidity and Capital
Resources sections below for a discussion of the steps we plan to take in
this uncertain economic environment.
For the
second consecutive year, our net wells drilled increased double digits, up 20.7%
in 2008 from 2007, which was up 100.1% from 2006. The increased
drilling activity was fueled by the July 2006 sale of an undeveloped leasehold
located in Grand Valley Field, Garfield County, Colorado, providing us with cash
proceeds of $353.6 million and our February 2008 senior notes offering with net
proceeds of $196 million. We ended 2008 with interests in 4,712
gross, 3,259 net, wells located in the Rocky Mountain Region and the Appalachian
and Michigan Basins. In 2008, we recompleted 104 wells in the
Wattenberg Field and 21 wells in the Appalachian Basin.
The
decline in prices during the fourth quarter of 2008 has resulted in $118.4
million in unrealized gains on derivatives for the year ended December 31,
2008. The $118.4 million in unrealized gains for the year is the fair
value of the derivative positions as of December 31, 2008, less the related
unrealized amounts recorded in prior periods. An unrealized gain is a
non-cash item and there will be further gains or losses as prices decrease or
increase until the positions mature or are closed. While the required
accounting treatment for derivatives that do not qualify for hedge accounting
treatment under SFAS No. 133 may result in significant swings in operating
results over the life of the derivatives, the combination of the settled
derivative contracts and the revenue received from the oil and gas sales at
delivery are expected to result in a more predictable cash flow stream than
would the sales contracts without the associated derivatives.
The
average NYMEX and CIG prices for the next 24 months (forward curve) from the
respective dates below are as follows:
|
|
|
|
December 31,
|
|
|
June 30,
|
|
|
December 31,
|
|
|
February 13,
|
|
Commodity
|
|
Index
|
|
2007
|
|
|
2008
|
|
|
2008
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas:
|
|
NYMEX
|
|
$ |
8.12 |
|
|
$ |
12.52 |
|
|
$ |
6.62 |
|
|
$ |
5.87 |
|
|
|
CIG
|
|
|
6.78 |
|
|
|
8.86 |
|
|
|
4.49 |
|
|
|
4.13 |
|
Oil:
|
|
NYMEX
|
|
|
90.79 |
|
|
|
140.15 |
|
|
|
57.49 |
|
|
|
53.07 |
|
The
dramatic commodity price declines from June 30, 2008, through December 31, 2008,
relative to our current derivative positions, resulted in the significant
unrealized derivative gains in 2008. If there are further price
declines in 2009, unrealized derivatives gains on our current positions are
expected to continue.
2009
Outlook
We
project that our 2009 production will be approximately 44.4 Bcfe or a 15%
increase over 2008 production. Our 2009 capital budget of $120
million to $140 million represents an approximate 60% decrease compared to
2008. We selected this level of spending with the goal of remaining
debt neutral to help maintain adequate liquidity during 2009. We
realize that oil and gas prices may vary considerably from our
projections. We use oil and natural gas derivatives contracts in
order to reduce the effects of volatile commodity prices. As of
December 31, 2008, we had oil and natural gas hedges in place covering 52% of
our expected oil production and 62% of our expected natural gas production in
2009.
For 2009,
our drilling plans continue to be focused primarily in the Rocky Mountain
Region. We plan to drill approximately 166 gross wells, excluding
exploratory wells, of which 154 are in the Rocky Mountain Region and 12 are in
the Appalachian Basin. We are currently evaluating the exploration
potential of the Marcellus Formation in the Appalachian
Basin. Through a combination of lease, farmout and wellbore
ownership, we operate over 2,100 wells within the Marcellus “Fairway”
area. We currently have three wells drilled, two of which are in
line, and seven additional vertical tests are planned in 2009.
Due to
the continued decline in natural gas prices, in early 2009, we temporarily
ceased all of our drilling operations in the Piceance Basin, resulting in the
demobilization of the three contracted drilling rigs in this area. We
have included in our approved 2009 capital budget $40.4 million for drilling and
completion activities in the Piceance Basin. Should natural gas
prices change materially from the projected levels, we will reevaluate our
drilling options.
Results
of Operations
Summary
Operating Results
The
following table sets forth selected information regarding our results of
operations, including production volumes, oil and gas sales, average sales
prices received, average sales price including realized derivative gains and
losses, average lifting cost, other operating income and expenses for the years
ended December 31, 2008, 2007 and 2006.
|
|
Summary
Operating Results for the
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
2008-2007
|
|
|
|
2007-2006
|
|
Production (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Bbls)
|
|
|
1,160,408 |
|
|
|
910,052 |
|
|
|
631,395 |
|
|
|
27.5 |
% |
|
|
44.1 |
% |
Natural
gas (Mcf)
|
|
|
31,759,792 |
|
|
|
22,513,306 |
|
|
|
13,160,784 |
|
|
|
41.1 |
% |
|
|
71.1 |
% |
Natural
gas equivalent (Mcfe) (2)
|
|
|
38,722,240 |
|
|
|
27,973,618 |
|
|
|
16,949,154 |
|
|
|
38.4 |
% |
|
|
65.0 |
% |
Oil and Gas
Sales (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
sales
|
|
$ |
104,168 |
|
|
$ |
55,196 |
|
|
$ |
37,460 |
|
|
|
88.7 |
% |
|
|
47.3 |
% |
Gas
sales
|
|
|
221,734 |
|
|
|
119,991 |
|
|
|
77,729 |
|
|
|
84.8 |
% |
|
|
54.4 |
% |
Royalty
litigation provision
|
|
|
(4,025) |
|
|
|
- |
|
|
|
- |
|
|
|
* |
|
|
|
* |
|
Total
oil and gas sales
|
|
$ |
321,877 |
|
|
$ |
175,187 |
|
|
$ |
115,189 |
|
|
|
86.0 |
% |
|
|
52.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gain (Loss) on
Derivatives, net (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
derivatives - realized loss
|
|
$ |
(3,145 |
) |
|
$ |
(177 |
) |
|
$ |
- |
|
|
|
* |
|
|
|
* |
|
Natural
gas derivatives - realized gain
|
|
|
12,632 |
|
|
|
7,350 |
|
|
|
1,895 |
|
|
|
71.9 |
% |
|
|
* |
|
Total
realized gain on derivatives, net
|
|
$ |
9,487 |
|
|
$ |
7,173 |
|
|
$ |
1,895 |
|
|
|
32.3 |
% |
|
|
* |
|
Average
Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl) (3)
|
|
$ |
89.77 |
|
|
$ |
60.65 |
|
|
$ |
59.33 |
|
|
|
48.0 |
% |
|
|
2.2 |
% |
Natural
gas (per Mcf) (3)
|
|
$ |
6.98 |
|
|
$ |
5.33 |
|
|
$ |
5.91 |
|
|
|
31.0 |
% |
|
|
-9.8 |
% |
Natural
gas equivalent (per Mcfe)
|
|
$ |
8.42 |
|
|
$ |
6.26 |
|
|
$ |
6.80 |
|
|
|
34.4 |
% |
|
|
-7.9 |
% |
Average
Sales Price (including realized gain (loss) on
derivatives)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
87.06 |
|
|
$ |
60.46 |
|
|
$ |
59.33 |
|
|
|
44.0 |
% |
|
|
1.9 |
% |
Natural
gas (per Mcf)
|
|
$ |
7.38 |
|
|
$ |
5.66 |
|
|
$ |
6.05 |
|
|
|
30.5 |
% |
|
|
-6.5 |
% |
Natural
gas equivalent (per Mcfe)
|
|
$ |
8.66 |
|
|
$ |
6.52 |
|
|
$ |
6.91 |
|
|
|
32.9 |
% |
|
|
-5.6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Lifting Cost per
Mcfe (4)
|
|
$ |
1.07 |
|
|
$ |
0.90 |
|
|
$ |
0.76 |
|
|
|
18.9 |
% |
|
|
18.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Operating
Income(5) (in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas marketing activities
|
|
$ |
1,029 |
|
|
$ |
3,040 |
|
|
$ |
1,175 |
|
|
|
-66.2 |
% |
|
|
158.7 |
% |
Oil
and gas well drilling operations
|
|
$ |
5,402 |
|
|
$ |
9,646 |
|
|
$ |
5,300 |
|
|
|
-44.0 |
% |
|
|
82.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses (in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
expense
|
|
$ |
45,105 |
|
|
$ |
23,551 |
|
|
$ |
8,131 |
|
|
|
91.5 |
% |
|
|
189.6 |
% |
General
and administrative expense
|
|
$ |
37,715 |
|
|
$ |
30,968 |
|
|
$ |
19,047 |
|
|
|
21.8 |
% |
|
|
62.6 |
% |
Depreciation,
depletion and amortization
|
|
$ |
104,575 |
|
|
$ |
70,844 |
|
|
$ |
33,735 |
|
|
|
47.6 |
% |
|
|
110.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense (in
thousands)
|
|
$ |
28,132 |
|
|
$ |
9,279 |
|
|
$ |
2,443 |
|
|
|
203.2 |
% |
|
|
* |
|
|
*Percentage
change not meaningful or equal to or greater than
250%
|
Amounts
may not calculate due to
rounding
|
_______________
|
(1)
|
Production
is net and determined by multiplying the gross production volume of
properties in which we have an interest by the percentage of the leasehold
or other property interest we own.
|
|
(2)
|
A
ratio of energy content of natural gas and oil (six Mcf of natural gas
equals one Bbl of oil) was used to obtain a conversion factor to convert
oil production into equivalent Mcf of natural
gas.
|
|
(3)
|
We
utilize commodity based derivative instruments to manage a portion of our
exposure to price volatility of our natural gas and oil
sales. This amount excludes realized and unrealized gains and
losses on commodity based derivative
instruments.
|
|
(4)
|
Production
costs represent oil and gas operating expenses which exclude production
taxes.
|
|
(5)
|
Includes
revenues and operating
expenses.
|
Oil
and Gas Sales Activity
Oil
and Natural Gas Production and Sales Activity by Area
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
2008-2007
|
|
|
|
2007-2006
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
6,623 |
|
|
|
5,490 |
|
|
|
1,837 |
|
|
|
20.6 |
% |
|
|
198.9 |
% |
Michigan
Basin
|
|
|
3,469 |
|
|
|
4,301 |
|
|
|
4,439 |
|
|
|
-19.3 |
% |
|
|
-3.1 |
% |
Rocky
Mountain Region
|
|
|
1,150,316 |
|
|
|
900,261 |
|
|
|
625,119 |
|
|
|
27.8 |
% |
|
|
44.0 |
% |
Total
|
|
|
1,160,408 |
|
|
|
910,052 |
|
|
|
631,395 |
|
|
|
27.5 |
% |
|
|
44.1 |
% |
Natural
gas (Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
3,902,183 |
|
|
|
2,711,300 |
|
|
|
1,451,729 |
|
|
|
43.9 |
% |
|
|
86.8 |
% |
Michigan
Basin
|
|
|
1,609,984 |
|
|
|
1,678,155 |
|
|
|
1,399,852 |
|
|
|
-4.1 |
% |
|
|
19.9 |
% |
Rocky
Mountain Region
|
|
|
26,247,625 |
|
|
|
18,123,851 |
|
|
|
10,309,203 |
|
|
|
44.8 |
% |
|
|
75.8 |
% |
Total
|
|
|
31,759,792 |
|
|
|
22,513,306 |
|
|
|
13,160,784 |
|
|
|
41.1 |
% |
|
|
71.1 |
% |
Natural
gas equivalent (Mcfe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
3,941,921 |
|
|
|
2,744,240 |
|
|
|
1,462,751 |
|
|
|
43.6 |
% |
|
|
87.6 |
% |
Michigan
Basin
|
|
|
1,630,798 |
|
|
|
1,703,961 |
|
|
|
1,426,486 |
|
|
|
-4.3 |
% |
|
|
19.5 |
% |
Rocky
Mountain Region
|
|
|
33,149,521 |
|
|
|
23,525,417 |
|
|
|
14,059,917 |
|
|
|
40.9 |
% |
|
|
67.3 |
% |
Total
|
|
|
38,722,240 |
|
|
|
27,973,618 |
|
|
|
16,949,154 |
|
|
|
38.4 |
% |
|
|
65.0 |
% |
Average
Sales Price (excluding derivative gains/losses)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
$ |
88.80 |
|
|
$ |
59.08 |
|
|
$ |
60.14 |
|
|
|
50.3 |
% |
|
|
-1.8 |
% |
Michigan
Basin
|
|
|
100.79 |
|
|
|
68.31 |
|
|
|
61.07 |
|
|
|
47.5 |
% |
|
|
11.9 |
% |
Rocky
Mountain Region
|
|
|
89.73 |
|
|
|
60.62 |
|
|
|
59.31 |
|
|
|
48.0 |
% |
|
|
2.2 |
% |
Weighted
average price
|
|
|
89.77 |
|
|
|
60.65 |
|
|
|
59.33 |
|
|
|
48.0 |
% |
|
|
2.2 |
% |
Natural
gas (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
$ |
9.21 |
|
|
$ |
6.99 |
|
|
$ |
7.37 |
|
|
|
31.8 |
% |
|
|
-5.2 |
% |
Michigan
Basin
|
|
|
8.41 |
|
|
|
6.12 |
|
|
|
6.53 |
|
|
|
37.4 |
% |
|
|
-6.3 |
% |
Rocky
Mountain Region
|
|
|
6.57 |
|
|
|
5.01 |
|
|
|
5.62 |
|
|
|
31.1 |
% |
|
|
-10.9 |
% |
Weighted
average price
|
|
|
6.98 |
|
|
|
5.33 |
|
|
|
5.91 |
|
|
|
31.0 |
% |
|
|
-9.8 |
% |
Natural
gas equivalent (per Mcfe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
$ |
9.24 |
|
|
$ |
7.02 |
|
|
$ |
7.39 |
|
|
|
31.6 |
% |
|
|
-5.0 |
% |
Michigan
Basin
|
|
|
8.52 |
|
|
|
6.20 |
|
|
|
6.60 |
|
|
|
37.4 |
% |
|
|
-6.1 |
% |
Rocky
Mountain Region
|
|
|
8.32 |
|
|
|
6.18 |
|
|
|
6.75 |
|
|
|
34.6 |
% |
|
|
-8.4 |
% |
Weighted
average price
|
|
|
8.42 |
|
|
|
6.26 |
|
|
|
6.80 |
|
|
|
34.5 |
% |
|
|
-7.9 |
% |
Our oil
and natural gas sales revenues have increased in each of the past two years,
primarily due to increased volumes and higher average sales prices in 2008 and
increased volumes partially offset by lower average sales prices in
2007. Increased volumes contributed $90.5 million and $75 million to
the increase in oil and gas sales revenues in 2008 and 2007,
respectively. The increases in oil and natural gas volumes over the
past two years is attributable to the significant increase in the number of
wells drilled for our own account in 2008 and 2007 compared to those drilled in
prior years, and to a lesser extent, the acquisition of producing oil and gas
properties in the fourth quarter of 2006. The production volumes and
oil and gas sales revenue generated in 2007 from the acquisition of oil and gas
properties made in early 2007 and December 2006 and their subsequent development
were 6.5 Bcfe and $45.8 million, respectively.
Oil and Natural
Gas Pricing. Financial results depend
upon many factors, particularly the price of oil and natural gas and our ability
to market our production effectively. Oil and natural gas prices have
been among the most volatile of all commodity prices. These price
variations have a material impact on our financial results. Oil and
natural gas prices also vary by region and locality, depending upon the distance
to markets, and the supply and demand relationships in that region or
locality. This can be especially true in the Rocky Mountain
Region. The combination of increased drilling activity and the lack
of local markets have resulted in a local market oversupply situation from time
to time. Like most producers in the region, we rely on major
interstate pipeline companies to construct these facilities to increase pipeline
capacity, rendering the timing and availability of these facilities beyond our
control. Oil pricing is also driven strongly by supply and demand
relationships.
The price
we receive for a large portion of the natural gas produced in the Rocky Mountain
Region is based on a market basket of prices, which generally includes gas sold
at CIG prices as well as gas sold at Mid-Continent or other nearby region
prices. The CIG Index, and other indices for production delivered to
other Rocky Mountain pipelines, has historically been less than the price
received for natural gas produced in the eastern regions, which is NYMEX
based.
Although
82.6% of our 2008 natural gas production came from the Rocky Mountain Region,
much of our Rocky Mountain natural gas pricing is based upon other indices in
addition to CIG. The table below identifies the pricing basis of our
oil and natural gas pricing based on sales volumes for the year ended December
31, 2008. The pricing basis is the index that most closely relates to
the price under which our oil and natural gas is sold.
Energy
Market Exposure
|
as
of December 31, 2008
|
Area
|
|
Pricing
Basis
|
|
Commodity
|
|
Percent
of
Oil
and Gas
Sales
|
|
|
|
|
|
|
|
|
|
Piceance/Wattenberg
|
|
Colorado
Interstate Gas (CIG)
|
|
Gas
|
|
|
39%
|
|
Colorado/North
Dakota
|
|
NYMEX
|
|
Oil
|
|
|
16%
|
|
NECO
|
|
Mid
Continent (Panhandle Eastern)
|
|
Gas
|
|
|
12%
|
|
Piceance
|
|
San
Juan Basin/Southern California
|
|
Gas
|
|
|
16%
|
|
Appalachian
|
|
NYMEX
|
|
Gas
|
|
|
10%
|
|
Michigan
|
|
Mich-Con/NYMEX
|
|
Gas
|
|
|
4%
|
|
Wattenberg
|
|
Colorado
Liquids
|
|
Gas
|
|
|
2%
|
|
Other
|
|
Other
|
|
Gas/Oil
|
|
|
1%
|
|
|
|
|
|
|
|
|
100%
|
|
Lifting
Costs. Lifting costs per
Mcfe,
excluding production taxes which fluctuate with oil and natural gas prices, have
increased approximately 18% annually since 2006, an increase of approximately
41% from 2006 to 2008. The increase is primarily due to general oil
field services and wage inflation pressures. As production volumes
increase when we add new wells, we can expect to see modest decreases in lifting
costs as we work on improving and stabilizing our lifting costs. In
our Rocky Mountain Region, we traditionally experience higher lifting costs due
to severe winter conditions for costs such as snow removal from well and access
roads, along with other weather related problems.
Oil and Gas
Production and Well Operations Costs. In addition to increased
production and the significant number of new wells operated, the increase in oil
and gas production and well operations costs in each of the past two years is
also attributable to additional personnel in the production and engineering
staffs, increased maintenance and operating cost of the new pipeline and
compressor upgrades and improvements, increased production enhancements and
workovers
associated with the early 2007 and December 2006 acquisitions and significant
general oil field services inflation pressures. Oil and gas
production and well operations cost includes our lifting cost, production taxes,
the cost to operate wells and pipelines for our sponsored partnerships and other
third parties (whose income is included in well operations and pipeline income)
and certain production and engineering staff related overhead
costs. In October 2007, in conjunction with the acquisition of oil
and gas properties (762 wells) located in southwestern Pennsylvania, we acquired
a well services operation. The costs related to this operation are
included in the statement of operations line item Oil and Gas Production and well
Operations Costs.
Oil
and Gas Price Risk Management, Net
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
Oil
and gas price risk management, net:
|
|
|
|
|
|
|
|
|
|
Realized
gain (loss)
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$ |
(3,145 |
) |
|
$ |
(177 |
) |
|
$ |
- |
|
Natural
gas
|
|
|
12,632 |
|
|
|
7,350 |
|
|
|
1,895 |
|
Total
realized gain, net
|
|
|
9,487 |
|
|
|
7,173 |
|
|
|
1,895 |
|
Unrealized
gain (loss), net
|
|
|
118,351 |
|
|
|
(4,417 |
) |
|
|
7,252 |
|
|
|
$ |
127,838 |
|
|
$ |
2,756 |
|
|
$ |
9,147 |
|
Oil and
gas price risk management, net includes realized gains and losses and unrealized
changes in the fair value of oil and natural gas derivatives related to our oil
and natural gas production. Oil and gas price risk management, net
does not include commodity based derivative transactions related to transactions
from natural gas marketing activities, which are included in sales from and cost
of natural gas marketing activities. See Note 2, Fair Value of Financial
Instruments, and Note 3, Derivative Financial
Instruments, to the accompanying consolidated financial statements for
additional details of our derivative financial instruments.
Oil and
Gas Derivative Activities. We use various
derivative instruments to manage fluctuations in oil and natural gas
prices. We have in place a series of collars, fixed price swaps and
basis swaps on a portion of our oil and natural gas production. Under
the collar arrangements, if the applicable index rises above the ceiling price
or swap, we pay the counterparty; however, if the index drops below the floor or
swap, the counterparty pays us. Our production volumes for the
quarter ended December 31, 2008, were 326,000 Bbls of oil and 9.3 Bcf of natural
gas.
The
following table identifies our derivative positions (excluding the derivative
positions allocated to our affiliated partnerships) related to oil and gas sales
activities in effect as of December 31, 2008, on our production by
area. No new positions have been entered into subsequent to December
31, 2008, through the date of this filing.
|
|
|
Floors
|
|
|
Ceilings
|
|
|
Swaps
(Fixed Prices)
|
|
|
Basis
Swaps
|
|
|
|
|
Commodity/
Index/ Operating
Area
|
|
|
Quantity
(Gas-MMbtu Oil-Bbls)
|
|
|
Weighted
Average Contract
Price
|
|
|
Quantity
(Gas-MMbtu Oil-Bbls)
|
|
|
Weighted
Average Contract
Price
|
|
|
Quantity
(Gas-MMbtu Oil-Bbls)
|
|
|
Weighted
Average Contract
Price
|
|
|
Quantity
(Gas-MMbtu Oil-Bbls)
|
|
|
Weighted
Average Contract
Price
|
|
|
Fair
Value
at December 31,
2008
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CIG
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance
Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q
2009
|
|
|
|
- |
|
|
$ |
- |
|
|
|
- |
|
|
$ |
- |
|
|
|
2,388,158 |
|
|
$ |
8.08 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
9,340 |
|
2Q
2009
|
|
|
|
2,116,233 |
|
|
|
5.75 |
|
|
|
2,116,233 |
|
|
|
8.90 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,358 |
|
3Q
2009
|
|
|
|
2,116,233 |
|
|
|
5.75 |
|
|
|
2,116,233 |
|
|
|
8.90 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,523 |
|
4Q
2009
|
|
|
|
1,536,701 |
|
|
|
6.70 |
|
|
|
1,536,701 |
|
|
|
10.25 |
|
|
|
584,500 |
|
|
|
9.20 |
|
|
|
|
|
|
|
|
|
|
|
6,490 |
|
2010
|
|
|
|
1,672,131 |
|
|
|
6.80 |
|
|
|
1,672,131 |
|
|
|
10.90 |
|
|
|
876,751 |
|
|
|
9.20 |
|
|
|
4,274,703 |
|
|
|
1.88 |
|
|
|
7,788 |
|
2011
|
|
|
|
637,795 |
|
|
|
4.75 |
|
|
|
637,795 |
|
|
|
9.45 |
|
|
|
- |
|
|
|
- |
|
|
|
4,698,955 |
|
|
|
1.88 |
|
|
|
689 |
|
2012
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,733,113 |
|
|
|
1.88 |
|
|
|
(1,907 |
) |
2013
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,250,630 |
|
|
|
1.88 |
|
|
|
(2,846 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
Field
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,702,203 |
|
|
|
8.07 |
|
|
|
- |
|
|
|
- |
|
|
|
6,640 |
|
2Q
2009
|
|
|
|
1,524,639 |
|
|
|
5.75 |
|
|
|
1,524,639 |
|
|
|
8.89 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,140 |
|
3Q
2009
|
|
|
|
1,524,639 |
|
|
|
5.75 |
|
|
|
1,524,639 |
|
|
|
8.89 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,538 |
|
4Q
2009
|
|
|
|
1,119,322 |
|
|
|
6.71 |
|
|
|
1,119,322 |
|
|
|
10.26 |
|
|
|
424,381 |
|
|
|
9.20 |
|
|
|
- |
|
|
|
- |
|
|
|
4,725 |
|
2010
|
|
|
|
1,170,071 |
|
|
|
6.90 |
|
|
|
1,170,071 |
|
|
|
10.98 |
|
|
|
636,571 |
|
|
|
9.20 |
|
|
|
2,682,613 |
|
|
|
1.88 |
|
|
|
5,410 |
|
2011
|
|
|
|
380,112 |
|
|
|
4.75 |
|
|
|
380,112 |
|
|
|
9.45 |
|
|
|
- |
|
|
|
- |
|
|
|
2,951,819 |
|
|
|
1.88 |
|
|
|
429 |
|
2012
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,953,958 |
|
|
|
1.88 |
|
|
|
(1,190 |
) |
2013
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,637,419 |
|
|
|
1.88 |
|
|
|
(1,766 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PEPL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NECO
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
810,000 |
|
|
|
8.46 |
|
|
|
- |
|
|
|
- |
|
|
|
3,315 |
|
2Q
2009
|
|
|
|
720,000 |
|
|
|
6.14 |
|
|
|
720,000 |
|
|
|
10.81 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,332 |
|
3Q
2009
|
|
|
|
720,000 |
|
|
|
6.14 |
|
|
|
720,000 |
|
|
|
10.81 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
984 |
|
4Q
2009
|
|
|
|
580,000 |
|
|
|
7.81 |
|
|
|
580,000 |
|
|
|
12.68 |
|
|
|
240,000 |
|
|
|
10.91 |
|
|
|
- |
|
|
|
- |
|
|
|
2,669 |
|
2010
|
|
|
|
1,410,000 |
|
|
|
6.59 |
|
|
|
1,410,000 |
|
|
|
10.91 |
|
|
|
1,060,000 |
|
|
|
7.99 |
|
|
|
- |
|
|
|
- |
|
|
|
3,741 |
|
2011
|
|
|
|
300,000 |
|
|
|
6.00 |
|
|
|
300,000 |
|
|
|
10.10 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
and Michigan Basins
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q
2009
|
|
|
|
260,103 |
|
|
|
8.40 |
|
|
|
260,103 |
|
|
|
13.05 |
|
|
|
972,279 |
|
|
|
9.71 |
|
|
|
- |
|
|
|
- |
|
|
|
4,469 |
|
2Q
2009
|
|
|
|
905,212 |
|
|
|
7.13 |
|
|
|
905,212 |
|
|
|
12.85 |
|
|
|
429,743 |
|
|
|
9.09 |
|
|
|
- |
|
|
|
- |
|
|
|
2,836 |
|
3Q
2009
|
|
|
|
905,212 |
|
|
|
7.13 |
|
|
|
905,212 |
|
|
|
12.85 |
|
|
|
429,743 |
|
|
|
9.09 |
|
|
|
- |
|
|
|
- |
|
|
|
2,625 |
|
4Q
2009
|
|
|
|
868,186 |
|
|
|
9.00 |
|
|
|
868,186 |
|
|
|
15.66 |
|
|
|
429,457 |
|
|
|
9.09 |
|
|
|
- |
|
|
|
- |
|
|
|
3,367 |
|
2010
|
|
|
|
1,547,849 |
|
|
|
8.22 |
|
|
|
1,547,849 |
|
|
|
14.19 |
|
|
|
1,704,946 |
|
|
|
9.08 |
|
|
|
- |
|
|
|
- |
|
|
|
5,968 |
|
2011
|
|
|
|
232,277 |
|
|
|
6.75 |
|
|
|
232,277 |
|
|
|
12.13 |
|
|
|
800,844 |
|
|
|
9.60 |
|
|
|
- |
|
|
|
- |
|
|
|
1,731 |
|
2012
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
155,211 |
|
|
|
9.89 |
|
|
|
- |
|
|
|
- |
|
|
|
306 |
|
Total
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80,796 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Watenberg
Field
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
154,188 |
|
|
|
90.52 |
|
|
|
- |
|
|
|
- |
|
|
|
6,428 |
|
2Q
2009
|
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
155,903 |
|
|
|
90.52 |
|
|
|
- |
|
|
|
- |
|
|
|
5,729 |
|
3Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
157,615 |
|
|
|
90.52 |
|
|
|
- |
|
|
|
- |
|
|
|
5,291 |
|
4Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
157,615 |
|
|
|
90.52 |
|
|
|
- |
|
|
|
- |
|
|
|
4,856 |
|
2010
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
529,664 |
|
|
|
92.96 |
|
|
|
- |
|
|
|
- |
|
|
|
14,702 |
|
Total
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,006 |
|
Total
Natural Gas and Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
117,802 |
|
Natural
Gas Marketing Activities
The
increase in sales from natural gas marketing activities in 2008 compared to 2007
is primarily due to an increase in prices and increased unrealized gains on
derivative instruments. The increase in costs of natural gas
marketing activities in 2008 compared to 2007 is primarily due to an increase in
prices and increased unrealized losses on derivative instruments.
In 2008,
prices on sales and purchases were 31.8% higher on average than in 2007,
resulting in a $27.8 million increase in sales and costs. The sales
related unrealized gain on derivatives increased by $6.4 million and the cost of
sales related unrealized loss on derivatives increased by $6.9 million. Volumes
sold and purchased for resale decreased slightly by 2%.
The
decrease in sales from natural gas marketing activities in 2007 compared to 2006
is primarily due to a decrease in prices and volumes sold and a decrease in
unrealized gains on derivative instruments. The decrease in costs of
natural gas marketing activities in 2007 compared to 2006 is also due to a
decrease in prices and volumes purchased and a decrease in unrealized losses on
derivative instruments.
In 2007,
prices on sales and purchases were 5% lower on average than in 2006, resulting
in a $5 million decrease in sales and costs. In January 2007, we
acquired all of the outstanding partnership interests in 44 of our sponsored
drilling partnerships. Natural gas sales and purchases related to the
net 423 wells acquired no longer flowed through marketing activities; the result
was a decline in sales from and costs of natural gas marketing activities of
$12.2 million. This decline in partnership volumes was offset by an
increase in non-partnership volumes sold and purchased amounting to $3.7
million, for a net volume effect of an $8.5 million decrease compared to
2006. The gain on unrealized sales decreased $14 million from a $12.3
million gain in 2006 to a $1.7 million loss in 2007. The gain on
unrealized costs decreased $13.4 million from an $11.9 million loss in 2006 to a
$1.5 million gain in 2007.
Our
natural gas marketing segment specializes in the purchase, aggregation and sale
of natural gas production in our eastern operating areas. Through our
natural gas marketing segment, we market the natural gas we produce as well as
our purchases of natural gas from other producers in the Appalachian Basin,
including our affiliated partnerships. Our derivative activities
related to natural gas marketing activities include both physical and
cash-settled derivatives. We offer fixed-price derivative contracts
for the purchase or sale of physical gas and enter into cash-settled derivative
positions with counterparties in order to offset those same physical
positions. We do not take speculative positions on commodity
prices.
Natural Gas Marketing
Derivative Activities.
The
following table identifies our derivative positions related to our gas marketing
activities in effect as of December 31, 2008.
|
|
|
Floors
|
|
|
Ceilings
|
|
|
Swaps
(Fixed Prices)
|
|
|
Basis
Swaps
|
|
|
|
|
Commodity/
Derivative Instrument
|
|
|
Quantity
(Gas-MMbtu Oil-Bbls)
|
|
|
Weighted
Average Contract
Price
|
|
|
Quantity
(Gas-MMbtu Oil-Bbls)
|
|
|
Weighted
Average Contract
Price
|
|
|
Quantity
(Gas-MMbtu Oil-Bbls)
|
|
|
Weighted
Average Contract
Price
|
|
|
Quantity
(Gas-MMbtu Oil-Bbls)
|
|
|
Weighted
Average Contract
Price
|
|
|
Fair
Value
at December 31,
2008
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q
2009
|
|
|
|
20,000 |
|
|
$ |
6.50 |
|
|
|
- |
|
|
$ |
- |
|
|
|
112,400 |
|
|
$ |
8.59 |
|
|
|
290,021 |
|
|
$ |
0.37 |
|
|
$ |
230 |
|
2Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
43,132 |
|
|
|
9.20 |
|
|
|
72,493 |
|
|
|
0.29 |
|
|
|
119 |
|
3Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
31,320 |
|
|
|
9.55 |
|
|
|
66,578 |
|
|
|
0.29 |
|
|
|
88 |
|
4Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9,293 |
|
|
|
8.36 |
|
|
|
38,266 |
|
|
|
0.51 |
|
|
|
14 |
|
2010
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
15,610 |
|
|
|
8.45 |
|
|
|
30,410 |
|
|
|
0.80 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q
2009
|
|
|
|
20,000 |
|
|
|
6.50 |
|
|
|
- |
|
|
|
- |
|
|
|
152,400 |
|
|
|
7.31 |
|
|
|
- |
|
|
|
- |
|
|
|
(207 |
) |
2Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
43,132 |
|
|
|
8.11 |
|
|
|
- |
|
|
|
- |
|
|
|
(99 |
) |
3Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
31,191 |
|
|
|
8.48 |
|
|
|
- |
|
|
|
- |
|
|
|
(74 |
) |
4Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
29,293 |
|
|
|
10.77 |
|
|
|
- |
|
|
|
- |
|
|
|
(113 |
) |
2010
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
45,610 |
|
|
|
10.86 |
|
|
|
- |
|
|
|
- |
|
|
|
(157 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
10,000 |
|
|
|
10.30 |
|
|
|
580,900 |
|
|
|
9.13 |
|
|
|
226,665 |
|
|
|
0.32 |
|
|
|
1,879 |
|
2Q
2009
|
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
322,500 |
|
|
|
9.27 |
|
|
|
211,272 |
|
|
|
0.32 |
|
|
|
1,116 |
|
3Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
250,500 |
|
|
|
9.39 |
|
|
|
141,250 |
|
|
|
0.32 |
|
|
|
812 |
|
4Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
248,500 |
|
|
|
8.90 |
|
|
|
166,050 |
|
|
|
0.32 |
|
|
|
540 |
|
2010
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
695,000 |
|
|
|
8.71 |
|
|
|
- |
|
|
|
- |
|
|
|
1,040 |
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
150,000 |
|
|
|
8.44 |
|
|
|
- |
|
|
|
- |
|
|
|
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical
Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
10,000 |
|
|
|
10.30 |
|
|
|
581,395 |
|
|
|
9.29 |
|
|
|
46,935 |
|
|
|
0.32 |
|
|
|
(1,762 |
) |
2Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
322,995 |
|
|
|
9.44 |
|
|
|
46,874 |
|
|
|
0.32 |
|
|
|
(1,079 |
) |
3Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
250,995 |
|
|
|
9.56 |
|
|
|
46,752 |
|
|
|
0.32 |
|
|
|
(788 |
) |
4Q
2009
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
228,665 |
|
|
|
9.60 |
|
|
|
15,584 |
|
|
|
0.32 |
|
|
|
(597 |
) |
2010
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
665,000 |
|
|
|
9.14 |
|
|
|
- |
|
|
|
- |
|
|
|
(1,146 |
) |
2011
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
150,000 |
|
|
|
8.61 |
|
|
|
- |
|
|
|
- |
|
|
|
(125 |
) |
Total
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(165 |
) |
Oil
and Gas Well Drilling
The
decrease in oil and gas well drilling operations revenue was due to our decision
not to sponsor a drilling partnership in 2008 and our change from footage-based
drilling arrangements to cost-plus drilling arrangements, which have differing
revenue recognition presentations.
In
January 2008, we announced that we did not plan to sponsor new drilling
partnerships in 2008. In August 2007, we completed our only sponsored
drilling partnership offering in 2007. Drilling for the partnership
commenced during the third quarter of 2007. From inception to
December 31, 2008, $12.7 million in revenues had been recognized related to the
2007 drilling program. Advances for future drilling contracts held as
of December 31, 2008, will be used for completion activities to be conducted in
2009. Currently, we do not plan to sponsor a drilling partnership in
2009 or in the foreseeable future. Consequently, we anticipate that our oil and
gas drilling segment’s contribution to operating income, which was $5.4 million,
$9.6 million and $5.3 million in 2008, 2007 and 2006, respectively, will decline
substantially in 2009. Thereafter, our oil and gas well drilling
contribution to operating income will cease unless we undertake new drilling
ventures.
Beginning
with the last sponsored partnership in 2005 (for which revenue generating
activities began in 2006), our partnership wells have been drilled on a
“cost-plus” basis, which means that we charge the partnerships for the actual
cost of the wells plus an agreed upon mark-up above that cost. Prior
to that partnership, we had conducted most of our third-party drilling
activities on a footage basis, pursuant to which we drilled the wells for a
fixed price per foot drilled with additional chargeable items as provided for in
the drilling agreement. Our services provided under the cost-plus
drilling arrangements are reported net of recovered costs and reflected as
revenue in oil and gas well drilling operations, whereas the revenues under the
footage-based arrangements were recorded gross of related
expenses. For the year ended December 31, 2006, the oil and gas well
drilling segment’s results included $5.4 million in revenues and $10 million in
expenses related to footage based arrangements.
Well
Operations and Pipeline Income
In
January 2007, we acquired all of the outstanding partnership interests in 44 of
our sponsored drilling partnerships. Having acquired 423 net wells
pursuant to the acquisition, we no longer record income for operating these
wells and related pipelines. This decrease in revenue was offset in
part by an increase in the number of new wells drilled and placed in service and
pipeline systems we operate for our sponsored drilling partnerships as well as
third parties. In October 2007, in conjunction with the acquisition
of oil and gas properties located in southwestern Pennsylvania, we acquired a
well services operation. The revenues related to this operation are
included in the statement of operations line item Well Operations and Pipeline
Income.
Gain
on Sale of Leaseholds
In July
2006, we entered into a purchase and sale agreement with an unaffiliated party
regarding the sale of our undeveloped leasehold located in the Grand Valley
Field, Garfield County, Colorado, as filed with the Securities and Exchange
Commission, or SEC, as Exhibit 10.3 to Form 10-Q for the period ended September
30, 2006. Total proceeds from the sale were $353.6 million, of which
we recognized a $328 million gain on sale of leasehold in the third quarter of
2006.
In
May 2007, we entered into a letter agreement amending the above
mentioned purchase and sale agreement, relieving us of our obligation, in its
entirety, to either drill 16 wells or pay liquidated damages of $1.6 million per
undrilled well. As a result, we recognized the remaining deferred
gain of $25.6 million in the second quarter of 2007.
In
December 2007, we sold to the same unaffiliated party a portion of our North
Dakota properties for approximately $34.7 million. The properties,
located in Dunn, Williams and McKenzie Counties, North Dakota, include interests
in five producing Bakken wells and approximately 72,000 net undeveloped
acres. We recorded a gain on sale of leaseholds of $7.7 million in
the fourth quarter of 2007.
Other
Costs and Expenses
Exploration
Expense
The
following table sets forth the major components of exploration
expense.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Impairment
of proved oil and gas properties
|
|
$ |
12,825 |
|
|
$ |
- |
|
|
$ |
1,510 |
|
Amortization/impairment
of unproved properties
|
|
|
12,798 |
|
|
|
3,291 |
|
|
|
1,010 |
|
Exploratory
dry holes
|
|
|
7,675 |
|
|
|
4,187 |
|
|
|
1,790 |
|
Geological
and geophysical costs
|
|
|
2,121 |
|
|
|
6,299 |
|
|
|
2,234 |
|
|
|
|
35,419 |
|
|
|
13,777 |
|
|
|
6,544 |
|
Operating
and other
|
|
|
9,686 |
|
|
|
9,774 |
|
|
|
1,587 |
|
Total
exploration expense
|
|
$ |
45,105 |
|
|
$ |
23,551 |
|
|
$ |
8,131 |
|
We
expanded exploratory drilling activities in 2005 and have generally believed
that the additional risk and costs associated with exploratory drilling is
justified by the potential to generate additional proved
properties. However, we plan to reduce exploratory drilling in 2009
given the current economic conditions and focus primarily on development
activities in our proven fields.
We assess
our proved oil and gas properties for possible impairment by comparing net
capitalized costs to estimated undiscounted future net cash flows on a
field-by-field basis using estimated production based upon prices at which we
reasonably estimate the commodity to be sold. If net capitalized
costs exceed undiscounted future net cash flows, the measurement of impairment
is based on estimated fair value which would consider future discounted cash
flows. We assess our unproved oil and gas properties for possible
impairment by field based on our historical experience, current market data,
acquisition dates, average lease terms and the probability of being
drilled.
We
recognized impairment losses on proved oil and gas properties of $12.8 million
in 2008, consisting of $7.5 million related to our properties in the Fort Worth
Basin, $3 million in our Bakken Field in North Dakota and $2.3 million in our
Nesson Field, also in North Dakota. We also recognized
impairment losses of unproved properties of $12.9 million, consisting primarily
of $7.3 million related to our unproved properties in the Fort Worth Basin and
amortization of approximately $5.6 million related to all of our other areas of
operations. The $7.7 million of exploratory dry holes relates
primarily to two Michigan wells, one New York well and one Colorado
well.
In 2007,
exploration expense includes $2.7 million of liquidated damages associated with
the abandonment of an exploration agreement with an unaffiliated party and $1.1
million related to the write-off of the carrying value of the related acreage,
$6.3 million in geological and geophysical costs related to seismic evaluation
of various exploratory prospects and increased payroll and payroll related costs
and other exploratory department costs.
In 2006,
exploration expense includes $1.8 million related to one exploratory dry hole,
$1.5 million related to an impairment charge on our Nesson Field in North Dakota
and $2.2 million in geological and geophysical costs related to the seismic
evaluation of our Northeast Colorado properties.
General
and Administrative Expense
General
and administrative expense has increased for the third consecutive
year. However, 2008 is considered pivotal because the rate of
increase is declining and we expect this trend to continue in
2009. It is this trend that we expect to continue in
2009. General and administrative expenses have been declining on a
per Mcfe basis, from $1.12 per Mcfe in 2006 to $1.11 per Mcfe in 2007 and $0.97
per Mcfe in 2008.
The
increase in general and administrative expense in 2008 compared to 2007 was
primarily due to increased payroll and payroll related expenses, which includes
$4.7 million related to agreements with two former executive officers: $3.2
million related to a separation agreement with our former president and $1.5
million related to an agreement for the retirement of our former chief executive
officer. This increase was partially offset by a $2 million decrease
in audit fees and a decrease in various other general and administrative
expenses.
The
increase in general and administrative expense in 2007 compared to 2006 was
primarily due to increased costs related to increased payroll and payroll
related expenses, which includes stock-based compensation expense related to the
recruitment of professionals and key personnel in 2007. The increase
in management personnel is attributable to the growth we are experiencing, the
increase in the cost of recruiting and the higher compensation required to
obtain experienced oil and gas personnel. We also experienced higher
financial statement audit costs related to the late filing of our 2006 Form
10-K, higher compliance costs with the various provisions of the Sarbanes-Oxley
Act, increased accounting assistance from third party consulting services and
increased legal costs.
Depreciation,
Depletion and Amortization
DD&A expense
includes depreciation and amortization expense related of non-oil and natural
gas properties as well as oil and natural gas properties. DD&A
expense for non-oil and natural gas properties was $7.6 million, $4.3 million
and $2 million in 2008, 2007 and 2006, respectively. DD&A expense
related to oil and natural gas properties is directly related to reserves and
production volumes. DD&A expense is primarily based upon year-end
proved developed producing oil and gas reserves. These reserves are
priced at the price of oil and natural gas as of December 31 each
year. If prices increase, the corresponding volume of oil and gas
reserves will increase, resulting in decreases in the rate of DD&A per unit
of production. If prices decrease, as they did from 2007 to 2008,
volumes of oil and gas reserves will decrease resulting in increases in the rate
of DD&A per unit of production. See Note 18, Supplemental Oil and Gas Information
– Unaudited, to our accompanying consolidated financial statements, for
the average December 31 oil and natural gas prices used to determine year-end
reserves and other reserve information. The cost to acquire acreage,
drill, complete and equip new wells have risen significantly over the past five
years along with oil and natural gas prices and is a major contributing factor
for the increased DD&A rate in the table below:
DD&A
rates for our oil and gas properties are shown in the table below.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(per
Mcfe)
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin (1)
|
|
$ |
1.55 |
|
|
$ |
1.32 |
|
|
$ |
1.13 |
|
Michigan
Basin
|
|
|
1.35 |
|
|
|
1.28 |
|
|
|
0.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky
Mountain Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
Field
(2)
|
|
|
3.47 |
|
|
|
2.99 |
|
|
|
2.34 |
|
Piceance
Basin (3)
|
|
|
2.04 |
|
|
|
2.27 |
|
|
|
1.83 |
|
NECO
|
|
|
1.45 |
|
|
|
1.45 |
|
|
|
1.26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average
|
|
|
2.51 |
|
|
|
2.37 |
|
|
|
1.87 |
|
______________
|
(1)
|
The
increase in DD&A rate for the Appalachian Basin in 2008 was due to the
higher market price of a fourth quarter 2007 acquisition of 752 wells in
southwestern Pennsylvania and the new wells drilled in
2008.
|
|
(2)
|
Although
the Wattenberg Field development costs and DD&A rates are higher than
the other fields, the relative value of its oil production currently more
than offsets this cost difference. The Wattenberg Field has
produced volumes in excess of 85% of our total oil production in each of
the years in the three-year period ended December 31,
2008.
|
|
(3)
|
The
decrease in DD&A rates for the Piceance Basin in 2008 compared to 2007
is the result of higher year-end 2008 oil and natural gas reserves, due
primarily to the improvements in drilling and completion technology and
expanded pipeline and compression
capacity.
|
Non-Operating
Income/Expense
Interest
Income. The decreases in our interest income in 2008 and 2007
were the result of lower cash balances earning interest compared to
2006. In July 2006, we received $353.6 million in cash proceeds from
the sale of undeveloped leaseholds. These proceeds earned interest
income until reinvested in oil and gas properties in January 2007.
Interest
Expense. The increases in our interest expense were primarily
due to significantly higher average outstanding balances of our credit facility
and, in 2008, our 12% senior notes offset in part by lower average interest
rates in our bank credit facility. The average long-term debt in 2008
was $275.9 million compared to $132.5 million in
2007. Interest expense is net of capitalized
interest. Interest costs capitalized in 2008, 2007 and 2006 were $2.6
million, $3 million and $1.6 million, respectively. We have
historically utilized our daily cash balances to reduce our line of credit
borrowings, thereby lowering our interest costs.
Provision
for Income Taxes
Our 2008
effective income tax rate was 35.2% in 2008 compared to 38.7% in 2007 and 38.6%
in 2006. This reduced rate reflects second and third quarter discrete
benefits of $1.4 million for each period, related principally to the
implementation of state tax strategies during each respective
quarter. The impact of these strategies also affected our rate used
to establish deferred taxes and resulted in a deferred tax benefit of $1 million
in 2008.
Our
effective tax rate, excluding the effect of discrete items, for 2008 was 37.3%,
which was virtually unchanged from 2007 and slightly less than the 2006 rate of
38.4%. In 2008, the rate decreased primarily due to a 0.5% reduction
in our effective state tax rate due to the benefit being realized from our
implemented state tax planning strategies and a 0.7% reduction primarily related
to reduced tax penalties. However, these 2008 rate decreases were
offset by our permanent tax deductions resulting in a proportionately smaller
effective rate benefit of 0.8% compared to 1.8% in 2007. In 2006, our
permanent tax deduction for percentage depletion resulted in a proportionately
smaller tax rate benefit of only 0.1%.
Liquidity
and Capital Resources
Cash flow
from operations and our bank credit facility are the primary sources of
liquidity for us to satisfy our operating expenses and fund our capital
expenditures. We had $180.5 million of available borrowing capacity
under our $375 million bank credit facility as of December 31,
2008. Cash provided by operating activities was $139.1 million for
the current year period compared to $60.3 million in the prior year
period. The $78.8 million increase in the current year period was
primarily due to higher natural gas and oil prices through mid-2008 and higher
volumes of oil and natural gas production and realized derivative gains
primarily in the fourth quarter of 2008. Changes in cash flow from
operations are largely due to the same factors that affect our net income,
excluding non-cash items which are primarily depreciation, depletion and
amortization and unrealized gains and losses on derivative
transactions. See the discussion under Results of
Operations. Cash flow used in investing activities increased
$55.6 million, or 21%, from $267.4 million for the year ended 2007 to $323
million in 2008. Substantially all of our investing activity involved
drilling for oil and gas reserves during 2008. Cash flows provided
from financing activities increased $52.6 million, or 54%, from $97.5 million to
$150.1 million for the years ended December 31, 2007 and 2008,
respectively. This increase was primarily due to the increase in
proceeds from the issuance of our 12% senior notes of $200 million offset by net
repayments on our bank credit facility.
Changes
in market prices for oil and natural gas, our ability to increase production,
the impact of realized gains and losses on our oil and natural gas derivative
instruments and changes in costs are the principal determinants of the level of
our cash flow from operations. Oil and natural gas sales for the year
ended December 31, 2008, were approximately 85% higher than the prior year,
resulting from a 34% increase in average oil and natural gas prices and a 38%
increase in oil and natural gas production. While a decline in oil
and natural gas prices would affect the amount of cash from operations that
would be generated, we have oil and natural gas derivative positions in place,
as of the date of this filing, covering 52% of our expected oil production and
62% of our expected natural gas production in 2009, at average prices of $90.52
per Bbl and $7.25 per Mcf, respectively. These contracts reduce the
impact of price changes for a substantial portion of our 2009 cash from
operations.
Our
primary use of funds is for capital expenditures. As a result of the
current unstable conditions in the commodity and financial markets, we have
significantly reduced our planned 2009 capital expenditures to a range of $120
million to $140 million which represents an approximate 60% decrease from our
2008 capital expenditures. With this reduction, we estimate our 2009
production will increase by approximately 15% over 2008 in part due to increased
production from wells drilled in the latter part of 2008. We believe,
based on the current commodity price environment, our cash flow from operations
will fund our reduced 2009 capital spending program allowing us to remain debt
neutral during 2009. We expect to manage capital expenditures within
our cash flow from operations in 2009 and for the foreseeable future until
commodity prices and capital markets are more favorable. In order to
continue to maintain or grow our production, we will need to commit greater
amounts of capital in 2010 and beyond. If capital is not available or
is constrained in the future, we will be limited to our cash flow from
operations and liquidity under our credit facility as the sources of funding for
our capital expenditures. Oil and gas produced from our existing
properties declines rapidly in the first two years of production. We
could not maintain our current level of oil and gas production and cash flow
from operations if capital markets and commodity prices remain in their current
depressed state for a prolonged period beyond 2009, which would have a material
negative impact on our operations in 2010 and beyond.
We
considered the possibility of a reduced available liquidity environment in
planning our 2009 drilling program and believe we will have adequate cash flow
from operations during the year to execute our planned capital expenditures
without drawing additional funds from our credit facility. Currently,
we operate approximately 95% of our properties, allowing us to control the pace
of substantially all of our planned capital
expenditures. Consequently, a substantial portion of our planned
capital expenditures for 2009 and beyond could be deferred if market conditions
worsen.
In
addition to deferring capital expenditures to reduce borrowings under our credit
facility, other sources of liquidity include the fair value of our oil and
natural gas derivative positions, excluding the derivative positions attributed
to our affiliated partnerships, of $117.8 million as well as our available cash
balance which was $51 million as of December 31, 2008.
We have
one significant future drilling commitment along with certain volume delivery
requirements that will require us to expend $60 million in development drilling
on our Wattenberg leases through 2011, provided that our counterparty in the
agreement expands two gas processing facilities and maintains certain wellhead
pressures by June 30, 2010. Our 2009 capital expenditure plan
includes approximately $50 million related to this
commitment. Failure to meet our drilling commitment would result in a
maximum payment to the counterparty of $15 million in 2012; failure to meet our
volume delivery commitments by December 31, 2012, would result in a maximum
payment to the counterparty of $10 million in 2013. Failure of the
counterparty to complete the required plant expansions results in a waiver of
our $60 million capital and volume delivery requirements.
We have
experienced no impediments in our ability to access borrowings under our current
bank credit facility. We continue to monitor market events and circumstances and
their potential impacts on each of the thirteen lenders that comprise our bank
credit facility. Our $375 million bank credit facility borrowing base
is subject to size redeterminations each April and October based upon a
quantification of our proved reserves at each December 31st
and June 30th, respectively. A commodity price deck reflective of the
current and future commodity pricing environment is utilized by our lenders to
quantify our reserve reports and determine the underlying borrowing
base. We will be subject to a borrowing base redetermination in April
2009.
We
increased our borrowing base in July 2008, and again in November 2008, to $300
million and $375 million respectively. The increases were driven
primarily by increases in proved producing reserves from drilling
operations. While we have continued to add producing reserves since
our November 2008 redetermination, we believe the significant decrease in
commodity prices and turmoil in the credit markets could have a negative impact
on our borrowing base at our next redetermination in April 2009. Our
credit facility matures in November 2010, and is payable in full at that
time. We have begun discussions with our bank group with the intent
of renewing the credit facility prior to November 1, 2009. There is
no assurance all of the lenders in our credit facility will participate in the
renewal and there is no assurance that our borrowing base will not be reduced
from its current level as a result of the renewal or the loss of one or more
lenders in our credit facility. Further, costs of capital have
increased since we last amended our credit facility and we expect that interest
and commitment fees under a new facility will be higher than in our current
credit facility. See Note 6, Long Term Debt, to the
accompanying consolidated financial statements. At December 31, 2008,
we had $180.5 million available for borrowing under our $375 million credit
facility. While we believe our borrowing base could be reduced as a
result of redeterminations, we believe that producing reserves added since our
last redetermination and our oil and natural gas derivative positions in place
could mitigate the risk of a significant decrease in our borrowing base in
2009. We also believe that while costs of capital have increased for
credit facilities like ours, the impact of an increase in interest and
commitment fees on our outstanding balance and commitments will not have a
material adverse effect on our liquidity in 2009. Our credit facility
matures in November 2010. If economic conditions deteriorate further
in 2009 and 2010, our ability to renew our credit facility and provide adequate
liquidity to continue our drilling programs could be negatively impacted in 2010
and beyond.
We are
subject to quarterly financial debt covenants on our bank credit
facility. Our key credit facility debt covenants require that we
maintain: 1) total debt of less than 3.75 times earnings before interest, taxes,
depreciation, amortization and capital expenditures (“EBITDAX”) and 2) an
adjusted working capital ratio of at least 1.0 to 1.0. As of December
31, 2008, our total debt was 1.5 times EBITDAX and our adjusted working capital
ratio was 1.6 to
1.0. Our adjusted working capital ratio is calculated by reducing our
current assets and liabilities by any impact of recording the fair value of our
oil and gas derivative instruments and adding our available borrowings on our
bank credit facilities to our current assets. In addition, the impact
of any current portion of our debt is eliminated from the current
liabilities. Therefore, any change in our available borrowings under
our credit facility impacts our working capital ratio.
We
believe we have sufficient liquidity and capital resources to conduct our
business and remain compliant with our debt covenants throughout 2009 based upon
our 2009 cash flow projections, anticipated capital requirements, the
discretionary nature of our capital expenditures and available capacity under
our bank credit facility. While current conditions in the financial
markets are extremely difficult and illiquid, we have no current plans or
requirements to raise capital through these markets. However, we cannot predict
with any certainty the impact to our future business of any further disruption
or deterioration in the financial markets. We will continue to
closely monitor our liquidity and the credit markets and may choose to access
them opportunistically should conditions and capital market liquidity
improve.
We filed
a shelf registration statement on Form S-3 with the SEC on November 26, 2008.
The shelf provides for an aggregate of $500 million, through the sale of debt
securities, common stock or preferred stock, either separately or represented by
depository shares, warrants and purchase contracts, as well as units that may
include any of these securities or securities of other entities. The
shelf registration statement is intended to allow the Company to be proactive in
its ability to raise capital should the need arise, and to have the flexibility
to raise such funds in one or more offerings, subject to market
conditions. This shelf registration statement was declared effective
by the SEC on January 30, 2009. There are no immediate plans to raise
any funds and there is no assurance that we will be able to secure any such
funds should the need arise.
See Item
7A, Quantitative and
Qualitative Disclosure about Market Risk, for our discussion of credit
risk.
Contractual
Obligations and Contingent Commitments
The table
below sets forth our contractual obligations and contingent commitments as of
December 31, 2008:
|
|
Payments
due by period
|
|
Contractual
Obligations and Contingent Commitments (1)
|
|
Total
|
|
|
Less
than
1
year
|
|
|
1-3
years
|
|
|
3-5
years
|
|
|
More
than
5
years
|
|
|
|
(in
thousands)
|
|
Long-Term
Debt (2)
|
|
$ |
394,867 |
|
|
$ |
- |
|
|
$ |
194,500 |
|
|
$ |
- |
|
|
$ |
200,367 |
|
Interest on
long-term debt(2)
|
|
|
238,955 |
|
|
|
33,398 |
|
|
|
56,352 |
|
|
|
73,080 |
|
|
|
76,125 |
|
Operating
leases
|
|
|
5,840 |
|
|
|
2,687 |
|
|
|
2,726 |
|
|
|
383 |
|
|
|
44 |
|
Asset
retirement obligations
|
|
|
23,086 |
|
|
|
50 |
|
|
|
100 |
|
|
|
100 |
|
|
|
22,836 |
|
Rig
commitments (3)
|
|
|
15,859 |
|
|
|
12,091 |
|
|
|
3,768 |
|
|
|
- |
|
|
|
- |
|
Capital
expenditure commitments (4)
|
|
|
71,800 |
|
|
|
- |
|
|
|
70,000 |
|
|
|
- |
|
|
|
1,800 |
|
Derivative
contracts (5)
|
|
|
10,486 |
|
|
|
4,766 |
|
|
|
(6,197 |
) |
|
|
11,917 |
|
|
|
- |
|
Partnership
derivative contracts (6)
|
|
|
13,944 |
|
|
|
3,808 |
|
|
|
10,136 |
|
|
|
- |
|
|
|
- |
|
Production
tax liability
|
|
|
43,948 |
|
|
|
18,226 |
|
|
|
25,722 |
|
|
|
- |
|
|
|
- |
|
Firm
transportation, sales and processing agreements (7)
|
|
|
217,495 |
|
|
|
8,391 |
|
|
|
37,490 |
|
|
|
50,333 |
|
|
|
121,281 |
|
Other
liabilities (8)
|
|
|
8,380 |
|
|
|
446 |
|
|
|
1,240 |
|
|
|
1,240 |
|
|
|
5,454 |
|
Total
|
|
$ |
1,044,660 |
|
|
$ |
83,863 |
|
|
$ |
395,837 |
|
|
$ |
137,053 |
|
|
$ |
427,907 |
|
__________
|
(1)
|
Table
does not include deferred income tax obligations to taxing authorities of
$190.9 million and maximum annual repurchase obligations to investing
partners of $15.9 million as of December 31, 2008 due to the uncertainty
surrounding the ultimate settlement of amounts and timing of these
obligations.
|
|
(2)
|
Amounts
presented for long term debt consist of amounts related to our 12% senior
notes and our outstanding credit facility. The interest on long term debt
includes $222.3 million payable to the holders of our 12% senior notes and
$16.7 million related to our outstanding balance of $194.5 million on our
credit facility as of December 31, 2008, based on an imputed interest rate
of 4.65%.
|
|
(3)
|
Drilling rig commitments in
the above table reflect our maximum obligation and does not include future
adjustments to daily rates as provided for in the agreements as such
increases are not predictable and are only included in the above
obligation table upon notification to us by the contractor of an increase
in the rate. Further, our rig commitment
above includes $5.1 million related to a rig sublet to a third party and
remains our obligation should the third party default on terms of the
sublet agreement.
|
|
(4)
|
Primarily
represents our capital expenditure commitment related to certain drilling
and development agreements. See Note 8,
Commitments and Contingencies, to our accompanying consolidated financial
statements. These amounts do not include advances for future
drilling contracts totaling $1.7 million at December 31,
2008.
|
|
(5)
|
Represents
our gross liability related to the fair value of derivative positions,
including the fair value of derivative contracts we entered into on behalf
of our affiliated partnerships as the managing general
partner. We have a related receivable from the partnerships of
$1.6 million as of December 31,
2008.
|
|
(6)
|
Represents
our affiliated partnerships’ share of the fair value of our gross
derivative assets at December 31,
2008.
|
|
(7)
|
Represents
our gross commitment, including amounts for volumes transported or
sold on behalf of our affiliated partnerships and other working interest
owners. We will recognize in our financial statements our
proportionate share based on our working and net revenue
interest.
|
|
(8)
|
Includes
funds held from revenue distribution to third party investors for plugging
liabilities related to wells we operate and deferred officer
compensation.
|
As
managing general partner of 33 partnerships (see Item 1.
Business – Drilling and
Development Conducted for Company Sponsored Partnerships), we have
liability for any potential casualty losses in excess of the partnership assets
and insurance. We believe that the casualty insurance coverage
we and our subcontractors carry is adequate to meet this potential
liability.
For
information regarding our legal proceedings, see Note 8, Commitments and Contingencies –
Litigation, and Note 17, Subsequent Events, to our
accompanying consolidated financial statements included in this
report. From time to time we are a party to various other legal
proceedings in the ordinary course of business. We are not currently
a party to any litigation that we believe would have a materially adverse affect
on our business, financial condition, results of operations, or
liquidity.
Critical
Accounting Policies and Estimates
We
have identified the following policies as critical to business operations and
the understanding of our results of operations. This is not a
comprehensive list of all of the accounting policies. In many cases,
the accounting treatment of a particular transaction is specifically dictated by
accounting principles generally accepted in the U.S., with no need for our
judgment in the application. There are also areas in which our
judgment in selecting any available alternative would not produce a materially
different result. However, certain of our accounting policies are
particularly important to the portrayal of our financial position and results of
operations and we may use significant judgment in the application; as a result,
they are subject to an inherent degree of uncertainty. In applying
those policies, we use our judgment to determine the appropriate assumptions to
be used in the determination of certain estimates. Those estimates
are based on historical experience, observation of trends in the industry, and
information available from other outside sources, as appropriate. For
a more detailed discussion on the application of these and other accounting
policies, see Note
1, Summary of
Significant Accounting Policies, to our accompanying consolidated
financial statements. Our critical accounting policies and estimates
are as follows:
Revenue
Recognition
Oil and natural gas
sales. Sales of oil are recognized when persuasive evidence of
a sales arrangement exists, the oil is verified as produced and is delivered to
a purchaser, collection of revenue from the sale is reasonably assured and the
sales price is determinable. We are currently able to sell all the
oil that we can produce under existing sales contracts with petroleum refiners
and marketers. We do not refine any of our oil
production. Our crude oil production is sold to purchasers at or near
our wells under short-term purchase contracts at prices and in accordance with
arrangements that are customary in the oil industry.
Sales of
natural gas are recognized when natural gas has been delivered to a custody
transfer point, persuasive evidence of a sales arrangement exists, the rights
and responsibility of ownership pass to the purchaser upon delivery, collection
of revenue from the sale is reasonably assured and the sales price is fixed or
determinable. Natural gas is sold by us under contracts with terms
ranging from one month to three years. Virtually all of our contract
pricing provisions are tied to a market index, with certain adjustments based
on, among other factors, whether a well delivers to a gathering or transmission
line, quality of natural gas and prevailing supply and demand conditions, so
that the price of the natural gas fluctuates to remain competitive with other
available natural gas supplies. As a result, our revenues from the
sale of natural gas will suffer if market prices decline and benefit if they
increase. We believe that the pricing provisions of our natural gas
contracts are customary in the industry.
We
currently use the “net-back” method of accounting for transportation
arrangements of natural gas sales. We sell gas at the wellhead and
collect a price and recognize revenues based on the wellhead sales price since
transportation costs downstream of the wellhead are incurred by our customers
and reflected in the wellhead price.
Natural gas marketing
activities. Natural gas marketing is reported on the gross
accounting method, based on the nature of the agreements between RNG, our
suppliers and our customers. RNG, our marketing subsidiary, purchases
gas from PDC and other small producers and bundles the gas together to sell in
larger amounts to purchasers of natural gas for a price
advantage. RNG has latitude in establishing price and discretion in
supplier and purchaser selection. Natural gas marketing revenues and
expenses reflect the full cost and revenue of those transactions because RNG
takes title to the gas it purchases from the various producers and bears the
risks and rewards of that ownership. Both the realized and unrealized
gains and losses of the RNG commodity based derivative transactions for natural
gas marketing activities are included in gas sales from marketing activities or
cost of gas marketing activities, as applicable.
Oil and gas well drilling
operations. Our drilling segment recognizes revenue from
drilling contracts with sponsored drilling programs using the percentage of
completion method based upon the percentage of contract costs incurred to date
to the estimated total contract costs for each contract. We utilize
this method since reasonably dependable estimates of the total estimated costs
can be made and recognized revenues are subject to revisions as a contract
progresses, the term of which can range from three to twelve
months. We have offered our drilling services under two types of
contractual arrangements, cost-plus or footage-based service contracts, which
result in differing risk and reward relationships and, consequently, different
revenue reporting policies pursuant to Emerging Issues Task Force, or EITF,
Issue No. 99-19, Reporting
Revenue Gross as a Principal versus Net as an Agent.
The first
cost-plus drilling service arrangement was entered into in late 2005 with
drilling activity commencing in the first quarter of 2006. Due to the
fixed-fee-percentage nature of our revenues from these services, we have
determined that, in substance, we are acting as an agent, without risk of loss
during the performance of the drilling activities. Accordingly, our
services provided under the cost-plus drilling agreements are reported on a net
basis. We entered into our second and third cost-plus drilling
arrangements in September 2006 and August 2007 and commenced drilling
immediately. Footage-based contracts provide for the drilling,
completion and equipping of wells at footage rates and are generally completed
within nine to twelve months after the commencement of drilling. We
provide geological, engineering, and drilling supervision on the drilling and
completion process and use subcontractors to perform drilling and completion
services at a fixed footage-based rate and accordingly have the risk of loss in
performing services under these arrangements. Accordingly, we report
revenue under these agreements gross of related expenses. Anticipated
losses, if any, on uncompleted contracts are recorded at the time that the
estimated total costs exceed the estimated total contract revenue. At
December 31, 2007, we had recorded a loss contract reserve of $0.2
million. There was no loss contract reserve as of December 31,
2008.
Well operations and pipeline
income. Well operations and pipeline income are recognized
when persuasive evidence of an arrangement exists, services have been rendered,
collection of revenues is reasonably assured and the sales price is fixed or
determinable. We are paid a monthly operating fee for each well we
operate for outside owners including the limited partnerships we
sponsor. The fee covers monthly operating and accounting costs,
insurance and other recurring costs. We may also receive additional
compensation for special non-recurring activities, such as reworks and
recompletions.
Fair
Value of Financial Instruments
We
adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements,
effective January 1, 2008. SFAS No. 157 defines fair value,
establishes a framework for measuring fair value and expands disclosures related
to fair value measurements. SFAS No. 157 applies broadly to financial and
nonfinancial assets and liabilities that are measured at fair value under other
authoritative accounting pronouncements, but does not expand the application of
fair value accounting to any new circumstances. In February 2008, the
Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”)
FAS No. 157-2, Effective Date of FASB Statement No. 157, which delays the
effective date of SFAS No. 157 by one year (to January 1, 2009) for nonfinancial
assets and liabilities, except those that are recognized or disclosed at fair
value in the financial statements on a recurring basis (at least
annually). Nonfinancial assets and liabilities for which we have not
applied the provisions of SFAS No. 157 include those initially measured at fair
value, including our asset retirement.
Derivative Financial
Instruments.
We use
derivative instruments to manage our commodity and financial market
risks. We currently do not use hedge accounting treatment for our
derivatives. Derivatives are reported on our accompanying
consolidated balance sheets at fair value on a gross asset and liability
basis. Changes in fair value of derivatives are recorded in oil and
gas price risk management, net, in our accompanying consolidated statements of
income.
SFAS No.
157 establishes a fair value hierarchy that requires an entity to maximize the
use of observable inputs and minimize the use of unobservable inputs when
measuring fair value. The valuation hierarchy is based upon the
transparency of inputs to the valuation of an asset or liability as of the
measurement date, giving the highest priority to quoted prices in active markets
(Level 1) and the lowest priority to unobservable data (Level 3). In
some cases, the inputs used to measure fair value might fall in different levels
of the fair value hierarchy. The lowest level input that is
significant to a fair value measurement in its entirety determines the
applicable level in the fair value hierarchy. Assessing the
significance of a particular input to the fair value measurement in its entirety
requires judgment, considering factors specific to the asset or
liability. The three levels of inputs that may be used to measure
fair value are defined as:
|
|
Level
1 – Quoted prices (unadjusted) in active markets for identical assets or
liabilities. Instruments included in Level 1 consist of our
commodity derivatives for New York Mercantile Exchange (“NYMEX”)-based
natural gas swaps.
|
|
|
Level
2 – Inputs other than quoted prices included within Level 1 that are
either directly or indirectly observable for the asset or liability,
including (i) quoted prices for similar assets or liabilities in active
markets, (ii) quoted prices for identical or similar assets or liabilities
in inactive markets, (iii) inputs other than quoted prices that are
observable for the asset or liability and (iv) inputs that are derived
from observable market data by correlation or other
means.
|
|
|
Level
3 – Unobservable inputs for the asset or liability, including situations
where there is little, if any, market activity for the asset or
liability. Instruments included in Level 3 consist of our
commodity derivatives for Colorado Interstate Gas (“CIG”) and Panhandle
Eastern Pipeline (“PEPL”)-based natural gas swaps, oil swaps, natural gas
basis protection swaps, oil and natural gas options, and physical sales
and purchases.
|
We
measure fair value of our derivatives based upon quoted market prices, where
available. Our valuation determination includes: (1) identification
of the inputs to the fair value methodology through the review of counterparty
statements and other supporting documentation, (2) determination of the validity
of the source of the inputs, (3) corroboration of the original source of inputs
through access to multiple quotes, if available, or other information and (4)
monitoring changes in valuation methods and assumptions. The methods
described above may produce a fair value calculation that may not be indicative
of future fair values. Our valuation determination also gives
consideration to our nonperformance risk on our own liabilities as well as the
credit standing of our counterparties. We primarily use two
investment grade financial institutions as our counterparties to our derivative
contracts. We have evaluated the credit risk of our derivative assets
from our counterparties using relevant credit market default rates, giving
consideration to amounts outstanding for each counterparty and the duration of
each outstanding derivative position. Based on our evaluation, we
have determined that the impact of the nonperformance of our counterparties on
the fair value of our derivative instruments is
insignificant. As of December 31, 2008, no valuation allowance
was recorded. Furthermore, while we believe these valuation
methods are appropriate and consistent with that used by other market
participants, the use of different methodologies, or assumptions, to determine
the fair value of certain financial instruments could result in a different
estimate of fair value. We estimated the gross net fair value of our
commodity based derivatives as of December 31, 2008, to be $153.5
million.
Non-Derivative
Financial Assets and Liabilities.
The
carrying values of the financial instruments comprising cash and cash
equivalents, restricted cash, accounts receivable and accounts payable
approximate fair value due to the short-term maturities of these
instruments.
The
portion of our long-term debt related to our credit facility, approximates fair
value due to the variable nature of its related interest rate. We
estimate the fair value of the portion of our long-term debt related to our
senior notes to be approximately $127 million or approximately 62.5% of par
value as of December 31, 2008. We determined this valuation based
upon measurements of trading activity and quotes provided by brokers and traders
participating in the trading of the securities.
Oil
and Gas Properties
We
account for our oil and gas properties under the successful efforts method of
accounting. Costs of proved developed producing properties,
successful exploratory wells and development dry hole costs are capitalized and
depreciated or depleted by the unit-of-production method based on estimated
proved developed producing oil and natural gas reserves. Property
acquisition costs are depreciated or depleted on the unit-of-production method
based on estimated proved oil and gas reserves.
Our
estimates of proved reserves are based on quantities of oil and natural gas that
engineering and geological analysis demonstrates, with reasonable certainty, to
be recoverable from established reservoirs in the future under current operating
and economic conditions. Annually, we engage independent petroleum
engineers to prepare a reserve and economic evaluation of all our properties on
a well-by-well basis as of December 31. Additionally, we adjust our
oil and gas reserves for major acquisitions, new drilling and divestitures
during the year as needed. The process of estimating and evaluating
oil and natural gas reserves is complex, requiring significant decisions in the
evaluation of available geological, geophysical, engineering and economic
data. The data for a given property may also change substantially
over time as a result of numerous factors, including additional development
activity, evolving production history and a continual reassessment of the
viability of production under changing economic conditions. As a
result, revisions in existing reserve estimates occur from time to
time. Although every reasonable effort is made to ensure that reserve
estimates reported represent our most accurate assessments possible, the
subjective decisions and variances in available data for various properties
increase the likelihood of significant changes in these estimates over
time. Because estimates of reserves significantly affect our DD&A
expense, a change in our estimated reserves could have an effect on our net
income.
Exploration
costs, including geological and geophysical expenses and delay rentals, are
charged to expense as incurred. Exploratory well drilling costs,
including the cost of stratigraphic test wells, are initially capitalized but
charged to expense if the well is determined to be nonproductive. The
status of each in-progress well is reviewed quarterly to determine the proper
accounting treatment under the successful efforts method of
accounting. Exploratory well costs continue to be capitalized as long
as the well has found a sufficient quantity of reserves to justify our
completion as a producing well and we are making sufficient progress assessing
our reserves and economic and operating viability. If an in-progress
exploratory well is found to be unsuccessful (referred to as a dry hole) prior
to the issuance of the financial statements, the costs incurred prior to the end
of the reporting period are expensed to exploration costs. If we are
unable to make a final determination about the productive status of a well prior
to issuance of the financial statements, the well is classified as “suspended
well costs” until we have had sufficient time to conduct additional completion
or testing operations to evaluate the pertinent geological and engineering data
obtained. At the time when we are able to make a final determination
of a well’s productive status, the well is removed from the suspended well
status and the proper accounting treatment is recorded. At December
31, 2008 and 2007, suspended well costs included in oil and gas properties on
our accompanying consolidated financial statements was $1.2 million and $2.3
million, respectively.
The
acquisition costs of unproved properties are capitalized when incurred, until
such properties are transferred to proved properties or charged to expense when
expired, impaired or amortized. Unproved oil and gas properties with
individually significant acquisition costs are periodically assessed, and any
impairment in value is charged to exploration expense. The amount of
impairment recognized on unproved properties which are not individually
significant is determined by amortizing the costs of such properties within
appropriate fields based on our historical experience, acquisition dates and
average lease terms. The valuation of unproved properties is
subjective and requires us to make estimates and assumptions which, with the
passage of time, may prove to be materially different from actual realizable
values.
In
accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, we assess our oil and gas properties for
possible impairment by comparing net capitalized costs to estimated undiscounted
future net cash flows on a field-by-field basis using estimated production based
upon prices at which we reasonably estimate the commodity to be
sold. The estimates of future prices may differ from current market
prices of oil and natural gas. Any downward revisions in estimates to
our reserve quantities, expectations of falling commodity prices or rising
operating costs could result in a reduction in undiscounted future net cash
flows and an impairment of our oil and gas properties. Although our
cash flow estimates are based on the relevant information available at the time
the estimates are made, estimates of future cash flows are, by nature, highly
uncertain and may vary significantly from actual results.
Deferred
Income Tax Asset Valuation Allowance
Deferred
income tax assets are recognized for deductible temporary differences, net
operating loss carry-forwards, and credit carry-forwards if it is more likely
than not that the tax benefits will be realized. To the extent a
deferred tax asset is not expected to be realized under the preceding criteria,
a valuation allowance is established. The factors which we consider
in assessing whether we will realize the value of deferred income tax assets
involve judgments and estimates of both amount and timing, which could differ
from actual results, achieved in future periods.
The
judgments used in applying the above policies are based on our evaluation of the
relevant facts and circumstances as of the date of the financial
statements. Actual results may differ from those
estimates.
Accounting
for Acquisitions Using Purchase Accounting
We
account for acquisitions utilizing the purchase method as prescribed by SFAS No.
141, Business
Combinations. Pursuant to purchase method accounting, the
acquiring company must allocate the cost of the acquisition to assets acquired
and liabilities assumed based on fair values as of the acquisition
date. The purchase price allocations are based on appraisals,
discounted cash flows, quoted market prices and estimates by
management. In addition, when appropriate, we review comparable
purchases and sales of oil and gas properties within the same regions, and use
that data as a basis for fair market value; for example, the amount a willing
buyer and seller would enter into an exchange for such
properties.
In
estimating the fair values of assets acquired and liabilities assumed we made
various assumptions. The most significant assumptions relate to the
estimated fair values assigned to proved developed producing, proved developed
non-producing, proved undeveloped and unproved oil and gas
properties. To estimate the fair values of these properties, we
prepared estimates of oil and gas reserves. We estimated future
prices to apply to the estimated reserve quantities acquired, and estimated
future operating and development costs, to arrive at estimates of future net
revenues. For estimated proved reserves, the future net revenues were
discounted using a market-based weighted average cost of capital rate determined
appropriate at the time of the acquisition. The market-based weighted
average cost of capital rate was subjected to additional project-specific
risking factors. To compensate for the inherent risk of estimating
and valuing unproved properties, the discounted future net revenues of probable
and possible reserves were reduced by additional risk-weighting
factors.
Deferred
taxes must be recorded for any differences between the assigned values and tax
basis of assets and liabilities. Estimated deferred taxes are based
on available information concerning the tax basis of assets acquired and
liabilities assumed and loss carryforwards at the acquisition date, although
such estimates may change in the future as additional information becomes
known.
Recent
Accounting Standards
See Note 1, Summary of Significant Accounting
Policies - Recent Accounting Standards, to our accompanying consolidated
financial statements.
Market-Sensitive
Instruments and Risk Management
We are
exposed to market risks associated with interest rates, commodity prices and
credit exposure. Management has established risk management processes
to monitor and manage these market risks.
Interest
Rate Risk
Changes
in interest rates affect the amount of interest we earn on our cash, cash
equivalents and restricted cash and the interest we pay on borrowings under our
bank credit facility. Our 12% senior notes are fixed rate and,
therefore, do not expose us to the cash flow loss due to changes in market
interest rate. However, changes in interest rates do affect the fair
value of our senior notes.
Our
interest-bearing cash and cash equivalents include our money market accounts,
short-term certificates of deposit and checking and savings accounts with
various banks. The amount of our interest-bearing cash and cash
equivalents as of December 31, 2008, was $78.8 million with an average annual
interest rate of 1.8%.
Based on
a sensitivity analysis of the credit facility borrowings as of December 31,
2008, it was estimated that if market interest rates were to average 1% higher
(lower) in 2009 than in 2008, our interest expense, net of tax, would increase
(decrease) by approximately $1.3 million.
Commodity Price
Risk
See Part
II, Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operation,
Critical Accounting Policies and Estimates-Accounting for Derivatives Contracts
at Fair Value, for further discussion of the accounting for derivative
contracts.
We are
exposed to the effect of market fluctuations in the prices of oil and natural
gas as they relate to our oil and natural gas sales and marketing
activities. Price risk represents the potential risk of loss from
adverse changes in the market price of oil and natural gas
commodities. We employ established policies and procedures to manage
the risks associated with these market fluctuations using commodity
derivatives. Our policy prohibits the use of oil and natural gas
derivative instruments for speculative purposes.
Validation
of a contract’s fair value is performed internally and while we use common
industry practices to develop our valuation techniques, changes in our pricing
methodologies or the underlying assumptions could result in significantly
different fair values. While we believe these valuation methods are
appropriate and consistent with those used by other market participants, the use
of different methodologies, or assumptions, to determine the fair value of
certain financial instruments could result in a different estimate of fair
value.
Economic Hedging
Strategies. Our results of operations and operating cash flows
are affected by changes in market prices for oil and natural gas. To
mitigate a portion of the exposure to adverse market changes, we have entered
into various derivative contracts. As of December 31, 2008, our oil
and natural gas derivative instruments consisted of (i) NYMEX-based natural gas
contracts for Appalachian and Michigan production, (ii) PEPL-based contracts for
NECO production, (iii) CIG-based contracts for other Colorado production and
(iv) NYMEX-based crude oil contracts for our Colorado oil
production.
|
·
|
For
swap instruments, we receive a fixed price for the derivative contract and
pay a floating market price to the counterparty. The
fixed-price payment and the floating-price payment are netted, resulting
in a net amount due to or from the
counterparty.
|
|
·
|
Basis
protection swaps are arrangements that guarantee a price differential for
natural gas from a specified delivery point. For CIG basis
protection swaps, which have negative differentials to NYMEX, we receive a
payment from the counterparty if the price differential is greater than
the stated terms of the contract and pay the counterparty if the price
differential is less than the stated terms of the
contract.
|
|
·
|
Collars
contain a fixed floor price (put) and ceiling price (call). If
the market price exceeds the fixed call strike price, we receive the
market price from the purchaser and pay the difference between the call
strike price and market price to the counterparty. If the
market price falls below the fixed put strike price, we receive the market
price from the purchaser and receive the difference between the put strike
price and market price from the counterparty. If the market
price is between the call and the put strike price, no payments are due
from either party.
|
With
regard to our natural gas marketing activities, we enter into fixed-price
physical purchase and sale agreements that are derivative
contracts. In order to offset these fixed-price physical derivatives,
we enter into financial derivative instruments that have the effect of locking
in the prices we will receive or pay for the same volumes and period, offsetting
the physical derivative. While these derivatives are structured to
reduce our exposure to changes in price associated with the derivative
commodity, they also limit the benefit we might otherwise have received from
price changes in the physical market. We believe our derivative
instruments continue to be effective in achieving the risk management objectives
for which they were intended.
The
following table presents monthly average NYMEX and CIG closing prices for oil
and natural gas in 2008 and 2007, as well as average sales prices we realized
for the respective commodity.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
Average
Index Closing Price
|
|
|
|
|
|
|
Natural
Gas (per MMbtu)
|
|
|
|
|
|
|
CIG
|
|
$ |
6.22 |
|
|
$ |
3.97 |
|
NYMEX
|
|
|
9.04 |
|
|
|
6.89 |
|
|
|
|
|
|
|
|
|
|
Oil
(per Barrel)
|
|
|
|
|
|
|
|
|
NYMEX
|
|
|
104.42 |
|
|
|
69.79 |
|
|
|
|
|
|
|
|
|
|
Average
Sales Price
|
|
|
|
|
|
|
|
|
Natural
Gas
|
|
|
6.98 |
|
|
|
5.33 |
|
Oil
|
|
|
89.77 |
|
|
|
60.65 |
|
Based on
a sensitivity analysis as of December 31, 2008, it was estimated that a 10%
increase in oil and natural gas prices, inclusive of basis, over the entire
period for which we have derivatives currently in place would have resulted in
an increase in fair value of $13.7 million and a 10% decrease in oil and natural
gas prices would have resulted in an increase in fair value of $49.4
million.
See Item
7, Management’s Discussion and
Analysis of Financial Condition and Results of Operations, Results of
Operations, Oil and Gas Price Risk Management, Net and Natural Gas Marketing
Activities, for a detailed discussion of the our open derivative
positions related to our oil and gas sales activities and our natural gas
marketing activities. See Note 3, Derivative Financial
Instruments, to our accompanying consolidated financial statements
included in this report for a summary of our open derivative positions as of
December 31, 2008.
Credit
Risk
Credit
risk represents the loss that we would incur if a counterparty fails to perform
under its contractual obligations. We attempt to reduce credit risk
by diversifying our counterparty exposure and entering into transactions with
high-quality counterparties. When exposed to credit risk, we analyze
the counterparties’ financial condition prior to entering into an agreement,
establish credit limits and monitor the appropriateness of those limits on an
ongoing basis. We have had no counterparty default
losses.
Our
receivables are from a diverse group of companies, including major energy
companies, both upstream and mid-stream, financial institutions and end-users in
various industries related to our gas marketing group. We monitor
their creditworthiness through credit reports and rating agency
reports.
Our
commodity-based derivative contracts expose us to the credit risk of
nonperformance by the counterparty to the contracts. These contracts
consist of fixed price swaps, basis swaps and collars. We primarily
use two investment grade financial institutions as our counterparties to our
derivative contracts who are also major lenders in our credit facility
arrangement. We have evaluated the credit risk of our derivative
assets from our counterparties using relevant credit market default rates,
giving consideration to amounts outstanding for each counterparty and the
duration of each outstanding derivative position. Based on our
evaluation, we have determined that the impact of the nonperformance of our
counterparties on the fair value of our derivative instruments is
insignificant. As of December 31, 2008, no valuation allowance
was recorded.
The
recent disruption in the credit market has had a significant adverse impact on a
number of financial institutions. We monitor the creditworthiness of
the financial institutions with which we transact, giving consideration to the
reports of credit agencies and their related ratings. While we
believe that our monitoring procedures are sufficient and customary, no amount
of analysis can guarantee performance in these uncertain times.
Disclosure
of Limitations
Because
the information above included only those exposures that exist at December 31,
2008, it does not consider those exposures or positions which could arise after
that date. As a result, our ultimate realized gain or loss with
respect to interest rate and commodity price fluctuations will depend on the
exposures that arise during the period, our hedging strategies at the time, and
interest rates and commodity prices at the time.
The
response to this Item is set forth herein in a separate section of this Report,
beginning on Page F-1.
Index to financial
statements.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
As
reported on Form 8-K filed with the SEC on May 31, 2007, and incorporated herein
by reference, the Audit Committee of our Board of Directors recommended, and the
Board of Directors ratified, the dismissal of KPMG LLP as our principal
accountants on May 24, 2007.
Evaluation
of Disclosure Controls and Procedures
As of
December 31, 2008, we carried out an evaluation, under the supervision and with
the participation of our management, including our Chief Executive Officer and
Chief Financial Officer, of the effectiveness of the design and operation of our
disclosure controls and procedures pursuant to Securities Exchange Act Rule
13a-15. Based upon that evaluation, our Chief Executive Officer and
Chief Financial Officer concluded that our disclosure controls and procedures
were effective as of December 31, 2008, to ensure that the information required
to be disclosed by the Company in the reports that we file or submit under the
Exchange Act is recorded, processed, summarized and reported, within the time
periods specified in the SEC rules and forms, and that the information is
accumulated and communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
Changes
in Internal Control over Financial Reporting
We made
no changes in our internal control over financial reporting (as such term is
defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934)
during the quarter ended December 31, 2008, that have materially affected or are
reasonably likely to materially affect our internal control over financial
reporting.
See Remediation of Material Weaknesses
in Internal Control below for a discussion of changes in our internal
control over financial reporting that occurred throughout 2008.
Remediation
of Material Weaknesses in Internal Control
We, with
oversight from the Audit Committee of our Board of Directors, have been
addressing the material weaknesses disclosed in our 2007 Form 10-K and Item 4 of
our subsequently filed Form 10-Q for each of the quarterly periods in the
nine-month period ended September 30, 2008. We have concluded, based
on our assessment, that, through the implementation of the changes in internal
controls over financial reporting described below, we have remediated these
previously reported material weaknesses as of December 31,
2008. Management’s annual report on internal control over financial
reporting and the audit report on our internal control over financial reporting
of our independent registered public accounting firm are included in response to
Item 8 of this report on pages F-2 and F-3 included
herein.
The
remediation initiatives that were undertaken during 2008 include:
|
·
|
In
the first quarter of 2008, we implemented the general ledger, accounts
receivable, and joint interest billing modules as part of a new broader
financial reporting system. We have taken the necessary steps
to monitor and maintain appropriate internal controls during this period
of change. These steps included providing training related to
business process changes and the financial reporting system software to
individuals using the financial reporting system to carry out their job
responsibilities as well as those who rely on the financial
information. The implementation of the financial reporting
system strengthened the overall internal controls due to enhanced
automation and integration of related processes. The design and
documentation of internal control process and procedures relating to the
new system has been modified to supplement and complement existing
internal controls over financial
reporting.
|
|
·
|
In
the third quarter of 2008, we implemented controls over key financial
statement spreadsheets that support all significant balance sheet and
income statement accounts. Specifically, we enhanced the
spreadsheet policy to provide additional clarification and guidance with
regard to risk assessment and enforced controls over: 1) the security and
integrity of the data used in the various spreadsheets, 2) access to the
spreadsheets, 3) changes to spreadsheet functionality and the related
approval process and documentation and 4) increased managements review of
the spreadsheets.
|
|
·
|
In
the third quarter of 2008, key personnel attended an accredited derivative
training course and a desktop procedure was implemented to ensure the
completeness and accuracy over derivative activities, which supplemented
the key controls that previously existed in the
process.
|
None.
PART
III
The
information called for by Item 10 is incorporated by reference from information
under the captions entitled Corporate Governance, Section 16(a) Beneficial Ownership
Reporting Compliance, Election of Directors and
Executive Compensation
and other relevant portions of our definitive proxy statement to be filed
pursuant to Regulation 14A no later than 120 days after the close of our fiscal
year.
The information called for by Item 11
is incorporated by reference from information under the caption entitled Executive Compensation and
other relevant portions of our definitive proxy statement to be filed pursuant
to Regulation 14A no later than 120 days after the close of our fiscal
year.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The
information called for by Item 12 is incorporated by reference from information
under the caption entitled Security Ownership of Certain
Beneficial Owners and Management and Related Stockholder Matters and
other relevant portions of our definitive proxy statement to be filed pursuant
to Regulation 14A no later than 120 days after the close of our fiscal
year.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
AND DIRECTOR INDEPENDENCE
The
information called for by Item 13 is incorporated by reference from information
under the captions entitled Certain Relationships and Related
Transactions and
Director Independence in our definitive proxy statement to be
filed pursuant to Regulation 14A no later than 120 days after the close of our
fiscal year.
The
information called for by Item 14 is incorporated by reference from information
under caption entitled Principal Accountant Fees and
Services and other relevant portions of our definitive proxy
statement to be filed pursuant to Regulation 14A no later than 120 days after
the close of our fiscal year.
PART
IV
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(a)
|
(1)
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Financial
Statements:
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|
|
|
See
Index to Financial Statements and
Schedules on page F-1.
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|
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(2)
|
Financial
Statement Schedules:
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|
See
Index to Financial Statements and
Schedules on page F-1.
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|
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|
Schedules
and Financial Statements Omitted
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|
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|
All
other financial statement schedules are omitted because they are not
required, inapplicable, or the information is included in the Financial
Statements or Notes thereto.
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(3)
|
Exhibits:
|
|
|
|
See
Exhibits Index on page
56.
|
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
|
PETROLEUM
DEVELOPMENT CORPORATION |
|
|
|
|
By |
/s/ Richard W. McCullough
|
|
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Richard
W. McCullough,
Chairman,
Chief Executive Officer, and President
|
|
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By |
/s/ Gysle R. Shellum
|
|
|
Gysle
R. Shellum,
Chief
Financial Officer
February
26,
2009
|
Pursuant to the requirements of the
Securities Exchange Act of 1934, this report has been signed below by the
following
persons
on behalf of the Registrant and in the capacities and on the dates
indicated:
Signature
|
Title
|
Date
|
|
|
|
/s/ Richard W. McCullough
Richard
W. McCullough
|
Chairman,
Chief Executive Officer, and President (principal
executive officer)
|
February
26, 2009
|
|
|
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/s/ Gysle R. Shellum
Gysle
R. Shellum
|
Chief
Financial Officer (principal
financial officer)
|
February
26, 2009
|
|
|
|
/s/ Darwin L. Stump
Darwin
L. Stump
|
Chief
Accounting Officer (principal
accounting officer)
|
February
26, 2009
|
|
|
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/s/ Daniel W. Amidon
Daniel
W. Amidon
|
General
Counsel, Corporate Secretary
|
February
26, 2009
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|
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/s/ Steven R. Williams
Steven
R. Williams
|
Director
|
February
26, 2009
|
|
|
|
/s/ Jeffrey C. Swoveland
Jeffrey
C. Swoveland
|
Director
|
February
26, 2009
|
|
|
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/s/ Vincent F. D'Annunzio
Vincent
F. D'Annunzio
|
Director
|
February
26, 2009
|
|
|
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/s/ Kimberly Luff Wakim
Kimberly
Luff Wakim
|
Director
|
February
26, 2009
|
|
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/s/ David C. Parke
David
C. Parke
|
Director
|
February
26, 2009
|
|
|
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/s/ Anthony J.
Crisafio
Anthony
J. Crisafio
|
Director
|
February
26,
2009
|
/s/ Joseph E.
Casabona
Joseph
E. Casabona
|
Director
|
February
26, 2009
|
|
|
|
/s/ Larry F. Mazza
Larry
F. Mazza
|
Director
|
February
26,
2009
|
The
following are abbreviations and definitions of terms commonly used in the oil
and gas industry and this Form 10-K.
Bbl - One barrel or 42 U.S.
gallons of liquid volume.
Bcf - One billion cubic
feet.
Bcfe - One billion cubic feet
of natural gas equivalent.
CIG - Colorado Interstate
Gas.
Completion - The installation
of permanent equipment for the production of oil or gas.
DD&A - Refers to depreciation,
depletion and amortization of our property and equipment.
Development well - A well
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 to justify
completion as an oil or gas well.
Exploratory well - A well
drilled to find and produce oil or natural gas reserves not classified as
proved, to find a new productive reservoir in a field previously found to be
productive of oil or natural gas in another reservoir or to extend a known
reservoir.
Extensions and discoveries -
As to any period, the increases to proved reserves from all sources other than
the acquisition of proved properties or revisions of previous
estimates.
Gross acres or wells - Refers
to the total acres or wells in which we have a working interest.
Horizontal drilling - A
drilling technique that permits the operator to contact and intersect a larger
portion of the producing horizon than conventional vertical drilling techniques
and may, depending on the horizon, result in increased production rates and
greater ultimate recoveries of hydrocarbons.
MBbls - One thousand
barrels.
Mcf - One thousand cubic
feet.
Mcfe - One thousand cubic feet
of natural gas equivalent, based on a ratio of 6 Mcf for each barrel of oil,
which reflects the relative energy content.
MMbtu - One million British
thermal units. One British thermal unit is the heat required to raise
the temperature of a one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit.
MMcf - One million cubic
feet.
MMcfe - One million cubic feet of
natural gas equivalent.
Net acres or wells - Refers to
gross acres or wells multiplied, in each case, by the percentage working
interest we own.
Net production - Oil and gas
production that we own, less royalties and production due others.
NYMEX - New York Mercantile
Exchange.
Oil - Crude oil or
condensate.
Operator - The individual or
company responsible for the exploration, development and/or production of an oil
or gas well or lease.
PEPL - Panhandle Eastern
Pipeline.
Present value of proved
reserves - The present value of estimated future revenues, discounted at
10% annually, to be generated from the production of proved reserves determined
in accordance with Securities and Exchange Commission guidelines, net of
estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation, without giving effect to (i)
estimated future abandonment costs, net of the estimated salvage value of
related equipment, (ii) non-property related expenses such as general and
administrative expenses, debt service and future income tax expense, or (iii)
depreciation, depletion and amortization.
Proved developed non-producing
reserves - Reserves that consist of (i) proved reserves from wells which
have been completed and tested but are not producing due to lack of market or
minor completion problems which are expected to be corrected and (ii) proved
reserves currently behind the pipe in existing wells and which are expected to
be productive due to both the well log characteristics and analogous production
in the immediate vicinity of the wells.
Proved developed producing
reserves -
Proved reserves that can be expected to be recovered from currently
producing zones under the continuation of present operating
methods.
Proved developed reserves - The combination of proved
developed producing and proved developed non-producing reserves.
Proved reserves - The
estimated quantities of crude 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.
Proved undeveloped reserves,
or PUD - Proved
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.
Recompletion - A recompletion
occurs when we reenter a well to complete (i.e., perforate) a new formation
different from that in which a well has previously been completed.
Refrac, or refracture – A
refrac is when we stimulate the present producing zone of a well to increase
production, using hydraulic, acid, gravel, etc. fracture
techniques.
Reserve replacement -
Calculated by dividing the sum of reserve additions from all sources (revisions,
extensions, discoveries and other additions and acquisitions) by the actual
production for the corresponding period. The values used for reserve
additions are derived directly from the proved reserves table located in Note 18, Supplemental Oil and Gas
information, to our consolidated financial statements included in this
report. We use the reserve replacement ratio as an indicator of our
ability to replenish annual production volumes and grow our reserves, thereby
providing some information on the sources of future production. It
should be noted that the reserve replacement ratio is a statistical indicator
that has limitations. As an annual measure, the ratio is limited
because it typically varies widely based on the extent and timing of new
discoveries and property acquisitions. Its predictive and comparative
value is also limited for the same reasons. In addition, since the
ratio does not imbed the cost or timing of future production of new reserves, it
cannot be used as a measure of value creation.
Royalty - An interest in an
oil and gas lease that gives the owner of the interest the right to receive a
portion of the production from the leased acreage (or of the proceeds of the
sale thereof), but generally does not require the owner to pay any portion of
the costs of drilling or operating the wells on the leased
acreage. Royalties may be either landowner’s royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
Standardized measure of discounted
future net cash flows - Present value of proved reserves, as adjusted to
give effect to (i) estimated future abandonment costs, net of the estimated
salvage value of related equipment, and (ii) estimated future income
taxes.
Undeveloped acreage - Leased
acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and gas, regardless of
whether such acreage contains proved reserves.
Working interest - An interest
in an oil and gas lease that gives the owner of the interest the right to drill
for and produce oil and gas on the leased acreage and requires the owner to pay
a share of the costs of drilling and production operations. The share
of production to which a working interest is entitled will be smaller than the
share of costs that the working interest owner is required to bear to the extent
of any royalty burden.
Workover - Operations on a
producing well to restore or increase production.
Exhibits
Index
|
|
|
|
Incorporated
by Reference
|
|
|
Exhibit
Number
|
|
Exhibit
Description
|
|
Form
|
|
SEC
File Number
|
|
Exhibit
|
|
Filing
Date
|
|
Filed
Herewith
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|
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|
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|
|
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3.1
|
|
Second
Amended and Restated Certificate of Incorporation of Petroleum Development
Corporation.
|
|
8-K
|
|
000-07246
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|
3.1
|
|
07/23/2008
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|
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3.2
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Bylaws
of Petroleum Development Corporation, amended and restated, effective
October 11, 2007.
|
|
8-K
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|
000-07246
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3.2
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10/17/2007
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4.1
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Rights
Agreement by and between Petroleum Development Corporation and Transfer
Online, Inc., as Rights Agent, dated as of September 11, 2007, including
the forms of Rights Certificates and Summary of Stockholder Rights Plan
attached thereto as Exhibits A and B.
|
|
8-K
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000-07246
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4.1
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09/14/2007
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4.2
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Indenture
dated as of February 8, 2008, by and among Petroleum Development
Corporation and The Bank of New York.
|
|
8-K
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000-07246
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4.1
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02/12/2008
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4.3
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First
Supplemental Indenture dated as of February 8, 2008, by and among
Petroleum Development Corporation and the Bank of New
York.
|
|
8-K
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000-07246
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4.2
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02/12/2008
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4.4
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Form
of 12% Senior Note due 2018.
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|
8-K
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000-07246
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4.3
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02/12/2008
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10.1
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Purchase
Agreement dated as of February 1, 2008, by and among Petroleum Development
Corporation and the Initial Purchasers of 12% senior notes due 2018 named
therein.
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8-K
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000-07246
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10.1
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02/07/2008
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10.2
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Registration
Rights Agreement dated as of February 8, 2008, by and among Petroleum
Development Corporation and the Initial Purchasers of 12% senior notes due
2018 named therein.
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|
8-K
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000-07246
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10.1
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02/12/2008
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10.3
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Amended
and Restated Credit Agreement dated as of November 4, 2005, Petroleum
Development Corporation, as borrower and JPMorgan Chase Bank, N.A and BNP
Paribas, as lenders.
|
|
8-K
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000-07246
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10.1
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11/04/2005
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10.4
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First
Amendment to Amended and Restated Credit Agreement, dated as of August 9,
2007, by an among Petroleum Development Corporation, certain of its
subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas and Wachovia Bank,
N.A.
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8-K
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000-07246
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10.1
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08/15/2007
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10.5
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Second
Amendment to Amended and Restated Credit Agreement, dated as of October
16, 2007, by and among Petroleum Development Corporation, certain of its
subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas, Wachovia Bank, N.A.,
Guaranty Bank, FSB, Bank of Oklahoma and Morgan Stanley
Bank.
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|
8-K
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000-07246
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10.1
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10/22/2007
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10.6
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Third
Amendment to Amended and Restated Credit Agreement dated as of July 15,
2008, by and among Petroleum Development Corporation,
certain of its subsidiaries, JP Morgan Chase Bank, N.A., BNP Paribas and
various other banks.
|
|
8-K
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000-07246
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10.1
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07/21/2008
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10.7
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Fourth
Amendment to Amended and Restated Credit Agreement dated as of July 18,
2008, by and among the Company, certain of its subsidiaries, JP Morgan
Chase Bank, N.A., BNP Paribas and various other banks.
|
|
8-K
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000-07246
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10.2
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07/21/2008
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10.8
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Fifth
Amendment to Amended and Restated Credit Agreement dated as of November
12, 2008, by and among the Company, certain of its subsidiaries, JP Morgan
Chase Bank, N.A., various other banks.
|
|
8-K
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000-07246
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10.1
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11/19/2008
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Incorporated
by Reference
|
|
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|
|
Exhibit
Number
|
|
Exhibit
Description
|
|
Form
|
|
SEC
File Number
|
|
Exhibit
|
|
Filing
Date
|
|
Filed
Herewith
|
|
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Employment
Agreement with Richard W. McCullough, Chief Executive Officer, dated as of
December 31, 2008.
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X
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Employment
Agreement with Eric R. Stearns, Executive Vice President, dated as of
December 31, 2008.
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X
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Employment
Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of
December 31, 2008.
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X
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Employment
Agreement with Barton R. Brookman, Jr., Senior Vice President of
Exploration and Production, dated as of December 31, 2008.
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X
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Employment
Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary,
dated as of December 31, 2008.
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X
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Employment
Agreement with Darwin L. Stump, Chief Accounting Officer, dated as of
December 31, 2008.
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X
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|
10.15*
|
|
2008
Short-Term Incentive Compensation Terms for Executive
Officers.
|
|
8-K
|
|
000-07246
|
|
|
|
03/28/2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.16*
|
|
2008
Long-Term Incentive Program (as amended for 2008) for Executive
Officers.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
03/13/2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.17*
|
|
Non-Employee
Director Compensation for the 2008-2009 Term.
|
|
8-K
|
|
000-07246
|
|
|
|
03/13/2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.18*
|
|
2008
Base Salary and Short-Term Incentive Cash Bonus Program for Executive
Officers.
|
|
8-K
|
|
000-07246
|
|
|
|
02/22/2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.19*
|
|
2007
Long-Term Incentive Program for Executive Officers.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
04/13/2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.20*
|
|
2006
Long-Term Equity Compensation Grants to Executive
Officers.
|
|
8-K
|
|
000-07246
|
|
|
|
04/10/2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.21*
|
|
Agreement
with Steven R. Williams, Director.
|
|
10-Q
|
|
000-07246
|
|
10.3
|
|
11/06/2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Separation
Agreement with Thomas E. Riley, former President.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.23*
|
|
Indemnification
Agreement with Directors and Officers.
|
|
10-Q
|
|
000-07246
|
|
10.1
|
|
08/09/2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.24*
|
|
The
Petroleum Development Corporation 401(k) & Profit Sharing
Plan.
|
|
S-8
|
|
333-137836
|
|
4.1
|
|
10/05/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.25*
|
|
2005
Non-Employee Director Restricted Stock Plan amended and restated as of
March 8, 2008.
|
|
10-Q
|
|
000-07246
|
|
10.6
|
|
11/06/2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
Long-Term Equity Compensation Plan amended and restated as of March 8,
2008.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.27*
|
|
Non-Employee
Director Deferred Compensation Plan.
|
|
S-8
|
|
333-118222
|
|
99.1
|
|
08/13/2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.28*
|
|
1999
Incentive Stock Option and Non-Qualified Stock Plan.
|
|
S-8
|
|
333-111825
|
|
99.1
|
|
01/09/2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Code
of Business Conduct and Ethics.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiaries.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consent
of PricewaterhouseCoopers LLP.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consent
of KPMG LLP.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consent
of Wright & Company, Inc., Petroleum Consultants.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consent
of Ryder Scott Company, L.P., Petroleum Consultants.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
Incorporated
by Reference
|
|
|
|
|
Exhibit
Number
|
|
Exhibit
Description
|
|
Form
|
|
SEC
File Number
|
|
Exhibit
|
|
Filing
Date
|
|
Filed
Herewith
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certification
by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the
Exchange Act Rules, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certification
by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the
Exchange Act Rules, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certifications
by Chief Executive Officer and Chief Financial Officer pursuant to Title
18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
|
|
|
|
X
|
____________
*Management
contract or compensatory plan or arrangement.
PETROLEUM
DEVELOPMENT CORPORATION
Index
to Consolidated Financial Statements and Financial Statement
Schedule
Management's Report on Internal Control Over
Financial Reporting
|
F-2
|
|
|
Financial
Statements:
|
|
Reports of Independent Registered Public
Accounting Firms
|
F-3
|
Consolidated Balance Sheets - December 31, 2008
and 2007
|
F-5
|
Consolidated Statements of Operations - Years
Ended December 31, 2008, 2007 and 2006
|
F-6
|
Consolidated Statements of Cash Flows - Years
Ended December 31, 2008, 2007 and 2006
|
F-7
|
Consolidated Statements of Shareholders' Equity -
Years Ended December 31, 2008, 2007 and 2006
|
F-8
|
Notes to Consolidated Financial
Statements
|
F-9
|
|
|
Financial
Statement Schedule:
|
|
Schedule II – Valuation and Qualifying Accounts
and Reserves
|
F-48
|
PETROLEUM
DEVELOPMENT CORPORATION
Management's Report on
Internal Control Over Financial Reporting
Management
is responsible for establishing and maintaining adequate internal control over
financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) of
the Exchange Act. Internal control over financial reporting is a
process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles. Because of its inherent limitations, internal control
over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with policies
or procedures may deteriorate.
Management
has assessed the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2008, based upon the criteria established in
“Internal Control – Integrated Framework” issued by the Committee of Sponsoring
Organizations of the Treadway Commission (“COSO”). Based on this
evaluation, management concluded that the Company maintained effective internal
control over financial reporting as of December 31, 2008.
The
effectiveness of Petroleum Development Corporation's internal control over
financial reporting as of December 31, 2008, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report which appears herein.
PETROLEUM
DEVELOPMENT CORPORATION
/s/
Richard W. McCullough
|
|
Richard
W. McCullough
|
|
Chairman
and Chief Executive Officer
|
|
|
|
/s/
Gysle R. Shellum
|
|
Gysle
R. Shellum
|
|
Chief
Financial Officer
|
|
PETROLEUM
DEVELOPMENT CORPORATION
Report of
Independent Registered Public Accounting Firm
To the Board of
Directors and Shareholders
of Petroleum
Development Corporation
In our opinion,
the accompanying consolidated balance sheets and the related consolidated
statements of operations, shareholders' equity, and cash flows present fairly,
in all material respects, the financial position of Petroleum Development
Corporation and its subsidiaries at December 31, 2008 and 2007, and
the results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the 2008 and 2007 information
in the financial statement schedule listed in the accompanying
index presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements. Also in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2008, based on criteria established in Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company's management is responsible
for these financial statements and financial statement schedule, for maintaining
effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting, included in the
accompanying Management's Report on Internal Control Over Financial
Reporting. Our responsibility is to express opinions on these
financial statements, on the 2008 and 2007 information in the financial
statement schedule, and on the Company's internal control over financial
reporting based on our integrated 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
audits to obtain reasonable assurance about whether the financial statements are
free of material misstatement and whether effective internal control over
financial reporting was maintained in all material respects. Our
audits of the financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. Our audit of
internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audits provide a reasonable basis for
our opinion.
As discussed in
Note 5 to the consolidated financial statements, the Company changed the
manner in which it accounts for uncertain tax positions in 2007.
A company’s
internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of
the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and
(iii) provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its
inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/
PricewaterhouseCoopers LLP
Pittsburgh,
Pennsylvania
February 26,
2009
PETROLEUM
DEVELOPMENT CORPORATION
Report
of Independent Registered Public Accounting Firm
The Board
of Directors and Stockholders
Petroleum
Development Corporation:
We have
audited the accompanying consolidated statements of operations, shareholders’
equity, and cash flows of Petroleum Development Corporation and subsidiaries for
the year ended December 31, 2006. In connection with our audit
of these consolidated financial statements, we also have audited the related
financial statement schedule. These consolidated financial statements
and financial statement schedule are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audit.
We
conducted our audit 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
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 audit provides a reasonable basis for our
opinion.
In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the results of operations and the cash flows of
Petroleum Development Corporation and subsidiaries for the year ended
December 31, 2006, in conformity with U.S. generally accepted accounting
principles. Also in our opinion, the related financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material respects, the
information set forth therein.
As
discussed in Note 1 to the consolidated financial statements, the Company
adopted the provisions of Statement of Financial Accounting Standards No.
123(R), (“Share-Based Payment”), in 2006.
As
discussed in Note 1 to the consolidated financial statements, the Company
changed its method of quantifying errors based on SEC Staff Accounting Bulletin
No. 108 (“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements”) in 2006.
KPMG
LLP
Pittsburgh,
Pennsylvania
May 22,
2007
PETROLEUM
DEVELOPMENT CORPORATION
Consolidated
Balance Sheets
(in
thousands, except share and per share data)
December
31,
|
|
2008
|
|
|
2007
|
|
Assets
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
50,950 |
|
|
$ |
84,751 |
|
Restricted
cash - current
|
|
|
19,030 |
|
|
|
14,773 |
|
Accounts
receivable, net
|
|
|
69,688 |
|
|
|
60,024 |
|
Accounts
receivable - affiliates
|
|
|
16,742 |
|
|
|
11,537 |
|
Fair
value of derivatives - current
|
|
|
116,881 |
|
|
|
4,817 |
|
Prepaid
expenses and other current assets
|
|
|
19,146 |
|
|
|
15,891 |
|
Total
current assets
|
|
|
292,437 |
|
|
|
191,793 |
|
Properties
and equipment, net
|
|
|
1,033,078 |
|
|
|
845,864 |
|
Other
assets
|
|
|
77,189 |
|
|
|
12,822 |
|
Total
Assets
|
|
$ |
1,402,704 |
|
|
$ |
1,050,479 |
|
|
|
|
|
|
|
|
|
|
Liabilities
and Shareholders' Equity
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
90,532 |
|
|
$ |
88,502 |
|
Accounts
payable - affiliates
|
|
|
40,540 |
|
|
|
3,828 |
|
Production
tax liability
|
|
|
18,226 |
|
|
|
21,330 |
|
Federal
and state income taxes payable
|
|
|
1,591 |
|
|
|
901 |
|
Fair
value of derivatives
|
|
|
4,766 |
|
|
|
6,291 |
|
Advances
for future drilling contracts
|
|
|
1,675 |
|
|
|
68,417 |
|
Funds
held for distribution
|
|
|
50,361 |
|
|
|
39,823 |
|
Net
deferred income taxes - current
|
|
|
28,355 |
|
|
|
- |
|
Other
accrued expenses
|
|
|
25,125 |
|
|
|
12,913 |
|
Total
current liabilities
|
|
|
261,171 |
|
|
|
242,005 |
|
Long-term
debt
|
|
|
394,867 |
|
|
|
235,000 |
|
Net
deferred income taxes - non current
|
|
|
162,593 |
|
|
|
136,490 |
|
Other
liabilities
|
|
|
71,798 |
|
|
|
40,699 |
|
Total
liabilities
|
|
|
890,429 |
|
|
|
654,194 |
|
|
|
|
|
|
|
|
|
|
Commitments
and contingent liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority
interest in consolidated limited liability company
|
|
|
694 |
|
|
|
759 |
|
|
|
|
|
|
|
|
|
|
Shareholders'
equity:
|
|
|
|
|
|
|
|
|
Preferred
shares, par value $.01 per share; authorized 50,000,000 shares;
issued: none
|
|
|
- |
|
|
|
- |
|
Common
shares, par value $.01 per share; authorized 100,000,000 shares;
issued: 14,871,870 in 2008 and 14,907,679 in
2007
|
|
|
149 |
|
|
|
149 |
|
Additional
paid-in capital
|
|
|
5,818 |
|
|
|
2,559 |
|
Retained
earnings
|
|
|
505,906 |
|
|
|
393,044 |
|
Treasury
shares, at cost: 7,066 shares in 2008 and 5,894 in 2007
|
|
|
(292 |
) |
|
|
(226 |
) |
Total
shareholders' equity
|
|
|
511,581 |
|
|
|
395,526 |
|
Total
Liabilities and Shareholders' Equity
|
|
$ |
1,402,704 |
|
|
$ |
1,050,479 |
|
See accompanying Notes to
Consolidated Financial Statements.
PETROLEUM
DEVELOPMENT CORPORATION
Consolidated
Statements of Operations
(in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$ |
321,877 |
|
|
$ |
175,187 |
|
|
$ |
115,189 |
|
Sales
from natural gas marketing activities
|
|
|
140,263 |
|
|
|
103,624 |
|
|
|
131,325 |
|
Oil
and gas well drilling
|
|
|
7,615 |
|
|
|
12,154 |
|
|
|
17,917 |
|
Well
operations and pipeline income
|
|
|
11,474 |
|
|
|
9,342 |
|
|
|
10,704 |
|
Oil
and gas price risk management gain, net
|
|
|
127,838 |
|
|
|
2,756 |
|
|
|
9,147 |
|
Other
|
|
|
293 |
|
|
|
2,172 |
|
|
|
2,221 |
|
Total
revenues
|
|
|
609,360 |
|
|
|
305,235 |
|
|
|
286,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas production and well operations cost
|
|
|
78,209 |
|
|
|
49,264 |
|
|
|
29,021 |
|
Cost
of natural gas marketing activities
|
|
|
139,234 |
|
|
|
100,584 |
|
|
|
130,150 |
|
Cost
of oil and gas well drilling
|
|
|
2,213 |
|
|
|
2,508 |
|
|
|
12,617 |
|
Exploration
expense
|
|
|
45,105 |
|
|
|
23,551 |
|
|
|
8,131 |
|
General
and administrative expense
|
|
|
37,715 |
|
|
|
30,968 |
|
|
|
19,047 |
|
Depreciation,
depletion, and amortization
|
|
|
104,575 |
|
|
|
70,844 |
|
|
|
33,735 |
|
Total
costs and expenses
|
|
|
407,051 |
|
|
|
277,719 |
|
|
|
232,701 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
on sale of leaseholds
|
|
|
- |
|
|
|
33,291 |
|
|
|
328,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from operations
|
|
|
202,309 |
|
|
|
60,807 |
|
|
|
381,802 |
|
Interest
income
|
|
|
591 |
|
|
|
2,662 |
|
|
|
8,050 |
|
Interest
expense
|
|
|
(28,132 |
) |
|
|
(9,279 |
) |
|
|
(2,443 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
174,768 |
|
|
|
54,190 |
|
|
|
387,409 |
|
Provision
for income taxes
|
|
|
61,459 |
|
|
|
20,981 |
|
|
|
149,637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
113,309 |
|
|
$ |
33,209 |
|
|
$ |
237,772 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
7.69 |
|
|
$ |
2.25 |
|
|
$ |
15.18 |
|
Diluted
|
|
$ |
7.63 |
|
|
$ |
2.24 |
|
|
$ |
15.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average common and common equivalent shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
14,736 |
|
|
|
14,744 |
|
|
|
15,660 |
|
Diluted
|
|
|
14,848 |
|
|
|
14,841 |
|
|
|
15,741 |
|
See accompanying Notes to
Consolidated Financial Statements.
PETROLEUM
DEVELOPMENT CORPORATION
Consolidated
Statements of Shareholders' Equity
(in
thousands, except share and per share data)
Year
Ended December 31,
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Common
stock, par value $.01 per share - shares issued:
|
|
|
|
|
|
|
|
|
|
Shares
at beginning of year
|
|
|
14,907,679 |
|
|
|
14,834,871 |
|
|
|
16,281,923 |
|
Adjust
prior conversion of predecessor shares
|
|
|
100 |
|
|
|
- |
|
|
|
59,546 |
|
Exercise
of stock options
|
|
|
25,699 |
|
|
|
38,000 |
|
|
|
8,000 |
|
Issuance
of stock awards, net of forfeitures
|
|
|
21,863 |
|
|
|
46,828 |
|
|
|
112,902 |
|
Retirement
of treasury shares
|
|
|
(83,471 |
) |
|
|
(12,020 |
) |
|
|
(1,627,500 |
) |
Shares
at end of year
|
|
|
14,871,870 |
|
|
|
14,907,679 |
|
|
|
14,834,871 |
|
Treasury
stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
at beginning of year
|
|
|
(5,894 |
) |
|
|
(4,706 |
) |
|
|
- |
|
Purchase
of treasury shares
|
|
|
(83,471 |
) |
|
|
(12,020 |
) |
|
|
(1,627,500 |
) |
Retirement
of treasury shares
|
|
|
83,471 |
|
|
|
12,020 |
|
|
|
1,627,500 |
|
Non-employee
directors' deferred compensation plan
|
|
|
(1,172 |
) |
|
|
(1,188 |
) |
|
|
(4,706 |
) |
Shares
at end of year
|
|
|
(7,066 |
) |
|
|
(5,894 |
) |
|
|
(4,706 |
) |
Common
shares outstanding
|
|
|
14,864,804 |
|
|
|
14,901,785 |
|
|
|
14,830,165 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stock, $.01 par:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at beginning of year
|
|
$ |
149 |
|
|
$ |
148 |
|
|
$ |
163 |
|
Exercise
of stock options
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Issuance
of stock awards, net of forfeitures
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
Retirement
of treasury shares
|
|
|
- |
|
|
|
- |
|
|
|
(16 |
) |
Balance
at end of year
|
|
|
149 |
|
|
|
149 |
|
|
|
148 |
|
Additional
paid-in capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at beginning of year
|
|
|
2,559 |
|
|
|
64 |
|
|
|
30,423 |
|
Reclassification
of unearned compensation pursuant to the adoption of SFAS No.
123(R)
|
|
|
- |
|
|
|
- |
|
|
|
(825 |
) |
Exercise
of stock options
|
|
|
627 |
|
|
|
183 |
|
|
|
31 |
|
Issuance
of stock awards, net of forfeitures
|
|
|
- |
|
|
|
(1 |
) |
|
|
(1 |
) |
Stock
based compensation expense
|
|
|
6,702 |
|
|
|
2,286 |
|
|
|
1,516 |
|
Retirement
of treasury shares
|
|
|
(5,101 |
) |
|
|
(646 |
) |
|
|
(31,150 |
) |
Excess
tax benefit of stock based compensation
|
|
|
1,031 |
|
|
|
673 |
|
|
|
70 |
|
Balance
at end of year
|
|
|
5,818 |
|
|
|
2,559 |
|
|
|
64 |
|
Retained
earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at beginning of year
|
|
|
393,044 |
|
|
|
360,102 |
|
|
|
158,504 |
|
Cumulative
effect adjustment for the adoption of SAB 108, net of tax
|
|
|
- |
|
|
|
- |
|
|
|
(1,021 |
) |
FIN
48 adoption
|
|
|
- |
|
|
|
(267 |
) |
|
|
- |
|
Retirement
of treasury shares
|
|
|
(447 |
) |
|
|
- |
|
|
|
(35,153 |
) |
Net
income
|
|
|
113,309 |
|
|
|
33,209 |
|
|
|
237,772 |
|
Balance
at end of year
|
|
|
505,906 |
|
|
|
393,044 |
|
|
|
360,102 |
|
Unamortized
stock award
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at beginning of year
|
|
|
- |
|
|
|
- |
|
|
|
(825 |
) |
Reclassification
of unearned compensation pursuant to the adoption of SFAS No.
123(R)
|
|
|
- |
|
|
|
- |
|
|
|
825 |
|
Balance
at end of year
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Treasury
stock, at cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at beginning of year
|
|
|
(226 |
) |
|
|
(170 |
) |
|
|
- |
|
Purchase
of treasury shares
|
|
|
(5,549 |
) |
|
|
(646 |
) |
|
|
(66,319 |
) |
Retirement
of treasury shares
|
|
|
5,549 |
|
|
|
646 |
|
|
|
66,319 |
|
Non-employee
directors' deferred compensation plan
|
|
|
(66 |
) |
|
|
(56 |
) |
|
|
(170 |
) |
Balance
at end of year
|
|
|
(292 |
) |
|
|
(226 |
) |
|
|
(170 |
) |
Total
shareholders' equity
|
|
$ |
511,581 |
|
|
$ |
395,526 |
|
|
$ |
360,144 |
|
See accompanying Notes to
Consolidated Financial Statements.
PETROLEUM
DEVELOPMENT CORPORATION
Consolidated
Statements of Cash Flows
(in
thousands)
Year
Ended December 31,
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
113,309 |
|
|
$ |
33,209 |
|
|
$ |
237,772 |
|
Adjustments
to net income to reconcile to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
59,079 |
|
|
|
12,201 |
|
|
|
86,431 |
|
Depreciation,
depletion and amortization
|
|
|
104,575 |
|
|
|
70,844 |
|
|
|
33,735 |
|
Allowance
for doubtful accounts
|
|
|
180 |
|
|
|
50 |
|
|
|
7 |
|
Amortization
of debt issuance costs
|
|
|
1,344 |
|
|
|
394 |
|
|
|
- |
|
Impairment
of oil and gas properties
|
|
|
22,091 |
|
|
|
1,485 |
|
|
|
1,519 |
|
Accretion
of asset retirement obligation
|
|
|
1,230 |
|
|
|
999 |
|
|
|
515 |
|
Exploratory
dry hole costs
|
|
|
6,504 |
|
|
|
1,775 |
|
|
|
1,790 |
|
Loss
(gain) from sale of leaseholds/assets
|
|
|
19 |
|
|
|
(33,322 |
) |
|
|
(327,991 |
) |
Expired
and abandoned leases
|
|
|
3,633 |
|
|
|
1,786 |
|
|
|
2,169 |
|
Stock
based compensation
|
|
|
6,702 |
|
|
|
2,286 |
|
|
|
1,516 |
|
Unrealized
(gains) losses on derivative transactions
|
|
|
(117,536 |
) |
|
|
4,642 |
|
|
|
(7,620 |
) |
Excess
tax benefits from stock-based compensation
|
|
|
(1,031 |
) |
|
|
(673 |
) |
|
|
(70 |
) |
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase)
decrease in restricted cash
|
|
|
(4,257 |
) |
|
|
(14,254 |
) |
|
|
982 |
|
Increase
in accounts receivable
|
|
|
(9,844 |
) |
|
|
(16,506 |
) |
|
|
(9,942 |
) |
Increase
in accounts receivable - affiliates
|
|
|
(7,631 |
) |
|
|
(2,302 |
) |
|
|
(194 |
) |
(Increase)
decrease in inventories
|
|
|
(2,062 |
) |
|
|
1,285 |
|
|
|
1,987 |
|
(Increase)
decrease in other current assets
|
|
|
(5,793 |
) |
|
|
4,839 |
|
|
|
(2,106 |
) |
Increase
(decrease) in production tax liability
|
|
|
9,857 |
|
|
|
10,802 |
|
|
|
(261 |
) |
Increase
(decrease) in accounts payable and accrued expenses
|
|
|
2,790 |
|
|
|
(10,869 |
) |
|
|
13,010 |
|
Increase
(decrease) in accounts payable - affiliates
|
|
|
10,282 |
|
|
|
(3,099 |
) |
|
|
6,116 |
|
(Decrease)
increase in advances for future drilling contracts
|
|
|
(66,742 |
) |
|
|
13,645 |
|
|
|
4,773 |
|
Increase
(decrease) in federal and state income taxes payable
|
|
|
1,721 |
|
|
|
(27,124 |
) |
|
|
19,950 |
|
Increase
in funds held for future distribution
|
|
|
10,538 |
|
|
|
7,488 |
|
|
|
(575 |
) |
Other
|
|
|
143 |
|
|
|
723 |
|
|
|
3,877 |
|
Net
cash provided by operating activities
|
|
|
139,101 |
|
|
|
60,304 |
|
|
|
67,390 |
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(323,153 |
) |
|
|
(238,988 |
) |
|
|
(146,945 |
) |
Acquisition
of oil and gas properties, net of cash acquired
|
|
|
- |
|
|
|
(255,661 |
) |
|
|
(18,512 |
) |
Investment
in drilling partnerships
|
|
|
- |
|
|
|
- |
|
|
|
(7,151 |
) |
(Increase)
decrease in restricted/designated cash
|
|
|
(874 |
) |
|
|
191,156 |
|
|
|
(192,416 |
) |
Proceeds
from sale of leases to partnerships
|
|
|
448 |
|
|
|
1,371 |
|
|
|
1,798 |
|
Proceeds
from sale of leaseholds/assets
|
|
|
538 |
|
|
|
34,701 |
|
|
|
353,600 |
|
Net
cash used in investing activities
|
|
|
(323,041 |
) |
|
|
(267,421 |
) |
|
|
(9,626 |
) |
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from credit facility
|
|
|
419,000 |
|
|
|
352,000 |
|
|
|
302,000 |
|
Proceeds
from senior notes
|
|
|
200,101 |
|
|
|
- |
|
|
|
- |
|
Proceeds
from short-term debt
|
|
|
- |
|
|
|
- |
|
|
|
20,000 |
|
Payment
of credit facility
|
|
|
(459,500 |
) |
|
|
(254,000 |
) |
|
|
(209,000 |
) |
Payment
of debt issuance costs
|
|
|
(5,571 |
) |
|
|
(1,468 |
) |
|
|
(160 |
) |
Proceeds
from exercise of stock options
|
|
|
627 |
|
|
|
183 |
|
|
|
31 |
|
Excess
tax benefits from stock-based compensation
|
|
|
1,031 |
|
|
|
673 |
|
|
|
70 |
|
Minority
interest investment
|
|
|
- |
|
|
|
800 |
|
|
|
- |
|
Purchase
of treasury stock
|
|
|
(5,549 |
) |
|
|
(646 |
) |
|
|
(66,489 |
) |
Net
cash provided by financing activities
|
|
|
150,139 |
|
|
|
97,542 |
|
|
|
46,452 |
|
Net
(decrease) increase in cash and cash equivalents
|
|
|
(33,801 |
) |
|
|
(109,575 |
) |
|
|
104,216 |
|
Cash
and cash equivalents, beginning of year
|
|
|
84,751 |
|
|
|
194,326 |
|
|
|
90,110 |
|
Cash
and cash equivalents, end of year
|
|
$ |
50,950 |
|
|
$ |
84,751 |
|
|
$ |
194,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
payments for:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest,
net of capitalized interest
|
|
$ |
19,200 |
|
|
$ |
9,535 |
|
|
$ |
1,376 |
|
Income
taxes, net of refunds
|
|
|
(530 |
) |
|
|
43,785 |
|
|
|
46,735 |
|
Non-cash
investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in deferred tax liability resulting from reallocation of acquisition
purchase price
|
|
|
- |
|
|
|
4,188 |
|
|
|
- |
|
Change
in accounts payable - affiliates related to acquisition of
partnerships
|
|
|
- |
|
|
|
668 |
|
|
|
- |
|
Change
in accounts payable related to purchases of properties and
equipment
|
|
|
8,197 |
|
|
|
32,820 |
|
|
|
1,800 |
|
Change
in accounts payable - affiliates related to investment in drilling
partnership
|
|
|
- |
|
|
|
18,712 |
|
|
|
(7,151 |
) |
Change
in asset retirement obligation, with a corresponding increase to oil and
gas properties, net of disposals
|
|
|
1,153 |
|
|
|
7,850 |
|
|
|
3,164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying Notes to Consolidated Financial Statements.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Petroleum
Development Corporation (“PDC,” “we,” “us” or “the Company”) is an independent
energy company engaged primarily in the drilling and development, production and
marketing of natural gas and oil. Since we began oil and gas
operations in 1969, we have grown primarily through drilling and development
activities, the acquisition of producing natural gas and oil wells and the
expansion of our natural gas marketing activities. As of December 31,
2008, we operate approximately 4,712 wells located in the Appalachian Basin,
Michigan Basin, and the Rocky Mountain Region. Our oil and natural
gas wells are located in West Virginia, Tennessee, Pennsylvania, Michigan, North
Dakota, Colorado, Kansas, Texas and Wyoming. We separate our
operations into four business segments: oil and gas sales, natural gas marketing
activities, well operations and pipeline income and oil and gas well drilling
operations. See Note 16, Business
Segments.
Principles of
Consolidation
The
consolidated financial statements of PDC include the accounts of our
wholly-owned subsidiaries and WWWV, LLC, an entity in which we have a
controlling financial interest. All material intercompany accounts
and transactions have been eliminated in consolidation. We account
for our investment in interests in oil and gas limited partnerships under the
proportionate consolidation method. Under this method, our
consolidated financial statements include our investments in the partnerships
recorded by our working interest in each well thereby accumulating our pro rata
share of assets, liabilities and revenues and expenses respectively of the
limited partnerships in which we participate. Our proportionate share
of all significant transactions between us and the limited partnerships is
eliminated.
Use
of Estimates
The
preparation of our consolidated financial statements in accordance with
generally accepted accounting principles in the United States of America
(“U.S.”) requires us to make estimates and assumptions that affect the amounts
reported in our consolidated financial statements and accompanying
notes. Actual results could differ from those
estimates. Estimates which are particularly significant to our
consolidated financial statements include estimates of oil and gas reserves,
future cash flows from oil and gas properties, valuation of derivative
instruments and valuation of deferred income tax assets.
Cash
Equivalents
For
purposes of the statement of cash flows, we consider all highly liquid debt
instruments with original maturities of three months or less to be cash
equivalents.
Restricted Cash
Included
in our restricted cash – current as of December 31, 2007, along with interest
earned of $0.4 million, is an escrow account funded in June 2007 in the amount
of $14.1 million, representing amounts due to the limited partners of our
sponsored drilling partnerships as a result of our over withholding estimated
production taxes in years prior to 2007. In October 2008, as part of
a pre-filing agreement, we paid the Internal Revenue Service on behalf of the
limited partners an estimated tax payment of $4.2 million. As of
December 31, 2008, we had reflected in restricted cash - current $10.6 million,
including additional interest of $0.3 million earned in 2008.
Pursuant
to a preliminary court approved litigation settlement agreement reached in
October 2008, we funded an escrow account in November 2008 in the amount of $8.2
million, of which $5.8 million represented the Company’s share of the settlement
and the remainder being that of the affiliated partnerships for which the
Company serves as the managing general partner. As of December 31,
2008, restricted cash – current includes $8.2 million related to this escrow
account. Further, our balance sheet includes a related accounts
receivable from our affiliated partnerships of $2.4 million.
We are
required by a counterparty to maintain a margin deposit for outstanding
derivative contracts. As of December 31, 2007, cash in the amount of
$0.3 million was on deposit and reflected in our consolidated balance sheets as
restricted cash - current. As of December 31, 2008, the margin
deposit requirement was insignificant.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We are
required by various government agencies or joint venture agreements to maintain
a bond or cash account for the plugging and abandonment of wells. As
of December 31, 2008 and 2007, we had bonds in the form of certificates of
deposit for plugging and abandonment of wells totaling $2.2 million and $1.3
million, respectively, which are reflected in other assets.
Accounts
Receivable
Our
accounts receivable are primarily from purchasers of oil and natural gas and
third parties and affiliated partnerships for well pipeline operating
services. Inherent to our industry is the concentration of oil and
natural gas sales to a few customers. This industry concentration has
the potential to impact our overall exposure to credit risk, either positively
or negatively, in that our customers may be similarly affected by changes in
economic, industry or other conditions.
We
provide an allowance for doubtful accounts equal to the estimated uncollectible
amounts. In making our estimate, we consider our historical
write-offs, relationships and overall creditworthiness of our customers,
additional consideration is given to well production data for receivables
related to well operations. It is reasonably possible that our
estimate of uncollectible amounts will change periodically. Accounts
receivable are presented on our consolidated balance sheets net of allowance for
doubtful accounts of $0.5 million and $0.4 million at December 31, 2008 and
2007, respectively.
Inventories
Materials,
supplies and commodity inventories are stated at the lower of average cost or
market and removed at carrying value. Inventory of $4.3 million and
$2.2 million as of December 31, 2008 and 2007, respectively, is included in
prepaid expenses and other current assets on our consolidated balance
sheets.
Derivative
Financial Instruments
We
account for derivative financial instruments in accordance with Statement of
Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative
Instruments and Certain Hedging Activities, as amended.
During
2008, 2007 and 2006, none of our derivative instruments qualified for use of
hedge accounting under the terms of SFAS No. 133. Accordingly, we
recognize all derivative instruments as either assets or liabilities on our
consolidated balance sheets at fair value, and changes in the derivatives' fair
values are recorded on a net basis in our consolidated statements of
operations. Changes in the fair value of derivative instruments
related to our oil and gas sales activities are recorded in oil and gas price
risk management, net and changes in fair value of derivatives related to our
natural gas marketing activities are recorded in sales from and cost of natural
gas marketing activities.
We record
on our consolidated balance sheets the fair value of derivative instruments
entered into by us and allocated to our affiliated partnerships, recording an
offsetting receivable from or payable to those partnerships.
See Note 2, Fair Value of Financial
Instruments, and Note 3, Derivative Financial
Instruments, for a discussion of our derivative fair value measurements
and a summary fair value table of our open positions as of December 31, 2008 and
2007, respectively.
Properties
and Equipment
Oil
and Gas Properties.
We
account for our oil and gas properties under the successful efforts method of
accounting. Costs of proved developed producing properties,
successful exploratory wells and development dry hole costs are capitalized and
depreciated or depleted by the unit-of-production method based on estimated
proved developed producing oil and natural gas reserves. Property
acquisition costs are depreciated or depleted on the unit-of-production method
based on estimated proved oil and gas reserves.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Our
estimates of proved reserves are based on quantities of oil and natural gas that
engineering and geological analysis demonstrates, with reasonable certainty, to
be recoverable from established reservoirs in the future under current operating
and economic conditions. Annually, we engage independent petroleum
engineers to prepare a reserve and economic evaluation of all our properties on
a well-by-well basis as of December 31. Additionally, we adjust our
oil and gas reserves for major acquisitions, new drilling and divestitures
during the year as needed. The process of estimating and evaluating
oil and natural gas reserves is complex, requiring significant decisions in the
evaluation of available geological, geophysical, engineering and economic
data. The data for a given property may also change substantially
over time as a result of numerous factors, including additional development
activity, evolving production history and a continual reassessment of the
viability of production under changing economic conditions. As a
result, revisions in existing reserve estimates occur from time to
time. Although every reasonable effort is made to ensure that reserve
estimates reported represent our most accurate assessments possible, the
subjective decisions and variances in available data for various properties
increase the likelihood of significant changes in these
estimates. Because estimates of reserves significantly affect our
depreciation, depletion and amortization (“DD&A”) expense, a change in our
estimated reserves could have an effect on our net income.
Exploration
costs, including geological and geophysical expenses and delay rentals, are
charged to expense as incurred. Exploratory well drilling costs,
including the cost of stratigraphic test wells, are initially capitalized but
charged to expense if the well is determined to be nonproductive. The
status of each in-progress well is reviewed quarterly to determine the proper
accounting treatment under the successful efforts method of
accounting. Exploratory well costs continue to be capitalized as long
as the well has found a sufficient quantity of reserves to justify our
completion as a producing well and we are making sufficient progress assessing
our reserves and economic and operating viability. If an in-progress
exploratory well is found to be unsuccessful (referred to as a dry hole) prior
to the issuance of the financial statements, the costs incurred prior to the end
of the reporting period are expensed to exploration costs. If we are
unable to make a final determination about the productive status of a well prior
to issuance of the financial statements, the costs associated with the well are
classified as “suspended well costs” until we have had sufficient time to
conduct additional completion or testing operations to evaluate the pertinent
geological and engineering data obtained. At the time when we are
able to make a final determination of a well’s productive status, the same well
is removed from the suspended well status and the proper accounting treatment is
recorded. At December 31, 2008, suspended well costs included in oil
and gas properties on our consolidated balance sheet were $1.2
million. See Note 4, Properties and
Equipment.
The
acquisition costs of unproved properties are capitalized when incurred, until
such properties are transferred to proved properties or charged to expense when
expired, impaired or amortized. Unproved oil and gas properties with
individually significant acquisition costs are periodically assessed, and any
impairment in value is charged to exploratory expense. The amount of
impairment recognized on unproved properties which are not individually
significant is determined by amortizing the costs of such properties within
appropriate fields based on our historical experience, acquisition dates and
average lease terms. Impairment costs are recorded in the statements
of operations as a component of exploration expense and were as follows for each
of the periods indicated:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
Individually
significant unproved properties (1)
|
|
$ |
9,165 |
|
|
$ |
1,484 |
|
|
$ |
473 |
|
Insignificant
unproved properties
|
|
|
3,633 |
|
|
|
1,786 |
|
|
|
157 |
|
Total
|
|
$ |
12,798 |
|
|
$ |
3,270 |
|
|
$ |
630 |
|
__________
|
(1)
|
2007
includes liquidated damages of $1.1 million related to the abandonment of
an exploration agreement with an unaffiliated
party.
|
The
valuation of unproved properties is subjective and requires us to make estimates
and assumptions which, with the passage of time, may prove to be materially
different from actual realizable values.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In
accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, we assess our oil and gas properties for
possible impairment quarterly by comparing net capitalized costs to estimated
undiscounted future net cash flows on a field-by-field basis using estimated
production based upon prices at which we reasonably estimate the commodity to be
sold. The estimates of future prices may differ from current market
prices of oil and natural gas. Any downward revisions in estimates to
our reserve quantities, expectations of falling commodity prices or rising
operating costs could result in a reduction in undiscounted future net cash
flows and an impairment of our oil and gas properties. If net
capitalized costs exceed undiscounted future net cash flows, the measurement of
impairment is based on estimated fair value which would consider future
discounted cash flows. We recognized impairment losses on proved oil
and gas properties of $12.8 million in 2008, consisting of $7.5 million related
to our properties in the Fort Worth Basin, $3 million in our Bakken Field in
North Dakota and $2.3 million in our Nesson Field also in North
Dakota. In 2006, we recorded an impairment loss of $1.5 million in
our Nesson Field. Impairment charges related to our oil and gas
properties are included in our statements of operations as a component of
exploration expense. No impairments related to proved oil and natural gas
properties were recorded in 2007.
Upon sale
or retirement of significant portions of or complete fields of depreciable or
depletable property, the net book value thereof, less proceeds or salvage value,
is credited or charged to income. Upon sale of individual wells, the
proceeds are credited to property costs.
Other
Property and Equipment.
The
following table sets forth the estimated useful lives of our other property and
equipment.
Pipelines
and related facilities
|
10
- 17 years
|
Transportation
and other equipment
|
3 -
20 years
|
Buildings
|
30
- 40 years
|
Pipelines, Transportation Equipment
and Other Equipment. Pipelines, transportation equipment and
other equipment are carried at cost. Depreciation is provided
principally on the straight-line method over the assets estimated useful
lives. In accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, long-lived assets, such as property, plant
and equipment, are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. Recoverability of assets to be held and used is measured
by a comparison of the carrying amount of an asset to estimated undiscounted
future cash flows expected to be generated by the asset. If the
carrying amount of an asset exceeds our estimated future cash flows, an
impairment charge is recognized in the amount by which the carrying amount of
the asset exceeds the fair value of the asset. No impairments were
recorded in 2008, 2007or 2006.
Buildings. Buildings
are carried at cost and depreciated on the straight-line method over their
estimated useful lives.
Maintenance
and repairs on other property and equipment are charged to expense as
incurred. Major renewals and improvements are
capitalized. Upon the sale or other disposition of assets, the cost
and related accumulated depreciation, depletion and amortization are removed
from the accounts, the proceeds are applied thereto and any resulting gain or
loss is reflected in income.
Total
depreciation expense related to other property and equipment was $7.6 million,
$4.3 million and $2 million in 2008, 2007 and 2006, respectively.
Capitalized
Interest
Interest
costs are capitalized as part of the historical cost of acquiring
assets. Oil and gas investments in unproved properties and major
development projects, on which DD&A expense is not currently recorded and on
which exploration or development activities are in progress, qualify for
capitalization of interest. Major construction projects also qualify
for interest capitalization until the asset is ready for
service. Capitalized interest is calculated by multiplying our
weighted-average interest rate on our debt outstanding by the qualifying
costs. Interest capitalized may not exceed gross interest expense for
the period. As the qualifying asset is moved to the DD&A pool,
the related capitalized interest is also transferred and is amortized over the
useful life of the asset. Interest costs of $2.6 million, $3 million
and $1.6 million were capitalized in 2008, 2007 and 2006,
respectively.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Production
Tax Liability
Production
tax liability represents estimated taxes, primarily severance and property, to
be paid to the states and counties in which we produce oil and
gas. Our share of these taxes is expensed to oil and gas production
and well operations cost.
Advances
for Future Drilling Contracts
Advances
for future drilling contracts represent funds received from our sponsored
drilling partnerships for drilling activities which have not been completed, a
portion of which will be recognized as revenue in accordance with our revenue
recognition policies. The amount advanced and outstanding as of
December 31, 2008, are primarily related to the drilling partnership sponsored
in August 2007 and represents the remaining costs to finish the wells, primarily
reclamation. No partnership was sponsored in 2008.
Income
Taxes
We
account for income taxes under the asset and liability method. We
recognize deferred tax assets and liabilities 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. The
effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment
date. If we determine that it is more likely than not that some
portion or all of the deferred tax assets will not be realized, we record a
valuation allowance thereby reducing the deferred tax assets to what we consider
realizable. No valuation allowance was recorded at December 31, 2008
or 2007.
Asset
Retirement Obligations
We
account for asset retirement obligations by recording the fair value of our
plugging and abandonment obligations when incurred, which is at the time the
well is completely drilled. Upon initial recognition of an asset
retirement obligation, we increase the carrying amount of the long-lived asset
by the same amount as the liability. Over time, the liabilities are
accreted for the change in their present value, through charges to oil and gas
production and well operations costs. The initial capitalized costs
are depleted over the useful lives of the related assets, through charges to
depreciation, depletion and amortization. If the fair value of the
estimated asset retirement obligation changes, an adjustment is recorded to both
the asset retirement obligation and the asset retirement
cost. Revisions in estimated liabilities can result from revisions of
estimated inflation rates, escalating retirement costs and changes in the
estimated timing of settling asset retirement obligations. See Note 7, Asset Retirement Obligations,
for a reconciliation of asset retirement obligation activity.
Minority
Interest in Consolidated Limited Liability Company
In May
2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (“LLC”), a
limited liability company for which we serve as the managing
member. One-sixth of the entity is owned by a member of our Board of
Directors, who paid the same unit price for his interest as was paid by us and
unrelated third parties for such interests in the LLC. The LLC's only
asset is an aircraft and the LLC was formed for the purpose of owning and
operating the aircraft.
The
minority interest portion of pre-tax expense incurred by and belonging to the
minority interest holders of the consolidated limited liability company is not
material and is included in our consolidated statement of operations as an
offset to DD&A expense.
Retirement
of Treasury Shares
We
have historically retired all treasury share purchases, with the exception of
shares purchased in accordance with our non-employee deferred compensation plan
for non-employee directors, see Note 9, Common Stock. As
treasury shares are retired, we charge any excess of cost over the par value
entirely to additional paid-in-capital, to the extent we have amounts in
paid-in-capital, with any remaining excess cost being charged to retained
earnings.
Revenue
Recognition
Oil and natural gas
sales. Sales of oil are recognized when persuasive evidence of
a sales arrangement exists, the oil is verified as produced and is delivered to
a purchaser, collection of revenue from the sale is reasonably assured and the
sales price is determinable. We are currently able to sell all the
oil that we can produce under existing sales contracts with petroleum refiners
and marketers. We do not refine any of our oil
production. Our crude oil production is sold to purchasers at or near
our wells under short-term purchase contracts at prices and in accordance with
arrangements that are customary in the oil industry.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Sales of
natural gas are recognized when natural gas has been delivered to a custody
transfer point, persuasive evidence of a sales arrangement exists, the rights
and responsibility of ownership pass to the purchaser upon delivery, collection
of revenue from the sale is reasonably assured and the sales price is fixed or
determinable. Natural gas is sold by us under contracts with terms
ranging from one month to three years. Virtually all of our contract
pricing provisions are tied to a market index, with certain adjustments based
on, among other factors, whether a well delivers to a gathering or transmission
line, quality of natural gas and prevailing supply and demand conditions, so
that the price of the natural gas fluctuates to remain competitive with other
available natural gas supplies. As a result, our revenues from the
sale of natural gas will suffer if market prices decline and benefit if they
increase. We believe that the pricing provisions of our natural gas
contracts are customary in the industry.
We
currently use the “net-back” method of accounting for transportation
arrangements of our natural gas sales. We sell gas at the wellhead
and collect a price and recognize revenues based on the wellhead sales price
since transportation costs downstream of the wellhead are incurred by the
customers and reflected in the wellhead price.
Natural gas marketing
activities. Natural gas marketing is reported on the gross
accounting method, based on the nature of the agreements between RNG, our
suppliers and our customers. RNG, our marketing subsidiary, purchases
gas from many small producers and bundles the gas together to sell in larger
amounts to purchasers of natural gas for a price advantage. RNG has
latitude in establishing price and discretion in supplier and purchaser
selection. Natural gas marketing revenues and expenses reflect the
full cost and revenue of those transactions because RNG takes title to the gas
it purchases from the various producers and bears the risks and rewards of that
ownership. Both the realized and unrealized gains and losses of the
RNG commodity based derivative transactions for natural gas marketing activities
are included in gas sales from marketing activities or cost of gas marketing
activities, as applicable.
Oil and gas well
drilling. Our drilling segment recognizes revenue from
drilling contracts with sponsored drilling programs using the percentage of
completion method based upon the percentage of contract costs incurred to date
to the estimated total contract costs for each contract. We utilize
this method since reasonably dependable estimates of the total estimated costs
can be made and recognized revenues are subject to revisions as a contract
progresses, the term of which can range from three to twelve
months. We have offered our drilling services under two types of
contractual arrangements, cost-plus or footage-based service contracts, which
result in differing risk and reward relationships, and consequently, different
revenue reporting policies pursuant to Emerging Issues Task Force (“EITF”) Issue
No. 99-19, Reporting Revenue
Gross as a Principal versus Net as an Agent.
The first
cost-plus drilling service arrangement was entered into in late 2005 with
drilling activity commencing in the first quarter of 2006. Due to the
fixed-fee-percentage nature of our revenues from these services, we have
determined that, in substance, we are acting as an agent, without risk of loss
during the performance of the drilling activities. Accordingly, our
services provided under the cost-plus drilling agreements are reported on a net
basis. We entered into our second and third cost-plus drilling
arrangements in September 2006 and August 2007 and commenced drilling
immediately.
Footage-based
contracts provide for the drilling, completion and equipping of wells at footage
rates and are generally completed within nine to twelve months after the
commencement of drilling. We provide geological, engineering, and
drilling supervision on the drilling and completion process and use
subcontractors to perform drilling and completion services and accordingly we
have the risk of loss in performing services under these
arrangements. Accordingly, we report revenue under these agreements
gross of related expenses. Anticipated losses, if any, on uncompleted
contracts are recorded at the time that the estimated total costs exceed the
estimated total contract revenue. At December 31, 2007, included as a
component of other current liabilities on the consolidated balance sheets, we
had recorded a loss contract reserve of $0.2 million. No loss
contract reserve was recorded as of December 31, 2008.
Well operations and pipeline
income. Well operations and pipeline income are recognized
when persuasive evidence of an arrangement exists, services have been rendered,
collection of revenues is reasonably assured and the sales price is fixed or
determinable. We are paid a monthly operating fee for each well we
operate and natural gas transported for outside owners including the limited
partnerships we sponsored. The fee covers monthly operating and
accounting costs, insurance and other recurring costs. We may also
receive additional compensation for special non-recurring activities, such as
reworks and recompletions.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Stock-Based
Compensation
On
January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS
No. 123R”), to account for stock-based compensation. SFAS No. 123R
eliminated the use of Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to
Employees, and the intrinsic value method of accounting for equity
compensation and requires us to recognize the cost of employee services received
in exchange for awards of equity instruments based on fair value at the date of
grant in our financial statements. We elected to use the modified
prospective method for adoption, and accordingly, prior period financial
statements have not been restated. For all unvested options and other
equity based awards outstanding as of January 1, 2006, the previously measured
but unrecognized compensation expense, based on the fair value at the original
grant date, will be recognized in the financial statements over the remaining
requisite service period for each separately vesting portion. For
equity-based compensation awards granted or modified subsequent to January 1,
2006, compensation expense, based on the fair value on the date of grant or
modification, will be recognized in the financial statements on a straight-line
basis over the vesting period for the entire award. To the extent
compensation cost relates to employees directly involved in oil and natural gas
acquisition, exploration and development activities, such amounts are
capitalized to properties and equipment. Amounts not capitalized to
properties and equipment are recognized in the appropriate cost and expense line
item in the statement of operations. No amounts for stock-based
compensation were capitalized in 2008, 2007 and 2006.
Earnings
Per Share
Basic
earnings per common share (“EPS”) is computed by dividing net income (the
numerator) by the weighted-average number of common shares outstanding for the
period (the denominator). Diluted EPS is similarly computed except
that the denominator includes the effect, using the treasury stock method, of
our outstanding stock options, unamortized portion of restricted stock and
shares held pursuant to our non-employee director deferred compensation plan, if
including such potential shares of common stock is dilutive.
The
following is a reconciliation of the basic and diluted weighted-average shares
outstanding for the years ended December 31:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average common shares outstanding - basic
|
|
|
14,736 |
|
|
|
14,744 |
|
|
|
15,660 |
|
Dilutive
effect of share-based compensation: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Unamortized
portion of restricted stock
|
|
|
71 |
|
|
|
44 |
|
|
|
22 |
|
Stock
options
|
|
|
35 |
|
|
|
48 |
|
|
|
55 |
|
Non
employee director deferred compensation
|
|
|
6 |
|
|
|
5 |
|
|
|
4 |
|
Weighted
average common and common share equivalents outstanding -
diluted
|
|
|
14,848 |
|
|
|
14,841 |
|
|
|
15,741 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Weighted average common share equivalents excluded from diluted
earnings per share due to their anti-dilutive affect:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unamortized
portion of restricted stock
|
|
|
73 |
|
|
|
18 |
|
|
|
- |
|
Stock
options
|
|
|
- |
|
|
|
- |
|
|
|
24 |
|
Total
anti-dilutive common share equivalents
|
|
|
73 |
|
|
|
18 |
|
|
|
24 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Recent
Accounting Standards
Recently Adopted Accounting
Standards
We
adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements,
effective January 1, 2008. SFAS No. 157 defines fair value,
establishes a framework for measuring fair value and expands disclosures related
to fair value measurements. SFAS No. 157 applies broadly to financial and
nonfinancial assets and liabilities that are measured at fair value under other
authoritative accounting pronouncements, but does not expand the application of
fair value accounting to any new circumstances. In February 2008, the
Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”)
FAS No. 157-2, Effective Date
of FASB Statement No. 157, which delays the effective date of SFAS No.
157 by one year (to January 1, 2009) for nonfinancial assets and liabilities,
except those that are recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually). Nonfinancial
assets and liabilities for which we have not applied the provisions of SFAS No.
157 include those initially measured at fair value, including our asset
retirement obligations. As of the adoption date, we have applied the
provisions of SFAS No. 157 to our recurring measurements and the impact was not
material to our underlying fair values and no amounts were recorded relative to
the cumulative effect of a change in accounting. We are currently
evaluating the potential effect that the nonfinancial assets and liabilities
provisions of SFAS No. 157 will have on our financial statements when adopted in
2009. See Note 2, Fair Value of Financial
Instruments.
In
October 2008, the FASB issued FSP No. FAS 157-3, Determining the Fair Value of a
Financial Asset in a Market That Is Not Active, which applies to
financial assets within the scope of accounting pronouncements that require or
permit fair value measurements in accordance with SFAS No. 157. This FSP
clarifies the application of SFAS No. 157 in a market that is not active and
defines additional key criteria in determining the fair value of a financial
asset when the market for that financial asset is not active. FSP No.
FAS 157-3 was effective upon issuance and did not have a material impact on our
financial statements.
In
February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities. SFAS No. 159 permits
entities to choose to measure, at fair value, many financial instruments and
certain other items that are not currently required to be measured at fair
value. The objective is to improve financial reporting by providing
entities with the opportunity to mitigate volatility in reported earnings caused
by measuring related assets and liabilities differently without having to apply
complex hedge accounting provisions. SFAS No. 159 establishes
presentation and disclosure requirements designed to facilitate comparisons
between entities that choose different measurement attributes for similar types
of assets and liabilities. The statement will be effective as of the
beginning of an entity's first fiscal year beginning after November 15,
2007. We have not elected to measure additional financial assets and
liabilities at fair value.
In April
2007, the FASB issued FSP No. FIN 39-1, Amendment of FASB Interpretation No.
39 (“FIN 39-1”), to amend certain portions of Interpretation
39. FIN 39-1 replaces the terms “conditional contracts” and “exchange
contracts” in Interpretation 39 with the term “derivative instruments” as
defined in Statement 133. FIN 39-1 also amends Interpretation 39 to
allow for the offsetting of fair value amounts for the right to reclaim cash
collateral or receivable, or the obligation to return cash collateral or
payable, arising from the same master netting arrangement as the derivative
instruments. FIN 39-1 applies to fiscal years beginning after
November 15, 2007, with early adoption permitted. The January 1,
2008, adoption of FSP FIN 39-1 had no impact on our financial
statements.
In June
2006, the FASB issued EITF No. 06-3, How Taxes Collected from Customers
and Remitted to Governmental Authorities Should be Presented in the Income
Statement (That Is, Gross versus Net Presentation). EITF 06-3
addresses the income statement presentation of any tax collected from customers
and remitted to a government authority and concludes that the presentation of
taxes on either a gross basis or a net basis is an accounting policy decision
that should be disclosed pursuant to APB No. 22, Disclosures of Accounting
Policies. For taxes that are reported on a gross basis
(included in revenues and costs), EITF 06-3 requires disclosure of the amounts
of those taxes in interim and annual financial statements, if those amounts are
significant. EITF 06-3 became effective for interim and annual
reporting periods beginning after December 15, 2006. The adoption of
the standard, effective January 1, 2007, did not have a significant effect on
our consolidated financial statements. Our existing accounting
policy, which was not changed upon the adoption of EITF 06-3, is to present
taxes within the scope of EITF 06-3 on a net basis.
In July
2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income
Taxes - an Interpretation of FASB Statement 109, which prescribes a
comprehensive model for accounting for uncertainty in tax
positions. FIN No. 48 provides that the tax effects from an uncertain
tax position can be recognized in the financial statements, only if the position
is more likely than not of being sustained on audit by the Internal Revenue
Service (“IRS”), based on the technical merits of the position. We
adopted the provisions of FIN No. 48 effective January 1, 2007. The
cumulative effect of applying the provisions of FIN No. 48 has been accounted
for as an adjustment to retained earnings in the first quarter of
2007. The adoption of FIN No. 48 resulted in a $0.3 million
cumulative effect adjustment (see Note 5, Income Taxes, for further
discussion).
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In May
2007, the FASB issued FASB Staff Position FIN No. 48-1, Definition of Settlement in FASB
Interpretation No. 48 (“FIN No. 48-1”). FIN No. 48-1 amends
FIN No. 48 to provide guidance on how an entity should determine whether a tax
position is effectively settled for the purpose of recognizing previously
unrecognized tax benefits. The term “effectively settled” replaces
the term “ultimately settled” when used to describe recognition, and the terms
“settlement” or “settled” replace the terms “ultimate settlement” or “ultimately
settled” when used to describe measurement of a tax position under FIN No.
48. FIN No. 48-1 clarifies that a tax position can be effectively
settled upon the completion of an examination by a taxing authority without
being legally extinguished. For tax positions considered effectively
settled, an entity would recognize the full amount of tax benefit, even if the
tax position is not considered more likely than not to be sustained based solely
on the basis of its technical merits and the statute of limitations remains
open. The adoption of FIN No. 48-1, effective January 1, 2007, did
not have an incremental effect on our consolidated financial
statements.
In
September 2006, the Securities and Exchange Commission (“SEC”) issued Staff
Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior
Year Misstatements when Quantifying Misstatements in Current Year Financial
Statements. SAB No. 108 provides guidance on how the effects
of prior year misstatements should be considered in quantifying misstatements in
the current year financial statements. SAB No. 108 requires
registrants to quantify misstatements using both the income statement
(“rollover”) and balance sheet (“iron curtain”) approach and evaluate whether
either approach results in a misstatement that, when all relevant quantitative
and qualitative factors are considered, is material. Historically, we
evaluated uncorrected misstatements using the “rollover” method which resulted
in an accumulation of quantitatively and qualitatively immaterial misstatements
to our consolidated financial statements. SAB No. 108 provides for a
one time transitional adjustment to retained earnings for errors which were not
deemed material to prior year financial statements, but which is material under
guidance of SAB No. 108. We adopted SAB No. 108 during the fourth
quarter of 2006 and recorded a one-time adjustment to reduce retained earnings
by $1.0 million.
In
December 2004, the FASB issued SFAS No. 123(R), Share-Based
Payment. In March 2005, the SEC issued Staff Accounting
Bulletin (“SAB”) No. 107, Share-Based Payment,
regarding the interaction between SFAS No. 123(R) and certain SEC rules and
regulations. Effective January 1, 2006, we adopted SFAS No. 123(R).
We elected to use the modified prospective method for adoption, which requires
compensation expense to be recognized in the statement of operations for all
unvested stock options and other equity-based compensation beginning in the
first quarter of adoption. Prior to the adoption of SFAS No. 123(R),
we followed the intrinsic value method in accordance with APB No. 25 (as
amended) to account for employee stock-based compensation. The
adoption of SFAS No. 123(R) required the unamortized stock award recorded under
APB No. 25 related to stock-based compensation awards as of January 1, 2006, in
the amount of $0.8 million to be eliminated against additional
paid-in-capital. See Stock-Based Compensation
policy above and Note 9, Common Stock, for further
discussion of the Company's accounting for share-based compensation
awards.
Recently Issued Accounting
Standards
In
December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS
No. 141R”). SFAS No. 141R requires an acquirer to recognize the
assets acquired, the liabilities assumed and any noncontrolling interest in the
acquiree at their acquisition-date fair values. SFAS No. 141R also
requires disclosure of the information necessary for investors and other users
to evaluate and understand the nature and financial effect of the business
combination. Additionally, SFAS No. 141R requires that
acquisition-related costs be expensed as incurred. The provisions of
SFAS No. 141R will become effective for acquisitions completed on or after
January 1, 2009; however, the income tax provisions of SFAS No. 141R will become
effective as of that date for all acquisitions, regardless of the acquisition
date. SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes,
to require the acquirer to recognize changes in the amount of its deferred tax
benefits recognizable due to a business combination either in income from
continuing operations in the period of the combination or directly in
contributed capital, depending on the circumstances. SFAS No. 141R
further amends SFAS No. 109 and FIN 48, Accounting for Uncertainty in Income
Taxes, to require, subsequent to a prescribed measurement period, changes
to acquisition-date income tax uncertainties to be reported in income from
continuing operations and changes to acquisition-date acquiree deferred tax
benefits to be reported in income from continuing operations or directly in
contributed capital, depending on the circumstances. Upon our
adoption of SFAS No. 141R effective January 1, 2009, we will recognize expense
of $1.4 million in deferred acquisition related costs.
In
December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements—An Amendment of ARB No.
51. SFAS No. 160 states that accounting and reporting for
minority interests will be recharacterized as non-controlling interests and
classified as a component of equity. Additionally, SFAS No. 160
establishes reporting requirements that provide sufficient disclosures which
clearly identify and distinguish between the interests of the parent and the
interests of the non-controlling owners. SFAS No. 160 is effective as
of the beginning of an entity’s first fiscal year beginning after December 15,
2008. We are evaluating the impact that SFAS No. 160 will have, if
any, on our consolidated financial statements and related disclosures when it is
adopted in 2009.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities—An Amendment of FASB Statement No.
133, which changes the disclosure requirements for derivative instruments
and hedging activities. Enhanced disclosures are required to provide
information about (a) how and why an entity uses derivative instruments, (b) how
derivative instruments and related hedged items are accounted for under
Statement 133 and its related interpretations and (c) how derivative instruments
and related hedged items affect an entity’s financial position, financial
performance and cash flows. SFAS No. 161 is effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008, with early application encouraged. As SFAS No. 161 is
disclosure related, we do not expect its adoption to have a material impact on
our financial statements.
In
January 2009, the SEC published its final rule, Modernization of Oil and Gas
Reporting, which modifies the SEC’s reporting and disclosure rules for
oil and natural gas reserves. The most notable changes of the final
rule include the replacement of the single day period-end pricing to value oil
and natural gas reserves to a 12-month average of the first day of the month
price for each month within the reporting period. The final rule also
permits voluntary disclosure of probable and possible reserves, a disclosure
previously prohibited by SEC rules. The revised reporting and
disclosure requirements are effective for our Form 10-K for the year ended
December 31, 2009. Early adoption is not permitted. We are
evaluating the impact that adoption of this final rule will have on our
consolidated financial statements, related disclosure and management’s
discussion and analysis.
NOTE
2 – FAIR VALUE OF FINANCIAL INSTRUMENTS
Derivative Financial
Instruments.
Determination of fair
value. We measure fair value based upon quoted market
prices, where available. Our valuation determination includes: (1)
identification of the inputs to the fair value methodology through the review of
counterparty statements and other supporting documentation, (2) determination of
the validity of the source of the inputs, (3) corroboration of the original
source of inputs through access to multiple quotes, if available, or other
information and (4) monitoring changes in valuation methods and
assumptions. The methods described above may produce a fair value
calculation that may not be indicative of future fair values. Our
valuation determination also gives consideration to our nonperformance risk on
our own liabilities as well as the credit standing of our
counterparties. We primarily use two investment grade financial
institutions as our counterparties to our derivative contracts. We
have evaluated the credit risk of our derivative assets from our counterparties
using relevant credit market default rates, giving consideration to amounts
outstanding for each counterparty and the duration of each outstanding
derivative position. Based on our evaluation, we have determined that
the impact of the nonperformance of our counterparties on the fair value of our
derivative instruments is insignificant. As of December 31,
2008, no valuation allowance was recorded. Furthermore, while
we believe these valuation methods are appropriate and consistent with that used
by other market participants, the use of different methodologies, or
assumptions, to determine the fair value of certain financial instruments could
result in a different estimate of fair
value.
Valuation
hierarchy. SFAS No. 157 establishes a fair value hierarchy
that requires an entity to maximize the use of observable inputs and minimize
the use of unobservable inputs when measuring fair value. The
valuation hierarchy is based upon the transparency of inputs to the valuation of
an asset or liability as of the measurement date, giving the highest priority to
quoted prices in active markets (Level 1) and the lowest priority to
unobservable data (Level 3). In some cases, the inputs used to
measure fair value might fall in different levels of the fair value
hierarchy. The lowest level input that is significant to a fair value
measurement in its entirety determines the applicable level in the fair value
hierarchy. Assessing the significance of a particular input to the
fair value measurement in its entirety requires judgment, considering factors
specific to the asset or liability. The three levels of inputs that
may be used to measure fair value are defined as:
Level 1 – Quoted prices
(unadjusted) in active markets for identical assets or
liabilities. Instruments included in Level 1 consist of our commodity
derivatives for New York Mercantile Exchange (“NYMEX”)-based natural gas
swaps.
Level 2 – Inputs other than
quoted prices included within Level 1 that are either directly or indirectly
observable for the asset or liability, including (i) quoted prices for similar
assets or liabilities in active markets, (ii) quoted prices for identical or
similar assets or liabilities in inactive markets, (iii) inputs other than
quoted prices that are observable for the asset or liability and (iv) inputs
that are derived from observable market data by correlation or other
means.
Level 3 – Unobservable inputs
for the asset or liability, including situations where there is little, if any,
market activity for the asset or liability. Instruments included in
Level 3 consist of our commodity derivatives for Colorado Interstate Gas (“CIG”)
and Panhandle Eastern Pipeline (“PEPL”)-based natural gas swaps, oil swaps,
natural gas basis protection swaps, oil and natural gas options, and physical
sales and purchases.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The
following table presents, for each hierarchy level, our assets and liabilities,
including both current and non-current portions, measured at fair value on a
recurring basis as of December 31, 2008:
|
|
Level
1
|
|
|
Level
3
|
|
|
Total
|
|
|
|
(in
thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
Commodity
based derivatives
|
|
$ |
19,359 |
|
|
$ |
144,677 |
|
|
$ |
164,036 |
|
|
|
|
|
Liabilities:
|
|
|
|
Commodity
based derivatives
|
|
|
(658 |
) |
|
|
(9,828 |
) |
|
|
(10,486 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
fair value of commodity based derivatives
|
|
$ |
18,701 |
|
|
$ |
134,849 |
|
|
$ |
153,550 |
|
The
following table sets forth a reconciliation of our Level 3 fair value
measurements:
|
|
Year
Ended
December 31,
2008
|
|
|
|
(in
thousands)
|
|
|
|
|
|
Fair
value, net asset (liability), beginning of period
|
|
$ |
(2,368 |
) |
Unrealized
gains (losses) included in statement of operations line
item:
|
|
|
|
|
Cost
of natural gas marketing activities
|
|
|
(1,079 |
) |
Unrealized
gains (losses) included in balance sheet line item:
|
|
|
|
|
Accounts
receivable - affiliates
|
|
|
821 |
|
Accounts
payable - affiliates
|
|
|
35,338 |
|
Purchases
|
|
|
|
|
Oil
and gas sales activities
|
|
|
105,214 |
|
Sales
from natural gas marketing activities
|
|
|
438 |
|
Cost
of natural gas marketing activities
|
|
|
(4,590 |
) |
Settlements
|
|
|
|
|
Oil
and gas sales activities
|
|
|
549 |
|
Sales
from natural gas marketing activities
|
|
|
(129 |
) |
Cost
of natural gas marketing activities
|
|
|
655 |
|
Fair
value, net asset (liability), end of period
|
|
$ |
134,849 |
|
|
|
|
|
|
|
|
|
|
|
Change
in unrealized gains (losses) relating to assets (liabilities) still held
as of December 31, 2008, included in statement of operations line
item:
|
|
|
|
|
Oil
and gas price risk management, net
|
|
$ |
105,214 |
|
Sales
from natural gas marketing activities
|
|
|
438 |
|
Cost
of natural gas marketing activities
|
|
|
(5,669 |
) |
|
|
$ |
99,983 |
|
See Note 3, Derivative Financial
Instruments, for additional disclosure related to our derivative
financial instruments.
Non-Derivative Financial Assets and
Liabilities.
The
carrying values of the financial instruments comprising cash and cash
equivalents, restricted cash, accounts receivable and accounts payable
approximate fair value due to the short-term maturities of these
instruments.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The
portion of our long-term debt related to our credit facility, approximates fair
value due to the variable nature of its related interest rate. We
estimate the fair value of the portion of our long-term debt related to our
senior notes to be approximately $127 million or approximately 62.5% of par
value as of December 31, 2008. We determined this valuation based
upon measurements of trading activity and quotes provided by brokers and traders
participating in the trading of the securities.
NOTE
3 – DERIVATIVE FINANCIAL INSTRUMENTS
We
are exposed to the effect of market fluctuations in the prices of oil and
natural gas as they relate to our oil and natural gas sales and natural gas
marketing segments. Price risk represents the potential risk of loss
from adverse changes in the market price of oil and natural gas
commodities. We employ established policies and procedures to manage
the risks associated with these market fluctuations using commodity
derivatives. Our policy prohibits the use of oil and natural gas
derivative instruments for speculative purposes.
Concentration of
Credit Risk. A significant portion of our
liquidity is concentrated in derivative instruments that enable us to manage a
portion of our exposure to price volatility from producing oil and natural
gas. These arrangements expose us to credit risk from our
counterparties. These contracts consist of fixed price swaps, basis
swaps and collars. We primarily use two investment grade financial
institutions as our counterparties to our derivative contracts who are also
major lenders in our credit facility arrangement. We have evaluated
the credit risk of our derivative assets from our counterparties using relevant
credit market default rates, giving consideration to amounts outstanding for
each counterparty and the duration of each outstanding derivative
position. Based on our evaluation, we have determined that the impact
of the nonperformance of our counterparties on the fair value of our derivative
instruments is insignificant. As of December 31, 2008, no
valuation allowance was recorded.
As of
December 31, 2008, the following counterparties expose us to credit
risk.
|
|
Fair
Value of Derivatives
|
|
|
|
As
of December 31, 2008
|
|
Counterparty
Name
|
|
Assets
|
|
|
Liabilities
|
|
|
Net
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
JPMorgan
Chase Bank, N.A.
(1)
|
|
$ |
83,291 |
|
|
$ |
(322 |
) |
|
$ |
82,969 |
|
BNP Paribas
(1)
|
|
|
79,316 |
|
|
|
- |
|
|
|
79,316 |
|
Various
(2)
|
|
|
1,429 |
|
|
|
(10,164 |
) |
|
|
(8,735 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
164,036 |
|
|
$ |
(10,486 |
) |
|
$ |
153,550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Major lender in our credit facility, see Note 6.
|
|
(2)
Represents a total of 48 counterparties, includes two lenders in our
credit faciity.
|
|
Economic Hedging
Strategies. Our results of operations and operating cash flows
are affected by changes in market prices for oil and natural gas. To
mitigate a portion of the exposure to adverse market changes, we have entered
into various derivative contracts. As of December 31, 2008, our oil
and natural gas derivative instruments were comprised of futures, swaps, basis
protection swaps and collars. These instruments generally consist of
NYMEX-traded natural gas futures contracts and option contracts for Appalachian
and Michigan production, PEPL-based contracts for NECO production and CIG-based
contracts for other Colorado production and NYMEX-based crude oil swaps for our
Colorado oil production.
|
·
|
For
swap instruments, we receive a fixed price for the hedged commodity and
pay a floating market price to the counterparty. The
fixed-price payment and the floating-price payment are netted, resulting
in a net amount due to or from the
counterparty.
|
|
·
|
Basis
protection swaps are arrangements that guarantee a price differential for
natural gas from a specified delivery point. For CIG basis
protection swaps, which have negative differentials to NYMEX, we receive a
payment from the counterparty if the price differential is greater than
the stated terms of the contract and pay the counterparty if the price
differential is less than the stated terms of the
contract.
|
|
·
|
Collars
contain a fixed floor price (put) and ceiling price (call). If
the market price exceeds the call strike price or falls below the fixed
put strike price, we receive the fixed price and pay the market
price. If the market price is between the call and the put
strike price, no payments are due from either
party.
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We
purchase puts and set collars and swaps for our own and affiliated partnerships’
production to protect against price declines in future periods while retaining
much of the benefits of price increases. RNG enters into fixed-price
physical purchase and sale agreements that are derivative
contracts. In order to offset these fixed-price physical derivatives,
we enter into financial derivative instruments that have the effect of locking
in the prices we will receive or pay for the same volumes and period, offsetting
the physical derivative. While these derivatives are structured to
reduce our exposure to changes in price associated with the derivative
commodity, they also limit the benefit we might otherwise have received from
price changes in the physical market. We believe our derivative
instruments continue to be effective in achieving the risk management objectives
for which they were intended.
Validation
of a contract’s fair value is performed internally and while we use common
industry practices to develop our valuation techniques, changes in our pricing
methodologies or the underlying assumptions could result in significantly
different fair values. At December 31, 2008 and 2007, we had the
following open commodity based derivative instruments designed as an economic
hedge for a portion of our oil and natural gas production for periods after
December 2008:
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Derivative
net assets (liabilities)
|
|
|
|
|
|
|
Oil
and gas sales activities:
|
|
|
|
|
|
|
Fixed-price
natural gas swaps
|
|
$ |
55,747 |
|
|
$ |
- |
|
Natural
gas collars
|
|
|
50,752 |
|
|
|
2,969 |
|
Natural
gas basis protection swaps
|
|
|
(4,292 |
) |
|
|
- |
|
Natural
gas floors
|
|
|
- |
|
|
|
105 |
|
Fixed-price
oil swaps
|
|
|
51,508 |
|
|
|
(5,097 |
) |
|
|
|
153,715 |
|
|
|
(2,023 |
) |
Natural
gas marketing activities:
|
|
|
|
|
|
|
|
|
Fixed-price
natural gas swaps
|
|
|
(159 |
) |
|
|
649 |
|
Natural
gas basis protection swaps
|
|
|
(13 |
) |
|
|
- |
|
Natural
gas collars
|
|
|
7 |
|
|
|
- |
|
|
|
|
(165 |
) |
|
|
649 |
|
Estimated
net fair value of derivative instruments
|
|
$ |
153,550 |
|
|
$ |
(1,374 |
) |
In
addition to including the gross assets and liabilities related to our share of
oil and gas production, the above table and our consolidated balance sheets
include the gross assets and liabilities related to derivative contracts we
entered into and those that we allocate to our affiliated partnerships as the
managing general partner. See Note 11, Transactions with Affiliates,
for a discussion of our allocation methodology. For those derivative
contracts which we have allocated to the affiliated partnerships, we have on our
consolidated balance sheets a corresponding payable to and receivable from the
partnerships of $37.5 million and $1.6 million, respectively, as of December 31,
2008, and $1 million and $2.4 million as of December 31, 2007,
respectively.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The
following table identifies the fair value of commodity based derivatives as
classified in our consolidated balance sheets.
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Classification
in the Condensed Consolidated Balance Sheets:
|
|
|
|
|
|
|
Fair
value of derivatives - current asset
|
|
$ |
116,881 |
|
|
$ |
4,817 |
|
Other
assets - long-term asset
|
|
|
47,155 |
|
|
|
193 |
|
|
|
|
164,036 |
|
|
|
5,010 |
|
|
|
|
|
|
|
|
|
|
Fair
value of derivatives - current liability
|
|
|
4,766 |
|
|
|
6,291 |
|
Other
liabilities - long-term liability
|
|
|
5,720 |
|
|
|
93 |
|
|
|
|
10,486 |
|
|
|
6,384 |
|
Net
fair value of commodity based derivatives - asset
(liability)
|
|
$ |
153,550 |
|
|
$ |
(1,374 |
) |
The
following changes in the fair value of commodity based derivatives are reflected
in our consolidated statements of operations.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Statement
of operations line item
|
|
Realized
|
|
|
Unrealized
|
|
|
Realized
|
|
|
Unrealized
|
|
|
Realized
|
|
|
Unrealized
|
|
|
|
(in
thousands, gain/(loss))
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas price risk management gain (loss), net
(1)
|
|
$ |
9,487 |
|
|
$ |
118,351 |
|
|
$ |
7,173 |
|
|
$ |
(4,417 |
) |
|
$ |
1,895 |
|
|
$ |
7,252 |
|
Sales
from natural gas marketing activities
(2)
|
|
|
(1,882 |
) |
|
|
4,614 |
|
|
|
3,870 |
|
|
|
(1,736 |
) |
|
|
2,592 |
|
|
|
12,291 |
|
Cost
of natural gas marketing activities
(2)
|
|
|
32 |
|
|
|
(5,429 |
) |
|
|
(482 |
) |
|
|
1,511 |
|
|
|
(1,908 |
) |
|
|
(11,923 |
) |
__________
|
(1)
|
Includes
realized and unrealized gains and losses on commodity based derivative
instruments related to PDC.
|
|
(2)
|
Includes
realized and unrealized gains and losses on commodity based derivatives
instruments related to RNG only.
|
NOTE
4 – PROPERTIES AND EQUIPMENT
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Properties
and equipment, net:
|
|
|
|
|
|
|
Oil
and gas properties (successful efforts method of
accounting)
|
|
|
|
|
|
|
Proved
|
|
$ |
1,245,316 |
|
|
$ |
953,904 |
|
Unproved
|
|
|
32,768 |
|
|
|
41,023 |
|
Total
oil and gas properties
|
|
|
1,278,084 |
|
|
|
994,927 |
|
Pipelines
and related facilities
|
|
|
34,067 |
|
|
|
22,408 |
|
Transportation
and other equipment
|
|
|
31,693 |
|
|
|
23,669 |
|
Land
and buildings
|
|
|
14,570 |
|
|
|
11,303 |
|
Construction
in progress
(1)
|
|
|
275 |
|
|
|
2,929 |
|
|
|
|
1,358,689 |
|
|
|
1,055,236 |
|
Accumulated
DD&A
|
|
|
(325,611 |
) |
|
|
(209,372 |
) |
|
|
|
|
|
|
|
|
|
|
|
$ |
1,033,078 |
|
|
$ |
845,864 |
|
(1) At
December 31, 2007 includes costs primarily related to a new integrated oil and
gas financial software system.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Suspended
Well Costs
The
following table identifies the capitalized exploratory well costs that are
pending the determination of proved reserves and included in oil and gas
properties on the consolidated balance sheets.
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands, except for number of wells)
|
|
|
|
|
|
|
|
|
|
|
|
Beginning
balance at January 1
|
|
$ |
2,300 |
|
|
$ |
765 |
|
|
$ |
1,918 |
|
Additions
to capitalized exploratory well costs pending the determination of proved
reserves
|
|
|
15,644 |
|
|
|
3,953 |
|
|
|
12,016 |
|
Reclassifications
to wells, facilities and equipment based on the determination of proved
reserves
|
|
|
(10,259 |
) |
|
|
(878 |
) |
|
|
(13,169 |
) |
Capitalized
exploratory well costs charged to expense
|
|
|
(6,505 |
) |
|
|
(1,540 |
) |
|
|
- |
|
Ending
balance at December 31
|
|
$ |
1,180 |
|
|
$ |
2,300 |
|
|
$ |
765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of wells pending determination at December 31
|
|
|
6 |
|
|
|
3 |
|
|
|
1 |
|
As of
December 31, 2008, none of the wells awaiting the determination of proved
reserves have been capitalized for more than one year after the completion of
drilling.
NOTE
5 - INCOME TAXES
For each
of the years in the three-year period ended December 31, 2008, we utilized our
tax election to currently expense approximately $30 million, $44 million and $55
million, respectively, of intangible drilling costs (“IDC”). This
election substantially reduced our current tax expense but resulted in a
correspondingly higher deferred tax expense as shown
below. Additionally, in 2006, we had a substantial taxable gain from
the sale of undeveloped oil and gas properties, see Note 13, Sale of Oil and Gas
Properties. We have chosen to use the favorable deferral
aspects of the Internal Revenue Code (“IRC”) Section 1031 like-kind exchange
(“LKE”) rules to
defer the tax liability on a portion of the gain realized by purchasing
replacement properties, see Note 14, Acquisitions. Accordingly,
our current and deferred provision for income taxes increased proportionately in
2006 due to the current and deferred tax associated with this large taxable
gain. The components of our tax expense consisted of the
following:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
Current:
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
6,198 |
|
|
$ |
7,579 |
|
|
$ |
54,467 |
|
State
|
|
|
(3,818 |
) |
|
|
1,201 |
|
|
|
8,739 |
|
Total
current income taxes
|
|
|
2,380 |
|
|
|
8,780 |
|
|
|
63,206 |
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
55,500 |
|
|
|
11,074 |
|
|
|
74,003 |
|
State
|
|
|
3,579 |
|
|
|
1,127 |
|
|
|
12,428 |
|
Total
deferred income taxes
|
|
|
59,079 |
|
|
|
12,201 |
|
|
|
86,431 |
|
Total
income taxes
|
|
$ |
61,459 |
|
|
$ |
20,981 |
|
|
$ |
149,637 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Income
tax expense differed from the amounts computed by applying the U.S. federal
income tax rate of 35%.
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Computed
"expected" tax
|
|
$ |
61,169 |
|
|
$ |
18,966 |
|
|
$ |
135,594 |
|
State
income tax, net
|
|
|
5,265 |
|
|
|
1,907 |
|
|
|
13,744 |
|
Percentage
depletion
|
|
|
(1,150 |
) |
|
|
(624 |
) |
|
|
(545 |
) |
Domestic
production activities deduction
|
|
|
(249 |
) |
|
|
(374 |
) |
|
|
- |
|
Other
|
|
|
(3,576 |
) |
|
|
1,106 |
|
|
|
844 |
|
|
|
$ |
61,459 |
|
|
$ |
20,981 |
|
|
$ |
149,637 |
|
In order
to reduce current income taxes payable, we elected to expense, for income tax
purposes, a large amount of IDC in each of the three years presented
above. This expensing election reduces our domestic production
activities deduction, which in 2008 and 2007 was statutorily equal to six
percent of our qualified production activity income (“QPAI”), to $0.7 million
and $1.1 million, respectively. In 2006, due to our decision to
expense $55 million of IDC, our domestic production deduction, which in 2006 was
statutorily equal to three percent of QPAI, was zero. In addition,
the amount in “Other” for 2008 was primarily for discrete tax benefit realized
upon the implementation of state tax strategies during the second and third
quarters. The amount in “Other” for 2007 was primarily nondeductible
tax penalties.
The
federal examination of our 2005 and 2006 tax returns is currently ongoing with
no significant adjustments noted as of December 31, 2008.
The tax
effects of temporary differences that give rise to significant portions of the
deferred tax assets and deferred tax liabilities at December 31, 2008 and 2007,
are presented below.
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Deferred
tax assets:
|
|
|
|
|
|
|
Allowance
for doubtful accounts
|
|
$ |
205 |
|
|
$ |
138 |
|
Drilling
notes
|
|
|
27 |
|
|
|
31 |
|
Allowance
for lease impairment
|
|
|
4,910 |
|
|
|
912 |
|
Litigation
allowance
|
|
|
- |
|
|
|
578 |
|
Deferred
revenue related to cash withheld for future plugging
cost
|
|
|
1,043 |
|
|
|
1,011 |
|
Deferred
compensation
|
|
|
2,846 |
|
|
|
2,058 |
|
Asset
retirement obligations
|
|
|
8,519 |
|
|
|
7,782 |
|
Unrealized
loss - derivatives
|
|
|
- |
|
|
|
703 |
|
Employee
benefits
|
|
|
547 |
|
|
|
456 |
|
State
tax credit - carryforward
|
|
|
309 |
|
|
|
- |
|
Other
|
|
|
57 |
|
|
|
16 |
|
Total
gross deferred tax assets
|
|
|
18,463 |
|
|
|
13,685 |
|
Less
valuation allowance
|
|
|
- |
|
|
|
- |
|
Deferred
tax assets
|
|
|
18,463 |
|
|
|
13,685 |
|
|
|
|
|
|
|
|
|
|
Deferred
tax liabilities:
|
|
|
|
|
|
|
|
|
Properties
and equipment
|
|
|
(165,212 |
) |
|
|
(145,499 |
) |
Unrealized
gains - derivatives
|
|
|
(44,199 |
) |
|
|
(55 |
) |
Total
gross deferred tax liabilities
|
|
|
(209,411 |
) |
|
|
(145,554 |
) |
Net
deferred tax liability
|
|
$ |
(190,948 |
) |
|
$ |
(131,869 |
) |
|
|
|
|
|
|
|
|
|
Classification
in the Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
Net
current deferred tax (liabilities) assets*
|
|
$ |
(28,355 |
) |
|
$ |
4,621 |
|
Net
non-current deferred tax liability
|
|
|
(162,593 |
) |
|
|
(136,490 |
) |
Net
deferred tax liability
|
|
$ |
(190,948 |
) |
|
$ |
(131,869 |
) |
|
|
|
|
|
|
|
|
|
______________
*
Included in other current assets on the consolidated balance
sheets.
|
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As noted
above, deferred tax liabilities for properties and equipment increased in 2008
and 2007, primarily as a result of our election to expense $30 million and $44
million of IDC for income tax purposes.
In
assessing whether a valuation allowance for the deferred tax assets should be
recorded, we consider whether it is more likely than not that some portion or
all of the deferred tax assets will not be realized. The ultimate
realization of deferred tax assets is dependent upon the generation of future
taxable income during the periods in which those temporary differences become
deductible. Based upon the level of historical taxable income and
projections for future taxable income over the periods in which the deferred tax
assets are deductible, we believe it is more likely than not that we will
realize the benefits of these deductible differences. The amount of
the deferred tax asset considered realizable, however, could be reduced in the
near term if estimates of future taxable income during the carry-forward period
are reduced.
We
adopted the provisions of FIN No. 48 effective January 1, 2007. As a
result of adoption, retained earnings decreased by $0.3 million, deferred income
taxes payable decreased by $0.9 million, current income taxes payable increased
by $0.2 million and the liability for unrecognized tax benefit increased by $1
million.
The
following table sets forth a reconciliation of the total amounts of unrecognized
tax benefits for 2008:
|
|
(in
thousands)
|
|
|
|
|
|
Balance,
December 31, 2007
|
|
$ |
888 |
|
Gross
increases for tax positions of prior years
|
|
|
216 |
|
Gross
increases for tax positions of current year
|
|
|
167 |
|
Balance,
December 31, 2008
|
|
$ |
1,271 |
|
Interest
and penalties related to uncertain tax positions are recognized in income tax
expense. As of January 1, 2008, and December 31, 2008, we have
approximately $0.1 and $0.3 million of accrued interest related to uncertain tax
positions, respectively. In addition, at December 31, 2008, $0.3
million of income tax penalties were accrued compared to $0.2 million accrued at
January 1, 2008. The total amount of unrecognized tax benefits that
would affect the effective tax rate, if recognized, is $0.9 million as of
December 31, 2008 and $0.5 million as of January 1, 2008. We expect
the unrecognized tax benefit at December 31, 2008, to decrease in the next
twelve months because of the ongoing IRS examination of our 2005 and 2006 tax
years that will be finalized in 2009. It is currently estimated that
the decrease in our unrecognized tax benefits during the next year will be
approximately $0.8 million.
The
statute of limitations for tax years 2004-2007 remains open for both federal and
state taxing jurisdictions. However, due to the July 31,
2007, completion date of the federal examination of our 2003 and 2004 tax years,
we believe that certain tax positions related to these tax years have been
“effectively settled” for federal tax purposes. Additionally, for the
majority of our state tax jurisdictions, the statute of limitations for the 2003
tax year remains open at December 31, 2008.
Our
subsidiary, Unioil Inc., which was acquired on December 6, 2006, filed separate
tax returns for years prior to the acquisition date. Unioil’s
2003-2006 tax returns remain open to examination at December 31,
2008. Any unrecognized tax benefit associated with Unioil's tax
returns is included in the above table amount.
NOTE
6 - LONG-TERM DEBT
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
Credit
facility
|
|
$ |
194,500 |
|
|
$ |
235,000 |
|
12%
Senior notes due 2018, net of discount of $2.6 million
|
|
|
200,367 |
|
|
|
- |
|
Total
long-term debt
|
|
$ |
394,867 |
|
|
$ |
235,000 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Credit
facility
We have a
credit facility co-arranged by JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP
Paribas, as amended last on November 12, 2008, dated as of November 4, 2005,
with an available commitment of $375 million as of December 31,
2008. The credit facility, through a series of amendments, includes
commitments from: Wachovia Bank N.A.; Bank of America, N.A.; Bank of Oklahoma;
Allied Irish Banks p.l.c.; Guaranty Bank, FSB; Royal Bank of Canada; The Royal
Bank of Scotland, plc; Calyon New York Branch; Compass Bank; The Bank of Nova
Scotia; and BMO Capital Markets Financing, Inc. The maximum allowable
commitment under the current credit facility is $400 million. The
credit facility is subject to and secured by required levels of oil and natural
gas reserves. The credit facility requires an aggregated security of
a value no less than 80% of the value of the direct interests included in the
borrowing base properties. Our credit facility borrowing base is
subject to size redeterminations each April and October based upon a
quantification of our reserves at December 31st and
June 30th, respectively. A commodity price deck reflective of the
current and future commodity pricing environment, as agreed upon by us and our
lenders, is utilized to quantify our reserve reports and determine the
underlying borrowing base.
We are
required to pay a commitment fee of .5% per annum on the unused portion of the
activated credit facility. Interest accrues at an alternative base
rate ("ABR") or adjusted LIBOR at our discretion. The ABR is the
greater of JPMorgan's prime rate, an adjusted secondary market rate for a
three-month certificate of deposit plus 1% or the federal funds effective rate
plus .5%. ABR borrowings are assessed an additional margin spread up
to 1.375% and adjusted LIBOR borrowings are assessed an additional margin spread
of 1.625% to 2.375% based upon the outstanding balance as a percentage of the
available balance. The credit agreement requires, among other things,
the maintenance of certain working capital and tangible net worth
ratios. No principal payments are required until the credit agreement
expires on November 4, 2010.
The
credit facility contains covenants customary for agreements of this type,
including, but not limited to, limitations on our ability to: (a) incur
additional indebtedness and guarantees, (b) create liens and other encumbrances
on our assets, (c) consolidate, merge or sell assets, (d) pay dividends and
other distributions, (e) make certain investments, loans and advances, (f) enter
into sale/leaseback transactions, (g) enter into transactions with our
affiliates, (h) change the character of our business, (i) engage in hedging
activities unless certain requirements are satisfied, (j) issue certain types of
stock, and (k) make certain amendments to our organizational
documents. The credit facility also requires us to execute and
deliver specified mortgages and other evidences of security and to deliver
specified opinions of counsel and other evidences of title. In
addition, we are required to comply with certain financial tests and maintain
certain financial ratios. The financial tests and ratios include requirements
to: (a) maintain a minimum ratio of consolidated current assets to consolidated
current liabilities, or working capital ratio, and (b) not to exceed a maximum
leverage ratio.
As of
December 31, 2008, we had drawn $194.5 million from our credit facility compared
to $235 million as of December 31, 2007. The borrowing rate on the
outstanding balance was 4.6% as of December 31, 2008 compared to 7.1% as of
December 31, 2007. Amounts outstanding under our credit facility are
secured by substantially all of our properties. We were in compliance
with all covenants at December 31, 2008, and expect to remain in compliance
throughout 2009.
12%
Senior Notes Due 2018
Our
outstanding 12% senior notes were issued on February 8, 2008. The
principal amount of the senior notes is $203 million, which is payable at
maturity on February 15, 2018. Interest is payable in cash
semi-annually in arrears on each February 15 and August 15. The
senior notes were issued at a price of 98.572% of the principal
amount. In addition, $5.4 million in costs associated with the
issuance of the debt has been capitalized as a deferred loan
cost. The original discount and the deferred loan costs are being
amortized to interest expense over the term of the debt using the effective
interest method. As a result of recent negative global financial
market conditions, we estimate that the fair value of the senior notes was
approximately $127 million or approximately 62.5% of par. We
determined this valuation based upon measurements of trading activity and quotes
provided by brokers and traders participating in the trading of the
securities.
The
indenture governing the notes contains customary representations and warranties
as well as typical restrictive covenants that, among other things, limit our
ability and the ability of our restricted subsidiaries to: (a) incur additional
debt, (b) make certain investments or pay dividends or distributions on our
capital stock or purchase or redeem or retire capital stock, (c) sell assets,
including capital stock of our restricted subsidiaries, (d) pay dividends or
other payments by restricted subsidiaries, (e) create liens that secure debt,
(f) enter into transactions with affiliates, and (g) merge or consolidate with
another company. Additionally, we are subject to two incurrence
covenants: 1) earnings before interest, taxes, depreciation, amortization and
capital expenditures (“EBITDAX”) of at least two times interest expense and 2)
total debt of less than 4.0 times EBITDAX. As of December 31, 2008,
our EBITDAX was 8.3 times interest expense and total debt was 1.8 time
EBITDAX. We were in compliance with all covenants as of December 31,
2008, and expect to remain in compliance throughout 2009.
The notes
are senior unsecured obligations and rank, in right of payment, equally with all
of our existing and future senior unsecured indebtedness and senior to any of
our existing and future subordinated indebtedness. The notes are
effectively subordinated to any of our existing or future secured indebtedness
to the extent of the assets securing such indebtedness.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The notes
are not initially guaranteed by any of our subsidiaries. However,
subsidiaries may be obligated to guarantee the notes if:
• a
subsidiary is a guarantor under our senior credit facility; and
• the
subsidiary has consolidated tangible assets that constitute 10% or more of our
consolidated tangible assets.
Subject
to specified exceptions, any subsidiary guarantor will be restricted from
entering into certain transactions including the disposition of all or
substantially all of its assets or merging with or into another
entity. Subsidiary guarantors may be released from a guarantee under
circumstances specified in the indenture. As of December 31, 2008,
none of our subsidiaries were obligated as guarantors of our senior
notes.
The
indenture provides that at any time, which may be more than once, before
February 15, 2011, we may redeem up to 35% of the outstanding notes with
proceeds from one or more equity offerings at a redemption price of 112% of the
principal amount of the notes redeemed, plus accrued and unpaid interest, as
long as:
|
•
|
at
least 65% of the aggregate principal amount of the notes issued on
February 8, 2008, remains outstanding after each such redemption;
and
|
•
the redemption occurs within 180 days after the closing of the equity
offering.
The notes
also provide that we may, at our option, redeem all or part of the notes, at any
time prior to February 15, 2013, at the make-whole price set forth in the
indenture, and on or after February 15, 2013, at fixed redemption prices, plus
accrued and unpaid interest, if any, to the date of
redemption. Further, the indenture provides that upon a change of
control, we must give holders of the notes the opportunity to put their notes to
us for repurchase at a repurchase price of 101% of the principal amount, plus
accrued and unpaid interest.
In
connection with the issuance of the notes, we entered into a registration rights
agreement with the initial purchasers in which we agreed to file a registration
statement with the SEC related to an offer to exchange the notes for other
freely tradable notes and to use commercially reasonable efforts to cause the
registration statement to become effective on or prior to February 7,
2009. On April 24, 2008, we filed the related registration statement
on Form S-4. The registration statement was declared effective May
23, 2008.
NOTE
7 - ASSET RETIREMENT OBLIGATIONS
Changes
in carrying amounts of the asset retirement obligations associated with our
working interest in oil and gas properties are as follows:
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
Balance
at beginning of year
|
|
$ |
20,781 |
|
|
$ |
11,966 |
|
Obligations
assumed with development activities and acquisitions
|
|
|
1,189 |
|
|
|
7,909 |
|
Obligations
discharged with disposed properties and asset retirements
|
|
|
(114 |
) |
|
|
(93 |
) |
Accretion
expense
|
|
|
1,230 |
|
|
|
999 |
|
Balance
at end of year
|
|
$ |
23,086 |
|
|
$ |
20,781 |
|
If the
fair value of the estimated asset retirement obligation changes, an adjustment
is recorded to both the asset retirement obligation and the asset retirement
cost. Approximately $0.1 million of the asset retirement obligations
were classified as short-term and included in other accrued expenses as of
December 31, 2008 and 2007.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE
8 - COMMITMENTS AND CONTINGENCIES
Drilling and Development
Agreements. We are a party to a pipeline expansion agreement
with an unrelated third party, which is also currently the purchaser of the
majority of our Wattenberg Field natural gas production. Pursuant to
the agreement, we have agreed to invest a minimum of $65 million to develop
specified acreage in the Wattenberg Field, during a three-year period ending
December 31, 2009. Such capital spending will include costs to drill
new wells and the cost to recomplete existing wells in this
area. Should we not meet the minimum commitment by December 31, 2009,
we will be required to pay liquidated damages of $2 million, prorated based on
our actual capital investment made to date. As of December 31, 2008,
our total capital expenditures pursuant to the agreement were $61.3 million,
resulting in a maximum potential liquidating damages charge of $0.1
million.
In
connection with the acquisition of oil and gas properties in October 2007 from
an unaffiliated party, we are obligated to drill 100 wells in the Appalachian
Basin by January 2016. We will retain a majority interest in each
well drilled. For each well we fail to drill, we are obligated to pay
to the seller liquidated damages of $25,000 per undrilled well for a total
contingent obligation of $2.5 million or reassign to the seller the interest
acquired in the number of undrilled well locations. As of December
31, 2008, we have drilled 28 wells pursuant to this agreement.
We have
entered into contracts that provide firm transportation, sales and processing
charges on pipeline systems which we transport or sale our natural gas and the
natural gas of other companies, working interest owners and our affiliated
partnerships. The remaining terms of the contracts range from two to
14 years and require us to pay these transportation and processing charges
regardless if the required volumes are delivered or not. The table
below represents our gross future minimum firm transportation, sales and
processing charges as of December 31, 2008, for the periods
indicated. We will record in our financial statements only our share
based upon our working and net revenue interest in the wells.
Year
|
|
(in
thousands)
|
|
2009
|
|
$ |
8,391 |
|
2010
|
|
|
19,047 |
|
2011
|
|
|
18,443 |
|
2012
|
|
|
25,071 |
|
2013
|
|
|
25,262 |
|
Thereafter
|
|
|
121,281 |
|
|
|
$ |
217,495
|
|
In
September 2008, we entered into a pipeline and processing plants expansion
agreement with an unrelated party, which is currently the purchaser of the
majority of our Wattenberg Field natural gas production. Pursuant to
the agreement, we have agreed to make a capital investment of $60 million, for
our own benefit, over a three-year period commencing on January 1, 2009, to
develop or facilitate production in our Wattenberg Field dedicated to this
purchaser. If the purchaser fails to complete the pipeline and
processing plants in accordance with the agreement, then the agreement
effectively terminates. The agreement also provides for certain
volume commitments to be obtained by December 31, 2012. Qualifying
capital expenditures include the cost to drill new wells and the cost to
recomplete existing wells in this area. Failure to meet our drilling
commitment would result in a maximum payment to the counterparty of $15 million
in 2012; failure to meet our volume delivery commitment by December 31, 2012,
would result in a maximum payment to the counterparty of $10 million in
2013.
Partnership Repurchase
Provision. Substantially all of our drilling programs contain
a repurchase provision where investing partners may request that we purchase
their partnership units at any time beginning with the third anniversary of the
first cash distribution. The provision provides that we are obligated
to purchase an aggregate of 10% of the initial subscriptions per calendar year
(at a minimum price of four times the most recent 12 months' cash
distributions), if repurchase is requested by investors, and subject to our
financial ability to do so. The maximum annual repurchase obligation
as of December 31, 2008, was approximately $15.9 million. We have
adequate liquidity to meet this obligation. During 2008 and 2007, we
paid $1.8 million and $1.6 million, respectively, under this provision for the
repurchase of partnership units. As of December 31, 2008, outstanding
repurchase offers to investing partners totaled $0.7 million, of which $0.2
million were consummated in 2009 prior to expiration.
Performance
Supplements. Our drilling programs formed from 1996 through
the second quarter of 2005 contain a performance supplement that provides for
changes in the distribution of partnership profits if certain levels of
performance are not met. The terms of this provision in the
partnership agreements are not a guarantee of a rate of return on an investment
in the partnership. Under those specific conditions, such changes can
result in our share of an affected partnership’s profits being reduced by up to
one half of the amount to which we otherwise would be entitled in the affected
period. In no event would we be obligated to assume a
disproportionate share of losses in such partnerships; should the partnerships
that contain this provision in the partnership agreements incur a loss, our
share of such losses would be unaffected by the terms of this
provision. In accordance with these provisions, our share of
partnership profits was reduced by an aggregate of $1 million, $0.6 million, and
$1 million during 2008, 2007and 2006, respectively. As of December
31, 2008 and 2007, based on production through December 31 of the corresponding
year, we had accrued $0.3 million and $0.2 million, respectively.
Partnership Casualty
Losses. As Managing General Partner of 33 partnerships, we
have liability for any potential casualty losses in excess of the partnership
assets and insurance. We believe the casualty insurance coverage that
we and our subcontractors carry is adequate to meet this potential
liability.
Drilling Rig
Contracts. In order to secure the services for drilling rigs,
we made commitments to the drilling contractors, which call for a minimum
commitment of $12,500 daily for a specified amount of time if we cease to use
the drilling rigs and a maximum commitment of $40,680 daily for a specified
amount of time for daily use of the drilling rigs. As of December 31,
2008, commitments for these two separate contracts expire in August 2009 and
July 2010. As of December 31, 2008, we have an outstanding minimum
commitment for $4.2 million and an outstanding maximum commitment for $15.9
million, which includes $5.1 million related to a rig sublet to a third party
and remains our obligation should the third party default on terms of the sublet
agreement.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Litigation.
Colorado
royalty. On May 29, 2007, Glen Droegemueller, individually and
as representative plaintiff on behalf of all others similarly situated, filed a
class action complaint against the Company in the District Court, Weld County,
Colorado alleging that we underpaid royalties on natural gas produced from wells
operated by us in parts of the State of Colorado (the “Droegemueller
Action”). The plaintiff sought declaratory relief and to recover an
unspecified amount of compensation for underpayment of royalties paid by us
pursuant to leases. We removed the case to Federal Court on June 28,
2007. On October 10, 2008, the court preliminarily approved a
settlement agreement between the plaintiffs and the Company, on behalf of itself
and the partnerships for which the Company is the managing general
partner. Based on the settlement terms, the settlement amount payable
by the Company is $5.8 million. Such moneys, in addition to moneys
related to the settlement on behalf of the partnerships for which the Company is
the managing general partner, were deposited in an escrow account on November 3,
2008. We have accrued as of December 31, 2008, and included in other
accrued expenses in our consolidated balance sheets, a related $5.8 million
litigation reserve. We believe that the amount accrued is adequate to
satisfy this obligation. Notice of the settlement was mailed to
members of the class action suit in the fourth quarter of 2008. The
final settlement approval hearing is expected on April 7, 2009.
See Note 17, Subsequent Events, regarding
two West Virginia royalty lawsuits filed in January 2009.
Colorado Stormwater
Permit. On December 8, 2008, we received a Notice of Violation
/Cease and Desist Order (the “Notice”) from the Colorado Department of Public
Health, related to the stormwater permit for the Garden Gulch
Road. The Company manages this private road for Garden Gulch
LLC. The Company is one of four equal owners of Garden Gulch LLC, all
of which are oil and gas companies operating in the Piceance region of
Colorado. The Notice alleges a deficient and/or incomplete stormwater
management plan, failure to implement best management practices and failure to
conduct required permit inspections. The Notice requires corrective
action and states that the recipient shall cease and desist such alleged
violations. The Notice states that a violation could result in civil
penalties up to $10,000 per day. The Company’s initial response was
submitted on February 6, 2009. No civil penalties have been imposed
or requested at this time. Given the preliminary stage of this
proceeding and the inherent uncertainty in litigation, the Company is unable to
predict the ultimate outcome of this suit at this time.
We are
involved in various other legal proceedings that we consider normal to our
business. Although the results cannot be known with certainty, we
believe that the ultimate results of such proceedings will not have a material
adverse effect on our financial position or results of operations.
Employment Agreements with Executive
Officers. We have employment agreements with our Chief
Executive Officer, Chief Financial Officer, Chief Accounting Officer and other
executive officers. The employment agreements provide for annual base
salaries, eligibility for performance bonus compensation, and other various
benefits, including retirement and termination benefits.
In the
event of termination without cause or if an executive officer terminates
employment for good reason, which includes a change in control, the executive
officer is entitled to receive a payment in the amount up to three times the sum
of his highest base salary during the previous two years of employment
immediately preceding the termination date and his highest bonus received during
the same two year period. The executive officer is also entitled to
(i) vesting of any unvested equity compensation, (ii) reimbursement for any
unpaid expenses, (iii) retirement benefits earned under the current and/or
previous agreements, (iv) continued coverage under our medical plan for up to 18
months, and (v) payment of any earned and unpaid bonus amounts. In
addition, the executive officer is entitled to receive any benefits that he
would have otherwise been entitled to receive under our 401(k) and profit
sharing plan, although those benefits are not increased or
accelerated.
In the
event that an executive officer is terminated for just cause, we are required to
pay the executive officer his base salary through the termination date plus any
bonus (only for periods completed and accrued, but not paid), incentive,
deferred, retirement or other compensation, and to provide any other benefits,
which have been earned or become payable as of the termination date but which
have not yet been paid or provided.
In the
event that an executive officer voluntarily terminates his employment for other
than good reason, he is entitled to receive (i) his base salary, bonus and
incremental retirement payment prorated for the portion of the year that the
executive officer is employed, (ii) any incentive, deferred or other
compensation which has been earned or has become payable, but which has not yet
been paid under the schedule originally contemplated in the agreement under
which they were granted or in full without discount within 60 days of the
termination date at our discretion, (iii) any unpaid expense reimbursement upon
presentation by the executive officer of an accounting of such expenses in
accordance with our normal practices, and (iv) any other payments for benefits
earned under the employment agreement or our plans.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In the
event of death or disability, the executive is entitled to receive (i) his base
salary and bonus for the portion of the year the executive officer is employed;
(ii) the base salary that would have been earned for six months after
termination; (iii) immediate vesting of all equity and option awards; (iv) the
payment of deferred retirement compensation based upon the schedule originally
contemplated in the deferred retirement compensation agreement or in a lump-sum
no later than two and one-half months following the close of the calendar year
in which the death or disability occurred; (v) reimbursement for any unpaid
expenses; (vi) and benefits earned under the 401(k) and profit sharing plan; and
(vii) continued coverage under our medical plan for up to 18
months.
Derivative
Contracts. We would be exposed to oil and natural gas price
fluctuations on underlying purchase and sale contracts should the counterparties
to our derivative instruments or the counterparties to our gas marketing
contracts not perform. Nonperformance is not
anticipated. There were no counterparty default losses in 2008, 2007
or 2006.
NOTE
9 - COMMON STOCK
Stock-Based
Compensation Plans
As
approved by the shareholders in June 2004, we maintain a long-term equity
compensation plan for our officers and certain key employees (the “2004
Plan”). In accordance with the plan, awards may be issued in the form
of stock options, stock appreciation rights, restricted stock or performance
shares. A total of 750,000 new shares of common stock have been
reserved for issuance. Awards pursuant to the plan vest over periods
set at the discretion of the Compensation Committee of our Board of Directors
(“Board”) and have a maximum exercisable period of ten years. As of
December 31, 2008, 312,418 common shares remain available for future
awards.
As
approved by the shareholders, we also maintain a restricted stock plan for
non-employee directors. A total of 100,000 new shares of common stock
have been reserved for issuance under the plan. During 2008, 2007 and
2006, 14,000, 12,710 and 6,551 common shares, respectively, were awarded in
accordance with the plan. Compensation expense for each of the years
ended December 31, 2008, 2007 and 2006, related to these restricted shares was
$1 million, $0.2 million and $0.1 million, respectively. As of
December 31, 2008, 59,844 common shares remain available for future
awards.
In August
1999, the shareholders approved the 1999 Incentive Stock Option and
Non-Qualified Stock Option Plan. A total of 500,000 shares of our
common stock were reserved for issuance upon the exercise of stock
options. All shares authorized to be awarded pursuant to this plan
were awarded in years prior to 2002. As of December 31, 2007, options
for 11,000 common shares remained outstanding and exercisable; in 2008,
these outstanding options were exercised.
The
following table provides a summary of the effect of our stock based compensation
plans on the results of operations for the periods presented.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Total
stock-based compensation expense (1)
|
|
$ |
6,702 |
|
|
$ |
2,286 |
|
|
$ |
1,516 |
|
Income
tax benefit
|
|
|
(2,557 |
) |
|
|
(882 |
) |
|
|
(585 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income impact
|
|
$ |
4,145 |
|
|
$ |
1,404 |
|
|
$ |
931 |
|
______________
(1) 2008
includes $1.1 million related to a separation agreement with our former
president and $1.5 million related to a retirement agreement with our former
chief executive officer.
Stock Option
Awards. As of December 31, 2008, all outstanding stock options
were issued pursuant to our 2004 Plan. Outstanding options expire ten
years from the date of grant and become vested and exercisable ratably over a
four year period. We have not granted any new stock option awards
since 2006. In 2008, pursuant to a separation agreement with our
former president and an agreement with our former chief executive officer, we
modified options to purchase 9,905 shares by accelerating the vesting schedule,
none of which would have vested pursuant to the original terms of the
award. The incremental change in fair value per share of the modified
awards was immaterial. The fair value of options modified in 2008 and
granted in 2006, were estimated at the date of modification or grant using a
Black-Scholes option-pricing model assuming no dividends and the following
weighted average assumptions, with the exception of 4,678 shares in 2008, which
were estimated to approximate fair value on the date of modification due to the
short-term nature of the award:
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2006
|
|
|
|
|
|
|
|
|
Expected
volatility
|
|
|
43.0%
|
|
|
|
40.4%
|
|
Expected
term (in years)
|
|
|
-
|
|
|
|
6.0
|
|
Risk-free
interest rate
|
|
|
1.6%
|
|
|
|
4.2%
|
|
|
|
|
|
|
|
|
|
|
Weighted-average
grant date fair value per share
|
|
$ |
18.03
|
|
|
$ |
20.30
|
|
Expected
volatilities are based on our historical volatility. The expected
life of an award is estimated using historical exercise behavior
data. The risk-free interest rate is based on the U.S. Treasury
yields in effect at the time of grant and extrapolated to approximate the
expected life of the award. We do not expect to pay dividends, nor do
we expect to declare dividends in the foreseeable future.
The
following table provides a summary of our stock option award activity for the
year ended December 31, 2008:
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Weighted
|
|
|
Average
|
|
|
|
Number
of
|
|
|
Average
|
|
|
Remaining
|
|
|
|
Shares
|
|
|
Exercise
|
|
|
Contractual
|
|
|
|
Underlying
|
|
|
Price
|
|
|
Term
|
|
|
|
Options
|
|
|
Per
Share
|
|
|
(years)
|
|
Outstanding
at December 31, 2007
|
|
|
51,567 |
|
|
$ |
33.55 |
|
|
|
6.4 |
|
Modified
|
|
|
9,905 |
|
|
|
43.03 |
|
|
|
|
|
Exercised
|
|
|
(25,699 |
) |
|
|
24.41 |
|
|
|
|
|
Forfeited
|
|
|
(17,422 |
) |
|
|
43.86 |
|
|
|
|
|
Outstanding
at December 31, 2008
|
|
|
18,351 |
|
|
|
41.68 |
|
|
|
6.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested
and expected to vest at December 31, 2008
|
|
|
18,351 |
|
|
|
41.68 |
|
|
|
6.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable
at December 31, 2008
|
|
|
12,736 |
|
|
|
40.41 |
|
|
|
6.6 |
|
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands, except market price)
|
|
Total
intrinsic value of options exercised
|
|
$ |
659 |
|
|
$ |
1,691 |
|
|
$ |
281 |
|
Total
intrinsic value of options outstanding
|
|
|
- |
|
|
|
1,319 |
|
|
|
1,984 |
|
Total
intrinsic value of options exercisable
|
|
|
- |
|
|
|
971 |
|
|
|
1,934 |
|
Market
price per common share as of December 31
|
|
|
24.07 |
|
|
|
59.13 |
|
|
|
43.05 |
|
The
intrinsic value of options exercised represents the amount by which the market
value of our stock at date of exercise exceeds the exercise price of the
option. The intrinsic values of the options outstanding and
exercisable represent the amount by which the closing market price of our common
stock at the last trading day of the year exceeds the exercise price of the
options. Total compensation cost related to stock options
granted under the 2004 Plan not yet recognized as of December 31, 2008, was $0.1
million. This cost is expected to be recognized over a weighted
average period of 1.5 years.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Restricted
Stock Awards
We have
issued restricted stock awards with vesting conditions that are either
time-based or market-based.
Time-Based
Awards. The fair value
of the time-based awards is amortized ratably over the requisite service period,
primarily over four years. Time-based awards for non-employee directors vest on
July 1 of the year following the date of grant. Total intrinsic value
is based upon the closing market price of our common stock on the last trading
date of the year. In 2008, pursuant to a separation agreement with
our former president and an agreement with our former chief executive officer,
we modified time-based awards to vest 25,027 shares by accelerating the vesting
schedule, none of which would have vested pursuant to the original terms of the
award, resulting in an increase in the original fair value of $0.4
million.
The
following table sets forth the changes in non-vested time-based awards for the
year ended December 31, 2008:
|
|
|
|
|
Weighted
Average
|
|
|
|
|
|
|
Grant-Date
|
|
|
|
Shares
|
|
|
Fair
Value
|
|
Non-vested
at December 31, 2007
|
|
|
201,845 |
|
|
$ |
37.97 |
|
Granted/modified
|
|
|
161,982 |
|
|
|
57.64 |
|
Vested
|
|
|
(110,562 |
) |
|
|
34.59 |
|
Forfeited
|
|
|
(35,205 |
) |
|
|
45.53 |
|
Non-vested
at December 31, 2008
|
|
|
218,060 |
|
|
$ |
52.59 |
|
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands, except market price)
|
|
Total
intrinsic value of time-based awards vested
|
|
$ |
6,710 |
|
|
$ |
2,208 |
|
|
$ |
844 |
|
Total
intrinsic value of time-based awards non-vested
|
|
|
5,249 |
|
|
|
10,161 |
|
|
|
5,671 |
|
Market
price per common share as of December 31
|
|
|
24.07 |
|
|
|
59.13 |
|
|
|
43.05 |
|
Total
intrinsic value of time-based awards vested is based on the closing market price
of our common stock on the date of vest. Total intrinsic value of
time-based awards not yet vested is based on the closing market price of our
common stock on the last trading day of the year. The total
compensation cost related to non-vested time-based awards not yet recognized as
of December 31, 2008, was $8.8 million. This cost is expected to be
recognized over a weighted-average period of 2.9 years.
Market-Based
Awards. The fair value of the market-based awards is amortized
ratably over the requisite service period, primarily over three years for
market-based awards. The market-based shares vest only upon the
achievement of certain per share price thresholds and continuous employment
during the vesting period. All compensation cost related to the
market based-awards will be recognized if the requisite service period is
fulfilled, even if the market condition is not achieved. In 2008,
pursuant to a separation agreement with our former president, we modified
market-based awards to vest 1,539 shares by accelerating the vesting schedule,
none of which would have vested pursuant to the original terms of the award;
pursuant to an agreement with our former chief executive officer, we modified
market-based awards to vest 37,440 shares by accelerating the vesting
schedule, none of which would have vested, nor was expected to vest, pursuant to
the original terms of the award. The incremental change in fair value
per share of the modified awards was immaterial.
The
weighted average grant date fair value per market-based share, including shares
modified pursuant to an agreement with our former chief executive officer, was
computed using the Monte Carlo pricing model using the following weighted
average assumptions:
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
Expected
term of award
|
|
3
years
|
|
|
3
years
|
|
Risk-free
interest rate
|
|
|
2.7%
|
|
|
|
4.7%
|
|
Volatility
|
|
|
45.6%
|
|
|
|
44.0%
|
|
Weighted
average grant date fair value per share
|
|
$ |
43.61
|
|
|
$ |
36.07
|
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The
following table sets forth the changes in non-vested market-based awards for the
year ended December 31, 2008:
|
|
|
|
|
Weighted
Average
|
|
|
|
|
|
|
Grant-Date
|
|
|
|
Shares
|
|
|
Fair
Value
|
|
Non-vested
at December 31, 2007
|
|
|
31,972 |
|
|
$ |
36.07 |
|
Granted/modified
|
|
|
87,384 |
|
|
|
43.61 |
|
Vested
|
|
|
(3,078 |
) |
|
|
52.00 |
|
Forfeited
|
|
|
(43,595 |
) |
|
|
40.81 |
|
Non-vested
at December 31, 2008
|
|
|
72,683 |
|
|
$ |
41.62 |
|
The
intrinsic value of market-based awards not yet vested at December 31, 2008 and
2007, was $1.7 million and $1.9 million, respectively, based upon the closing
market price of our common stock on the last trading date of the year. The total
compensation cost related to non-vested market-based awards not yet recognized
as of December 31, 2008, is $1.4 million. This cost is expected to be
recognized over a weighted-average period of 1.1 years.
Treasury
Share Purchases
In
January 2006, we announced that our Board authorized the purchase of up to 10%
(1,627,500 shares) of our common stock during 2006. Stock purchases
under this program were made in the open market or in private transactions, at
times and in amounts that we deemed appropriate. In October 2006, we
completed our January 2006 program. Total shares purchased pursuant
to the program were 1,627,500 common shares at a cost of $66.3 million ($40.75
average price paid per share), including 100,000 shares from one of our
executive officers at a cost of $4.1 million ($40.66 price paid per
share). All shares purchased in accordance with the program have
subsequently been retired.
On
October 16, 2006, our board of directors of approved a second 2006 purchase
program authorizing us to purchase up to 10% (1,477,109 shares) of our then
outstanding common stock through April 2008. Stock purchases under
this program were made in the open market or in private transactions, at times
and in amounts that we deem appropriate. There were 1,465,089 shares
that were authorized but not yet purchased as of December 31,
2007. Total shares purchased in 2008 pursuant to the program were
64,263 common shares at a cost of $4.4 million ($67.97 average price paid per
share), including 63,756 shares from our executive officers at a cost of $4.3
million ($67.98 price paid per share). Shares purchased in 2008
from employees, excluding executive officers, were generally purchased at fair
market value based on the closing price on the date of purchase and were
primarily purchased to satisfy the statutory minimum tax withholding requirement
for restricted stock that vested in 2008. Shares purchased from
executive officers in 2008 were primarily pursuant to a separation agreement
with our former president and to satisfy the statutory minimum tax withholding
requirements for shares vested in 2008. Shares purchased in prior
years were generally purchased at fair market value based on the closing price
on the date of purchase and were primarily purchased to satisfy the statutory
minimum tax withholding requirement for shares vesting in prior
years. The authorization to purchase the remaining 1,400,826 shares
effectively expired on April 30, 2008. All shares purchased in
accordance with the program have been subsequently retired.
Pursuant
to our senior notes indenture entered on February 8, 2008, any future purchases
are limited, see Note 6, Long-Term Debt.
Shareholders’ Rights
Agreement
On
September 11, 2007, we entered into a rights agreement, with Transfer Online,
Inc., as rights agent. The rights agreement is designed to improve
the ability of our board of directors to protect the interest of our
shareholders in the event of an unsolicited takeover attempt. Our
Board declared a dividend of one right for each outstanding share of our common
stock. The right dividend was paid to shareholders of record on
September 14, 2007. A “distribution date,” as defined in the rights
agreement, can occur after any individual shareholder exceeds 15% ownership of
our outstanding common stock. After the occurrence of a “distribution
date,” the right entitles each registered holder (other than the acquiring
shareholder who triggered the “distribution date”), to purchase shares of our
common stock (or, in certain circumstances, cash, property or other securities)
having a then-current value equal to two times the exercise price of the right
(i.e., for the $240 exercise price, the rights holder receives $480 worth of
common stock). The exercise price is subject to adjustment for
various corporate actions which affect all shareholders, such as a stock
split. The rights agreement and all rights will expire on September
11, 2017.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Common
and Preferred stock
Effective
July 17, 2008, pursuant to shareholder approval, we amended and restated our
Articles of Incorporation to: (1) increase the number of the Company's
authorized shares of common stock, par value $0.01, from 50,000,000 shares to
100,000,000 shares, and (2) authorize 50,000,000 shares of Company preferred
stock, par value $0.01, which may be issued in one or more series, with such
rights, preferences, privileges and restrictions as shall be fixed by our Board
of Directors from time to time. As of December 31, 2008, no preferred
stock had been issued.
NOTE
10 - EMPLOYEE BENEFIT PLANS
We
sponsor a qualified retirement plan covering substantially all of our
employees. The plan consists of a 401(k) component and a profit
sharing component. The 401(k) component enables eligible employees to
contribute a portion of their compensation through pre-tax payroll deductions in
accordance with specific guidelines. We provide a discretionary
matching contribution based on a percentage of the employees' contributions up
to certain limits. Our contribution to the profit sharing component
is discretionary. Our total combined expense for both 401(k) and
profit sharing in 2008, 2007 and 2006, was $1.9 million, $1.4 million and $3.1
million, respectively.
We
provide a supplemental retirement benefit of deferred compensation under terms
of the various employment agreements with certain executive
officers. During 2008, 2007 and 2006, we charged $0.2 million, $0.4
million and $0.3 million related to this plan to general and administrative
expenses, respectively, and we have recorded a related liability in the amount
$2.4 million and $2.2 million as of December 31, 2008 and 2007,
respectively.
In
addition to the supplemental retirement benefit of deferred compensation, we
offer a supplemental healthcare benefit covering certain executive officers and
their spouses in accordance with each officer's employment
agreement. Expense incurred during 2008 and 2007 related to this plan
was immaterial. As of December 31, 2008 and 2007, we had a recorded
liability of $0.6 million.
We
maintain a non-qualified deferred compensation plan for our non-employee
directors. The amount of compensation deferred by each participant is
based on participant elections. The amounts deferred pursuant to the
plan are invested in our common stock, maintained in a rabbi trust and are
classified in the balance sheet as treasury shares as a component of
shareholders' equity. The plan may be settled in either cash or
shares as requested by the participant. As of December 31, 2008 and
2007, we had recorded a long-term liability of $0.2 million and $0.3 million,
respectively, which is included in other liabilities in our consolidated balance
sheets.
NOTE
11 - TRANSACTIONS WITH AFFILIATES
Funds
held for future distribution on our consolidated balance sheets represent
amounts owed to affiliated partnerships and others for production proceeds
received by us on their behalf and undistributed as of December 31, 2008 and
2007.
Amounts
due from/to the affiliated partnership are primarily related to derivative
positions, unbilled well lease operating expenses, and costs resulting from
audit and tax preparation services.
We enter
into derivative instruments for our own production as well as for our 33
affiliated partnerships’ production. We enter into these derivative
instruments for us and, as the managing general partner, for the affiliated
partnerships jointly by area of operation. Prior to September 30,
2008, as volumes produced changed, the allocation between us and the affiliated
partnerships changed. As of September 30, 2008, we fixed the
allocation of the derivative positions between us and each affiliated
partnership. Fixed quantities of each of the then existing positions
were allocated to us and the affiliated partnerships based upon current
estimated future production. For positions entered into subsequent to
September 30, 2008, specific designations of the quantities between us and the
affiliated partnerships are made at the time the positions are entered into
based on estimated future production. As of December 31, 2008, we
have recorded a payable to affiliates of $37.5 million representing their
allocated portion of the fair value of our gross derivative assets and a due
from affiliates of $1.6 million representing their allocated portion of the fair
value of our gross derivative liabilities.
Our
natural gas marketing segment manages the marketing of oil and natural gas for
our affiliated partnerships in the Appalachian Basin. Our sales from
natural gas marketing activities include $12.4 million, $9.3 million and $17.6
million in 2008, 2007 and 2006, respectively, related to the marketing of oil
and natural gas on behalf of our affiliated partnerships. Included in
our cost of natural gas marketing activities is $12.1 million, $9.1 million and
$17.3 million for 2008, 2007 and 2006, respectively, related to these sales.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We
provided oil and gas well drilling services to our affiliated
partnerships. Pursuant to our cost-plus drilling arrangements and our
corresponding net presentation, we performed drilling services for our
affiliated partnerships totaling $68 million, $68.4 million and $87 million in
2008, 2007 and 2006, for which we recognized $7.6 million, $11.4 million and
$12.4 million in oil and gas well drilling operations revenue,
respectively. As part of the oil and gas well drilling services we
provide to our affiliated partnerships, we sell to them at cost the oil and gas
leases upon which the wells are drilled. For the years ended December
31, 2008, 2007 and 2006, we sold to our affiliated partnerships leases in the
amounts of $0.5 million, $1.4 million and $1.8 million,
respectively. Further, we provide well operations and pipeline
services to our affiliated partnerships. Substantially all of our
revenue and expenses related to oil and gas well drilling operations and
revenues from well operations and pipeline income are associated with services
provided to our affiliated partnerships.
Revenues
from oil and gas well drilling operations and costs of oil and gas well drilling
operations each include $0.1 million during 2006 related to investments made by
executive officers for working interests in wells drilled during in
2006. Amounts invested by the executive officers during 2007 were
immaterial. No amounts were invested by the executive officers during
2008.
Management
fees collected from the affiliated partnerships were $1.3 million in each of the
years 2007 and 2006. Management fees are included in other income on
our consolidated statements of operations. In 2008, we did not offer
a drilling partnership; therefore, no management fee was collected from an
affiliated partnership in 2008.
Through
our wholly-owned subsidiary, PDC Securities Incorporated, we act as
Dealer-Manager of the drilling partnerships. PDC Securities receives
the applicable commissions and marketing allowances from the Escrow Agent of the
drilling program and distributes them to the soliciting broker/dealers who sell
the programs. The commissions and marketing allowances received by
PDC Securities are included in other income net of the commissions distributed
to the soliciting broker/dealer. The commissions and marketing
allowances retained by PDC Securities were $0.5 million and $0.6 million and
those distributed to the soliciting broker/dealers amounted to $8.3 million and
$8.8 million for the years ended December 31, 2007 and 2006,
respectively. In 2008, we did not offer a drilling partnership;
therefore, no commissions and marketing allowances were received, distributed or
retained by PDC Securities.
NOTE
12 - LEASE OBLIGATIONS
We
have entered into operating leases principally for the leasing of natural gas
compressors, office space in Denver and Bridgeport, and general office
equipment. The future minimum lease payments under these
non-cancelable operating leases as of December 31, 2008, are as
follows:
Year
|
|
(in
thousands)
|
|
2009
|
|
$ |
2,687 |
|
2010
|
|
|
1,645 |
|
2011
|
|
|
1,081 |
|
2012
|
|
|
309 |
|
2013
|
|
|
74 |
|
Thereafter
|
|
|
44 |
|
|
|
$ |
5,840 |
|
Operating
lease expense for the years ended December 31, 2008, 2007 and 2006, was $2.5
million, $1.5 million and $0.4 million, respectively.
NOTE
13 - SALE OF OIL AND GAS PROPERTIES
Grand
Valley Field Properties
In July
2006, we sold to an unaffiliated company a portion of our undeveloped leasehold
located in Grand Valley Field, Garfield County, Colorado. The sale
encompassed 100% of the working interest in approximately 8,700 acres, including
approximately 6,400 acres of the Chevron leasehold and 2,300 acres of the
Puckett Land Company leasehold. We retained approximately 475
undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in
addition to all of our producing properties in the field. The
proceeds from the sale were $353.6 million. We recorded a gain on
sale of leaseholds of $328 million and a deferred gain on sale of leaseholds of
$25.6 million.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Pursuant
to the purchase and sale agreement, we were obligated to either drill 16 wells
on specifically identified acreage over the next three years or pay liquidated
damages of $1.6 million per un-drilled well for a total contingent obligation of
$25.6 million, which was reflected as a deferred gain on sale of leaseholds on
the balance sheet as of December 31, 2006. In May 2007, we entered
into a letter agreement amending the original purchase and sale
agreement. The letter agreement relieved us of the obligation, in its
entirety, to either drill 16 wells or pay liquidated damages, resulting in the
recognition of the remaining $25.6 million deferred gain on sale of leaseholds
in the second quarter of 2007. Pursuant to the letter agreement, we
were obligated to drill six wells on specifically identified
acreage. As of December 31, 2007, we had drilled all six wells, which
were drilled on the unaffiliated party's leasehold for its benefit and at its
cost.
In
conjunction with the purchase and sale agreement described above, we entered
into a LKE agreement, in accordance with Section 1031 of the Internal Revenue
Code, with a “qualified intermediary.” Proceeds in the amount of $300
million were transferred directly to the qualified intermediary to be held in
trust pursuant to the terms of the LKE agreement. We had until
mid-January 2007 to close any acquisition of suitable like-kind property,
allowing us to take advantage of the income tax deferral benefits of a LKE
transaction.
In
December 2007, we sold to the same unaffiliated party above a portion of our
North Dakota properties for approximately $34.7 million. The
properties, located in Dunn, Williams and McKenzie Counties, North Dakota,
include interests in five producing Bakken wells and approximately 72,000 net
undeveloped acres. The reduction in our production and proved
reserves as a result of this transaction is not material. We recorded
a gain on sale of leaseholds of $7.7 million in the fourth quarter of
2007. Following the sale, we retain ownership in three producing
wells in Dunn County, ten producing wells in Burke County and approximately
60,000 acres of undeveloped leasehold in Burke County.
NOTE
14 – ACQUISITIONS
2007
Acquisitions
Acquisition
of Internal Revenue Code Section 1031 – Like-Kind Exchange
Properties
During
the first quarter of 2007, we completed the acquisition of suitable like-kind
properties in accordance with the LKE agreement we entered into in connection
with our sale of undeveloped leaseholds located in Grand Valley Field, Garfield
County, Colorado in July 2006. We acquired, for cash, qualifying oil
and gas properties totaling $188.9 million, including costs of acquisition, as
described below.
EXCO
Properties. On January 5, 2007, we completed the purchase of
producing properties and undeveloped drilling locations and acreage in the
Wattenberg Field of the DJ Basin, Colorado from EXCO Resources Inc., an
unaffiliated party. The acquisition included substantially all of
EXCO’s assets in the area and encompassed 144 oil and natural gas wells
(approximating 25.5 Bcfe proved developed reserves as of December 31, 2005) and
8,160 acres of leasehold interests. The wells and leases acquired are
located in Weld, Adams, Larimer, and Broomfield Counties,
Colorado. We operate the assets and hold a majority working interest
in the properties.
Company Sponsored
Partnerships. On January 10, 2007, we completed the purchase
of the remaining working interests in 44 of our sponsored
partnerships. The transaction resulted in an increase in our
ownership in 718 gross (423 net) wells that we currently operate. The
wells are located primarily in the Appalachian Basin and Michigan.
The
following table presents the adjusted purchase price for the like-kind exchange
property acquisitions described above as of December 31, 2007.
|
|
EXCO
|
|
|
Partnerships
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
Cash
consideration paid
|
|
$ |
128,672 |
|
|
$ |
57,776 |
|
Plus:
direct costs of acquisition
|
|
|
1,662 |
|
|
|
1,664 |
|
Less:
acquisition cost adjustments
|
|
|
(119 |
) |
|
|
(2,792 |
) |
Total acquisition
cost
|
|
$ |
130,215 |
|
|
$ |
56,648 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The
following table presents, as of the respective date of acquisition, the final
allocations of the purchase prices based on estimates of fair
value.
|
|
EXCO
|
|
|
Partnerships
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
Current
assets acquired
|
|
$ |
91 |
|
|
$ |
- |
|
Proved
oil and gas properties
|
|
|
117,099 |
|
|
|
59,081 |
|
Unproved
oil and gas properties
|
|
|
14,960 |
|
|
|
- |
|
Asset
retirement obligation
|
|
|
(422 |
) |
|
|
(2,433 |
) |
Other
liabilities assumed
|
|
|
(1,513 |
) |
|
|
- |
|
Total acquisition
cost
|
|
$ |
130,215 |
|
|
$ |
56,648 |
|
The
assessment of fair value of proved oil and gas properties acquired was based
primarily on projections of expected discounted future cash flows of acquired
oil and natural gas reserves. To compensate for the inherent risk of
estimating and valuing unproved properties, the discounted future net revenues
of probable reserves were reduced by additional risk-weighting factors in that
valuation.
Other. In January
2007, we acquired from unaffiliated parties other like-kind undeveloped
leaseholds in Erath County, Texas for $2.1 million, including costs of
acquisition. Acreage in this area is prospective for development of
oil and natural gas reserves in the Barnett Shale.
Other
Acquisitions
On
February 22, 2007, we acquired, from an unaffiliated party, 28 producing wells
and associated undeveloped acreage located in Colorado (Wattenberg Field) for a
purchase price of $12 million, which was allocated to oil and gas
properties.
On
October 30, 2007, with an effective date of October 1, 2007, we purchased from
unrelated parties, Castle Gas Company, et.al., a majority working interest in
762 natural gas wells located in southwestern Pennsylvania for approximately $54
million. We estimated that the acquisition included approximately 47
Bcfe of reserves, or 31 Bcfe of proved reserves and 16 Bcfe of unproved
reserves. The purchase also included associated pipelines, equipment,
real estate and undeveloped acreage.
The
following table presents the adjusted purchase price for the Castle acquisition
described above as of December 31, 2007.
|
|
(in
thousands)
|
|
|
|
|
|
Cash
consideration paid
|
|
$ |
53,041 |
|
Plus:
direct costs of acquisition
|
|
|
443 |
|
Plus:
acquisition cost adjustments
|
|
|
583 |
|
Total acquisition
cost
|
|
$ |
54,067 |
|
The
following table presents, as of the respective date of acquisition, the final
allocation of the purchase price based on estimates of fair value.
|
|
(in
thousands)
|
|
|
|
|
|
Current
assets acquired
|
|
$ |
185 |
|
Proved
oil and gas properties
|
|
|
55,778 |
|
Unproved
oil and gas properties
|
|
|
217 |
|
Real
estate and equipment, and other assets
|
|
|
2,115 |
|
Non
current assets
|
|
|
783 |
|
Asset
retirement obligation
|
|
|
(4,043 |
) |
Other
liabilities assumed
|
|
|
(968 |
) |
Total acquisition
cost
|
|
$ |
54,067 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The
assessment of fair value of proved oil and gas properties acquired was based
primarily on projections of expected discounted future cash flows of acquired
oil and natural gas reserves. To compensate for the inherent risk of
estimating and valuing unproved properties, the discounted future net revenues
of probable reserves were reduced by additional risk-weighting factors in that
valuation.
Pro
Forma Financial Information
The
results of operations for all of the above acquisitions have been included in
our consolidated financial statements from the dates of
acquisition. The pro forma effect of the inclusion in our
consolidated statement of operations for the year ended December 31, 2007, of
the results of operations for the January and February 2007 acquisitions
described above, individually and in the aggregate, was not
material.
The
following unaudited pro forma financial information presents a summary of our
consolidated results of operations for the years ended December 31, 2007 and
2006, assuming the acquisitions of the EXCO properties, our sponsored
partnerships and the Castle properties had been completed as of January 1, 2006,
including adjustments to reflect the allocation of the purchase price to the
acquired net assets. The pro forma effect of the inclusion of the
results of operations for all of the other acquisitions described above,
individually and in the aggregate, was not material.
|
|
Year
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
310,351 |
|
|
$ |
315,492 |
|
Net
income
|
|
$ |
34,571 |
|
|
$ |
243,105 |
|
Earnings
per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
2.34 |
|
|
$ |
15.52 |
|
Diluted
|
|
$ |
2.33 |
|
|
$ |
15.44 |
|
The pro
forma results of operations are not necessarily indicative of what our results
of operations would have been had the EXCO properties, our sponsored
partnerships and the Castle properties been acquired at the beginning of the
periods indicated, nor does it purport to represent our results of operations
for any future periods.
2006
Acquisitions
On
December 6, 2006, we completed a cash tender offer and purchased approximately
95.5% or 9,112,750 shares of the outstanding common stock of Unioil, an
independent energy company with properties in northern Colorado and southern
Wyoming. The acquisition of more than 90% of the outstanding shares
of common stock allowed us to effect a short-form merger of Unioil and one of
our wholly-owned subsidiaries, resulting in the acquisition of the remaining
428,719 shares of Unioil. Each share of Unioil common stock not
tendered through the offer was converted into the right to receive $1.91 in
cash, the same consideration paid for shares in the tender offer. The
total price paid for 100% of Unioil’s outstanding common stock was $18.6
million, including $0.4 million in direct costs of the
acquisition. The final acquisition cost allocation as reflected on
our consolidated balance sheets as of December 31, 2007, included $25.8 million
in properties and equipment, current assets of $0.7 million, a deferred tax
liability of $6.8 million and other liabilities assumed of $1
million. The pro forma effect of the inclusion of Unioil in our 2006
results of operations was not material.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE
15 – MAJOR CUSTOMERS
The
following table identifies sales to individual customers constituting 10% or
more of oil and natural gas sales, including natural gas sales by our natural
gas marketing activities segment, and total revenues.
|
|
Oil
and Gas Sales
|
|
|
Total
Revenues
|
|
|
|
Year
Ended December 31,
|
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Customer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams
Production RMT Company
|
|
|
16.3 |
% |
|
|
14.1 |
% |
|
|
8.7 |
% |
|
|
12.4 |
% |
|
|
12.9 |
% |
|
|
7.5 |
% |
Tepco
Crude Oil, LLC
|
|
|
14.3 |
% |
|
|
14.8 |
% |
|
|
14.9 |
% |
|
|
10.8 |
% |
|
|
13.5 |
% |
|
|
12.9 |
% |
DCP
Midstream, LP
|
|
|
8.8 |
% |
|
|
7.8 |
% |
|
|
10.6 |
% |
|
|
6.6 |
% |
|
|
7.1 |
% |
|
|
9.1 |
% |
Sempra
Energy Trading
|
|
|
5.4 |
% |
|
|
6.0 |
% |
|
|
10.3 |
% |
|
|
4.1 |
% |
|
|
5.5 |
% |
|
|
8.9 |
% |
NOTE
16 - BUSINESS SEGMENTS
We
separate our operating activities into four segments: oil and gas
sales, natural gas marketing, well operations and pipeline income and oil and
gas well drilling operations. All material inter-company accounts and
transactions between segments have been eliminated.
Oil and Gas Sales. Our
oil and gas sales segment represents revenues and expenses from the production
and sale of oil and natural gas. Segment revenue includes oil and gas
price risk management, net. Segment profit consists of oil and gas
sales revenues less its proportionate share of oil and gas production and well
operations cost, exploration expense, direct general and administrative expense
and DD&A expense. Segment DD&A expense was $100.2 million,
$68.1 million and $31.3 million in 2008, 2007 and 2006,
respectively.
Natural Gas Marketing
Activities. Our
natural gas marketing segment is composed of our wholly owned subsidiary, RNG,
through which we purchase, aggregate and resell natural gas produced by us and
others. Segment profit primarily represents sales from natural gas
marketing activities and direct interest income less costs of natural gas
marketing activities, direct general and administrative expense.
Well Operations and Pipeline
Income. We
charge our affiliated partnerships and other third parties competitive industry
rates for well operations and natural gas gathering. Segment revenue
includes monthly operating and gas gathering fees we charge for each well in
which we operate that is owned by others, including our sponsored
partnerships. Segment profit consists of well operations and pipeline
income revenues less its proportionate share of oil and gas production and well
operations cost and direct DD&A expense. Segment DD&A expense
was $1.9 million, $1.2 million and $1.9 million in 2008, 2007, 2006,
respectively.
Oil and Gas Well Drilling
Operations. We drill natural gas
wells for Company-sponsored drilling partnerships and retain an interest in each
well. Our drilling and development segment reflects results of drilling and
development activities conducted for affiliated and non-affiliated
parties. Segment profit consists of oil and gas well drilling
revenues less cost of oil and gas well drilling.
Other. This
segment includes unallocated corporate general administrative expense, direct
DD&A expense, direct interest income and interest expense.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Segment
information for the years ended December 31, 2008, 2007 and 2006 is presented
below.
Year
Ended December 31,
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Revenues:
|
|
(in
thousands)
|
|
Oil
and gas sales
|
|
$ |
449,715 |
|
|
$ |
177,943 |
|
|
$ |
124,336 |
|
Natural
gas marketing activities
|
|
|
140,263 |
|
|
|
103,624 |
|
|
|
131,326 |
|
Well
operations and pipeline income
|
|
|
11,474 |
|
|
|
9,342 |
|
|
|
10,704 |
|
Oil
and gas well drilling operations
|
|
|
7,615 |
|
|
|
12,154 |
|
|
|
17,917 |
|
Unallocated
amounts
|
|
|
293 |
|
|
|
2,172 |
|
|
|
2,220 |
|
Total
|
|
$ |
609,360 |
|
|
$ |
305,235 |
|
|
$ |
286,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
Income Before Income Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$ |
231,885 |
|
|
$ |
42,068 |
|
|
$ |
61,868 |
|
Natural
gas marketing activities
|
|
|
1,329 |
|
|
|
3,822 |
|
|
|
1,816 |
|
Well
operations and pipeline income
|
|
|
3,933 |
|
|
|
3,136 |
|
|
|
2,823 |
|
Oil
and gas well drilling operations
|
|
|
5,402 |
|
|
|
9,646 |
|
|
|
5,300 |
|
Unallocated
amounts
|
|
|
(67,781 |
) |
|
|
(4,482 |
) |
|
|
315,602 |
|
Total
|
|
$ |
174,768 |
|
|
$ |
54,190 |
|
|
$ |
387,409 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures
for Segment Long-Lived Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
& gas sales
|
|
$ |
309,395 |
|
|
$ |
226,801 |
|
|
$ |
133,401 |
|
Natural
gas marketing activities
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Well
operations and pipeline income
|
|
|
7,564 |
|
|
|
6,715 |
|
|
|
1,419 |
|
Oil
and gas well drilling operations
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Unallocated
amounts
|
|
|
6,194 |
|
|
|
5,472 |
|
|
|
12,125 |
|
Total
|
|
$ |
323,153 |
|
|
$ |
238,988 |
|
|
$ |
146,945 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
& gas sales
|
|
$ |
1,247,687 |
|
|
$ |
862,237 |
|
|
$ |
394,952 |
|
Natural
gas marketing activities
|
|
|
50,117 |
|
|
|
40,269 |
|
|
|
39,899 |
|
Well
operations and pipeline income
|
|
|
50,052 |
|
|
|
26,156 |
|
|
|
28,895 |
|
Oil
and gas well drilling operations
|
|
|
2,028 |
|
|
|
4,959 |
|
|
|
87,746 |
|
Unallocated
amounts
|
|
|
52,820 |
|
|
|
116,858 |
|
|
|
332,795 |
|
Total
|
|
$ |
1,402,704 |
|
|
$ |
1,050,479 |
|
|
$ |
884,287 |
|
NOTE
17 – SUBSEQUENT EVENTS
West
Virginia royalty litigation. On January 26, 2009, we received notice of a lawsuit
filed in West Virginia state court in Barbour County, Beymer
and Beymer v. Petroleum Development Corporation and Riley National Gas
Company, CA No. 09-C-3 (“Beymer lawsuit”) , alleging a class action for
failure to properly pay royalties. The allegations state that the
Company improperly deducted certain charges and costs before applying the
royalty percentage. Punitive damages are requested in addition to
breach of contract, tort, and fraud allegations. On February 25,
2009, we filed to remove the action to federal court.
On
January 30, 2009, the Company was served with another lawsuit alleging class
action related to royalty payments file in West Virginia state court in Harrison
County, Gobel,
Phares and Cather v. Petroleum Development Corporation, CA No.
09-40-2. West Virginia oil and gas production constitutes
approximately 8% of the Company’s current oil and gas sales. Given
the preliminary stage of these proceedings and the inherent uncertainty in
litigation, the Company is unable to predict the ultimate outcome of these suits
at this time.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE
18 – SUPPLEMENTAL OIL AND GAS INFORMATION – UNAUDITED
Costs
Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
We
incurred costs in oil and gas property acquisition, exploration and development
are presented below.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
Acquisition
of properties:
|
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
$ |
6,147 |
|
|
$ |
257,330 |
|
|
$ |
802 |
|
Unproved
properties
|
|
|
6,890 |
|
|
|
13,701 |
|
|
|
11,926 |
|
Development
costs
|
|
|
257,656 |
|
|
|
194,031 |
|
|
|
114,487 |
|
Exploration
costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
drilling
|
|
|
26,499 |
|
|
|
12,972 |
|
|
|
18,660 |
|
Geological
and Geophysical
|
|
|
2,121 |
|
|
|
6,299 |
|
|
|
2,234 |
|
Total
costs incurred
|
|
$ |
299,313 |
|
|
$ |
484,333 |
|
|
$ |
148,109 |
|
The
proved reserves attributable to the development costs in the above table were
125,198 MMcf and 2,354 MBbls for 2008, 216,383 MMcf
and 3,700 MBbls for 2007 and 64,126 MMcf and 2,955 MBbls for 2006. Of
the above development costs incurred for the years ended December 31, 2008, 2007
and 2006, the amounts of $66.2 million, $37.1 million, and $20.1 million,
respectively, were incurred to develop proved undeveloped properties from the
prior year end.
Property
acquisition costs include costs incurred to purchase, lease or otherwise acquire
a property. Development costs include costs incurred to gain access
to and prepare development well locations for drilling, to drill and equip
development wells, recompletions and to provide facilities to extract, treat,
gather and store oil and gas. Exploration costs include costs
incurred in identifying areas that may warrant examination and in examining
specific areas that are considered to have prospects of containing oil and gas
reserves.
Capitalized
Oil and Gas Costs
Aggregate
capitalized costs for related to oil and gas exploration and production
activities with applicable accumulated depreciation, depletion and amortization
are presented below:
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
Proved
oil and gas properties
|
|
$ |
1,245,316 |
|
|
$ |
953,904 |
|
Unproved
oil and gas properties
|
|
|
32,768 |
|
|
|
41,023 |
|
|
|
|
1,278,084 |
|
|
|
994,927 |
|
Less
accumulated depreciation, depletion and amortization
|
|
|
306,142 |
|
|
|
196,310 |
|
|
|
$ |
971,942 |
|
|
$ |
798,617 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Results
of Operations for Oil and Gas Producing Activities
The
results of operations for oil and gas producing activities, excluding natural
gas marketing activities, are presented below.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$ |
321,877 |
|
|
$ |
175,187 |
|
|
$ |
115,189 |
|
Oil
and gas price risk management gain, net
|
|
|
127,838 |
|
|
|
2,756 |
|
|
|
9,147 |
|
|
|
|
449,715 |
|
|
|
177,943 |
|
|
|
124,336 |
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
costs
|
|
|
72,518 |
|
|
|
44,238 |
|
|
|
20,855 |
|
Depreciation,
depletion and amortization
|
|
|
100,207 |
|
|
|
68,086 |
|
|
|
30,988 |
|
Exploration
costs
|
|
|
45,105 |
|
|
|
23,551 |
|
|
|
8,131 |
|
|
|
|
217,830 |
|
|
|
135,875 |
|
|
|
59,974 |
|
Results
of operations for oil and gas producing activities before provision for
income taxes
|
|
|
231,885 |
|
|
|
42,068 |
|
|
|
64,362 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for income taxes
|
|
|
86,493 |
|
|
|
16,280 |
|
|
|
24,818 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results
of operations for oil and gas producing activities, excludes corporate
overhead and interest costs
|
|
$ |
145,392 |
|
|
$ |
25,788 |
|
|
$ |
39,544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
costs include those costs incurred to operate and maintain productive wells and
related equipment, including costs such as labor, repairs, maintenance,
materials, supplies, fuel consumed, insurance and production and severance
taxes. In addition, production costs include administrative expenses
and depreciation applicable to support equipment associated with these
activities. Depreciation, depletion and amortization expense includes those
costs associated with capitalized acquisition, exploration and development
costs, but does not include the depreciation applicable to support
equipment. The provision for income taxes is computed using effective
tax rates.
Net
Proved Oil and Gas Reserves
We
utilized the services of independent petroleum engineers to estimate our oil and
gas reserves. For the years ended December 31, 2008 and 2007, our
reserve estimates for the Appalachian and Michigan Basins are based on reserve
reports prepared by Wright & Company and for the Rocky Mountain Region,
reserve estimates are based on reserve reports prepared by Ryder Scott Company,
L.P. For the year ended December 31, 2006, our reserve estimates for
the Appalachian and Michigan Basins and NECO Area were based on reserve reports
prepared by Wright & Company and our reserve estimates for the Rocky
Mountain Region, with the exception of the NECO properties, were based on
reserve reports prepared by Ryder Scott. These reserve estimates have
been prepared in compliance with professional standards and the reserves
definitions prescribed by the SEC.
Proved
reserves are the estimated quantities of oil and natural gas that geologic and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Estimates of proved reserves may change, either
positively or negatively, as additional information becomes available and as
contractual, economic and political conditions change. The Company's
net proved reserve estimates have been adjusted as necessary to reflect all
contractual agreements, royalty obligations and interests owned by others at the
time of the estimate.
Proved
developed reserves are the quantities of oil and natural gas expected to be
recovered through existing wells with existing equipment and operating
methods. In some cases, proved
undeveloped reserves may require substantial new investments in
additional wells and related facilities.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
An
analysis of the change in estimated quantities of oil and gas reserves, all of
which are located within the U.S., is shown below.
|
|
Oil
(MBbl)
|
|
|
Gas
(MMcf)
|
|
|
Total
(MMcfe)
|
|
Proved
Reserves:
|
|
|
|
|
|
|
|
|
|
Proved
reserves, January 1, 2006
|
|
|
4,538 |
|
|
|
247,288 |
|
|
|
274,516 |
|
Revisions
of previous estimates
|
|
|
226 |
|
|
|
(21,721 |
) |
|
|
(20,365 |
) |
Extensions,
discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
Michigan
Basin
|
|
|
- |
|
|
|
225 |
|
|
|
225 |
|
Rocky
Mountain Region
|
|
|
2,955 |
|
|
|
63,901 |
|
|
|
81,631 |
|
Purchases
of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
- |
|
|
|
222 |
|
|
|
222 |
|
Michigan
Basin
|
|
|
- |
|
|
|
35 |
|
|
|
35 |
|
Rocky
Mountain Region
|
|
|
276 |
|
|
|
3,504 |
|
|
|
5,160 |
|
Dispositions
to partnerships
|
|
|
(92 |
) |
|
|
(1,215 |
) |
|
|
(1,767 |
) |
Production
|
|
|
(631 |
) |
|
|
(13,161 |
) |
|
|
(16,947 |
) |
Proved
reserves, December 31, 2006
|
|
|
7,272 |
|
|
|
279,078 |
|
|
|
322,710 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of previous estimates
|
|
|
1,375 |
|
|
|
14,177 |
|
|
|
22,427 |
|
Extensions,
discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
- |
|
|
|
5,493 |
|
|
|
5,493 |
|
Michigan
Basin
|
|
|
- |
|
|
|
488 |
|
|
|
488 |
|
Rocky
Mountain Region
|
|
|
3,700 |
|
|
|
210,402 |
|
|
|
232,602 |
|
Purchases
of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
2 |
|
|
|
63,014 |
|
|
|
63,026 |
|
Michigan
Basin
|
|
|
- |
|
|
|
6,059 |
|
|
|
6,059 |
|
Rocky
Mountain Region
|
|
|
4,490 |
|
|
|
39,239 |
|
|
|
66,179 |
|
Dispositions
to partnerships
|
|
|
(591 |
) |
|
|
(1,874 |
) |
|
|
(5,420 |
) |
Production
|
|
|
(910 |
) |
|
|
(22,513 |
) |
|
|
(27,973 |
) |
Proved
reserves, December 31, 2007
|
|
|
15,338 |
|
|
|
593,563 |
|
|
|
685,591 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of previous estimates
|
|
|
(1,538 |
) |
|
|
(25,216 |
) |
|
|
(34,444 |
) |
Extensions,
discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
- |
|
|
|
24,875 |
|
|
|
24,875 |
|
Rocky
Mountain Region
|
|
|
2,354 |
|
|
|
100,323 |
|
|
|
114,447 |
|
Purchases
of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
- |
|
|
|
83 |
|
|
|
83 |
|
Michigan
Basin
|
|
|
- |
|
|
|
46 |
|
|
|
46 |
|
Rocky
Mountain Region
|
|
|
106 |
|
|
|
1,712 |
|
|
|
2,348 |
|
Dispositions
to partnerships
|
|
|
(63 |
) |
|
|
(769 |
) |
|
|
(1,147 |
) |
Production
|
|
|
(1,160 |
) |
|
|
(31,760 |
) |
|
|
(38,720 |
) |
Proved
reserves, December 31, 2008
|
|
|
15,037 |
|
|
|
662,857 |
|
|
|
753,079 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Developed Reserves(1),
as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1, 2006
|
|
|
2,848 |
|
|
|
146,664 |
|
|
|
163,752 |
|
December
31, 2006
|
|
|
3,503 |
|
|
|
144,672 |
|
|
|
165,690 |
|
December
31, 2007
|
|
|
5,219 |
|
|
|
286,570 |
|
|
|
317,884 |
|
December
31, 2008
|
|
|
5,438 |
|
|
|
297,041 |
|
|
|
329,669 |
|
______________
|
(1)
|
December
31, 2008, 2007, 2006, and January 1, 2006, reserve amounts reflect the
reclassification of our Rocky Mountain Region refrac and behind pipe
reserves of 75,863 MMcfe, 49,801 MMcfe, 21,062 MMcfe and 14,762 MMcfe,
respectively, from proved developed to proved
undeveloped.
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
2008
Activity. In 2008, we
recorded a downward revision of our previous estimate of proved reserves of
approximately 34 Bcfe. The revision was primarily due to a decrease
of approximately 50 Bcfe due to lower commodity prices, 26 Bcfe due to increased
operating costs, and 15 Bcfe due to adjustments to proved undeveloped reserve
values, partially offset be an increase of 55 Bcfe due to asset
performance. New discoveries and extensions of 139 Bcfe in 2008 are
due to drilling of 229 net wells and the addition of new proved undeveloped
reserves. Approximately 25 Bcfe were added in the Appalachian Basin,
and approximately 114 Bcfe were added in the Rocky Mountain Region with 26 Bcfe
in the Wattenberg Field, 80 Bcfe in Grand Valley Field, and 8 Bcfe in the NECO
area. We acquired approximately 2 Bcfe of proved reserves through the
purchases of interest in some of our existing properties. We
primarily acquired reserves in the Wattenberg Field with the remaining reserves
being split between the Appalachian Basin, Michigan, Piceance, the NECO area and
North Dakota. We sold proved reserves of approximately 1 Bcfe to
unaffiliated third parties and to our sponsored partnerships for drilling
activity.
2007 Activity. In
2007, we recorded an upward revision to our previous estimate of proved reserves
of approximately 22 Bcfe. The revision was primarily due to an
increase of approximately 25 Bcfe and 12 Bcfe, respectively, due to asset
performance and higher commodity prices, partially offset by a decrease of
approximately 15 Bcfe due primarily to increased operating costs, adjustments to
proved undeveloped reserve values and change in well ownership
interests. New discoveries and extensions of 239 Bcfe in 2007 are due
to the drilling of 218 net wells and the addition of new proved undeveloped
reserves. Approximately 233 Bcfe were added in the Rocky Mountain
Region, with 43 Bcfe in the Wattenberg Field, 170 Bcfe in Grand Valley Field and
19 Bcfe in the NECO area. We acquired approximately 135 Bcfe of
proved reserves through purchases of oil and natural gas
properties. In the Rocky Mountain Region approximately 66 Bcfe of
proved reserves were acquired in the Wattenberg Field, in the Appalachian Basin
approximately 75 Bcfe were acquired and approximately 6 Bcfe in the Michigan
Basin. We sold proved reserves of approximately 5 Bcfe to
unaffiliated third parties and to our sponsored partnerships for drilling
activity.
2006 Activity. In
2006 we recorded a downward revision to our previous estimate of proved reserves
of approximately 20 Bcfe. The revision was primarily due to a
decrease of 3 Bcfe due to asset performance and a decrease of 10 Bcfe due to
lower commodity prices and a decrease of approximately 7 Bcfe due to changes in
proved undeveloped reserve value, operating expense, and well ownership
interests. New discoveries and extensions in 2006 of approximately 82
Bcfe were primarily due to the drilling of 91 net wells and adding new proved
undeveloped reserves in the Rocky Mountain Region. Approximately 34
Bcfe were added in Wattenberg Field, 33 Bcfe in Grand Valley Field and 12 Bcfe
in the NECO area. We acquired approximately 5 Bcfe of proved reserves
through purchases of oil and natural gas properties in Wattenberg
Field. We sold proved reserves of approximately 2 Bcfe to our
sponsored partnerships.
Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein Relating to
Proved Oil and Gas Reserves
Summarized
in the following table is information with respect to the standardized measure
of discounted future net cash flows relating to proved oil and gas
reserves. Future cash inflows are computed by applying year-end
prices of oil and gas relating to our proved reserves to the year-end quantities
of those reserves. Future production, development, site restoration
and abandonment costs are derived based on current costs assuming continuation
of existing economic conditions. Future income tax expenses are
computed by applying the statutory rate in effect at the end of each year to the
future pretax net cash flows, less the tax basis of the properties and gives
effect to permanent differences, tax credits and allowances related to the
properties.
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Future
estimated cash flows
|
|
$ |
3,867,461 |
|
|
$ |
5,257,962 |
|
|
$ |
1,804,796 |
|
Future
estimated production costs
|
|
|
(1,325,362 |
) |
|
|
(1,374,027 |
) |
|
|
(571,346 |
) |
Future
estimated development costs
|
|
|
(1,100,533 |
) |
|
|
(876,961 |
) |
|
|
(373,460 |
) |
Future
estimated income tax expense
|
|
|
(384,676 |
) |
|
|
(1,159,489 |
) |
|
|
(334,536 |
) |
Future
net cash flows
|
|
|
1,056,890 |
|
|
|
1,847,485 |
|
|
|
525,454 |
|
10%
annual discount for estimated timing of cash flows
|
|
|
(700,085 |
) |
|
|
(1,094,414 |
) |
|
|
(309,792 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future
estimated net cash flows
|
|
$ |
356,805 |
|
|
$ |
753,071 |
|
|
$ |
215,662 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The
following table summarizes the principal sources of change in the standardized
measure of discounted future estimated net cash flows.
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of oil and gas production net of production costs
|
|
$ |
(261,692 |
) |
|
$ |
(137,725 |
) |
|
$ |
(94,337 |
) |
Net
changes in prices and production costs
|
|
|
(479,894 |
) |
|
|
157,797 |
|
|
|
(301,132 |
) |
Extensions,
discoveries, and improved recovery, less related costs
|
|
|
80,859 |
|
|
|
317,031 |
|
|
|
46,109 |
|
Sales
of reserves
|
|
|
(2,012 |
) |
|
|
(7,846 |
) |
|
|
(3,356 |
) |
Purchase
of reserves
|
|
|
4,280 |
|
|
|
342,792 |
|
|
|
11,003 |
|
Development
costs incurred during the period
|
|
|
88,008 |
|
|
|
42,510 |
|
|
|
20,051 |
|
Revisions
of previous quantity estimates
|
|
|
(79,536 |
) |
|
|
92,462 |
|
|
|
(22,090 |
) |
Changes
in estimated income taxes
|
|
|
239,054 |
|
|
|
(335,327 |
) |
|
|
120,818 |
|
Accretion
of discount
|
|
|
122,409 |
|
|
|
38,660 |
|
|
|
62,838 |
|
Timing
and other
|
|
|
|
|
|
|
|
|
|
|
|
|
Timing
|
|
|
(20,117 |
) |
|
|
27,055 |
|
|
|
(29,672 |
) |
Net
changes in future development costs
|
|
|
(87,625 |
) |
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
(396,266 |
) |
|
$ |
537,409 |
|
|
$ |
(189,768 |
) |
It is
necessary to emphasize that the data presented should not be viewed as
representing the expected cash flow from, or current value of, existing proved
reserves since the computations are based on a large number of estimates and
arbitrary assumptions. Reserve quantities cannot be measured with
precision and their estimation requires many judgmental determinations and
frequent revisions. The required projection of production and related
expenditures over time requires further estimates with respect to pipeline
availability, rates of demand and governmental control. Actual future
prices and costs are likely to be substantially different from the current
prices and costs utilized in the computation of reported amounts. Any
analysis or evaluation of the reported amounts should give specific recognition
to the computational methods utilized and the limitations inherent
therein.
The
estimated present value of future cash flows relating to proved reserves is
extremely sensitive to prices used at any measurement period. The
average December 31 price used for each commodity at December 31, 2008, 2007 and
2006 is presented below.
|
|
Average
Price
|
|
As
of December 31,
|
|
Oil
|
|
|
Gas
|
|
2008
|
|
$ |
37.85 |
|
|
$ |
4.98 |
|
2007
|
|
|
80.67 |
|
|
|
6.77 |
|
2006
|
|
|
57.70 |
|
|
|
4.96 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE
19 - QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly
financial data for the years ended December 31, 2008 and 2007, are presented
below The sum of the quarters may not equal the total of the
year's net income per share due to changes in the weighted average shares
outstanding throughout the year.
|
|
2008
|
|
|
|
Quarter
Ended
|
|
|
|
|
|
|
3/31/2008
|
|
|
6/30/2008
|
|
|
9/30/2008
|
|
|
12/31/2008
|
|
|
Year
Ended
|
|
|
|
(in
thousands, except per share data)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$ |
71,646 |
|
|
$ |
94,549 |
|
|
$ |
99,422 |
|
|
$ |
56,260 |
|
|
$ |
321,877 |
|
Sales
from natural gas marketing activities
|
|
|
23,325 |
|
|
|
30,941 |
|
|
|
53,372 |
|
|
|
32,625 |
|
|
|
140,263 |
|
Oil
and gas well drilling
|
|
|
3,083 |
|
|
|
2,887 |
|
|
|
1,232 |
|
|
|
413 |
|
|
|
7,615 |
|
Well
operations and pipeline income
|
|
|
2,352 |
|
|
|
2,438 |
|
|
|
3,356 |
|
|
|
3,328 |
|
|
|
11,474 |
|
Oil
and gas price risk management gain (loss), net
|
|
|
(42,310 |
) |
|
|
(101,798 |
) |
|
|
169,402 |
|
|
|
102,544 |
|
|
|
127,838 |
|
Other
income
|
|
|
3 |
|
|
|
34 |
|
|
|
20 |
|
|
|
236 |
|
|
|
293 |
|
Total
revenues
|
|
|
58,099 |
|
|
|
29,051 |
|
|
|
326,804 |
|
|
|
195,406 |
|
|
|
609,360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas production and well operations costs
|
|
|
18,132 |
|
|
|
20,815 |
|
|
|
22,173 |
|
|
|
17,089 |
|
|
|
78,209 |
|
Cost
of natural gas marketing activities
|
|
|
22,121 |
|
|
|
30,117 |
|
|
|
54,372 |
|
|
|
32,624 |
|
|
|
139,234 |
|
Cost
of oil and gas well drilling
|
|
|
78 |
|
|
|
518 |
|
|
|
501 |
|
|
|
1,116 |
|
|
|
2,213 |
|
Exploration
expense
|
|
|
4,283 |
|
|
|
3,467 |
|
|
|
10,212 |
|
|
|
27,143 |
|
|
|
45,105 |
|
General
and administrative expense
|
|
|
9,823 |
|
|
|
9,231 |
|
|
|
8,106 |
|
|
|
10,555 |
|
|
|
37,715 |
|
Depreciation,
depletion and amortization
|
|
|
21,131 |
|
|
|
22,105 |
|
|
|
28,645 |
|
|
|
32,694 |
|
|
|
104,575 |
|
Total
costs and expenses
|
|
|
75,568 |
|
|
|
86,253 |
|
|
|
124,009 |
|
|
|
121,221 |
|
|
|
407,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) from operations
|
|
|
(17,469 |
) |
|
|
(57,202 |
) |
|
|
202,795 |
|
|
|
74,185 |
|
|
|
202,309 |
|
Interest
income
|
|
|
271 |
|
|
|
75 |
|
|
|
151 |
|
|
|
94 |
|
|
|
591 |
|
Interest
expense
|
|
|
(4,932 |
) |
|
|
(6,394 |
) |
|
|
(7,817 |
) |
|
|
(8,989 |
) |
|
|
(28,132 |
) |
Income
(loss) before income taxes
|
|
|
(22,130 |
) |
|
|
(63,521 |
) |
|
|
195,129 |
|
|
|
65,290 |
|
|
|
174,768 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
(benefit) for income taxes
|
|
|
(8,202 |
) |
|
|
(22,809 |
) |
|
|
68,233 |
|
|
|
24,237 |
|
|
|
61,459 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
(13,928 |
) |
|
$ |
(40,712 |
) |
|
$ |
126,896 |
|
|
$ |
41,053 |
|
|
$ |
113,309 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
(0.95 |
) |
|
$ |
(2.76 |
) |
|
$ |
8.59 |
|
|
$ |
2.78 |
|
|
$ |
7.69 |
|
Diluted
|
|
$ |
(0.95 |
) |
|
$ |
(2.76 |
) |
|
$ |
8.55 |
|
|
$ |
2.78 |
|
|
$ |
7.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average common and common equivalent shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
14,738 |
|
|
|
14,742 |
|
|
|
14,767 |
|
|
|
14,778 |
|
|
|
14,736 |
|
Diluted
|
|
|
14,738 |
|
|
|
14,742 |
|
|
|
14,835 |
|
|
|
14,791 |
|
|
|
14,848 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
|
2007
|
|
|
|
Quarter
Ended
|
|
|
|
|
|
|
3/31/2007
|
|
|
6/30/2007
|
|
|
9/30/2007
|
|
|
12/31/2007
|
|
|
Year
Ended
|
|
|
|
(in
thousands, except per share data)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$ |
34,016 |
|
|
$ |
39,246 |
|
|
$ |
44,437 |
|
|
$ |
57,488 |
|
|
$ |
175,187 |
|
Sales
from natural gas marketing activities
|
|
|
21,987 |
|
|
|
29,924 |
|
|
|
19,934 |
|
|
|
31,779 |
|
|
|
103,624 |
|
Oil
and gas well drilling
|
|
|
4,030 |
|
|
|
1,739 |
|
|
|
1,573 |
|
|
|
4,812 |
|
|
|
12,154 |
|
Well
operations and pipeline income
|
|
|
3,298 |
|
|
|
1,292 |
|
|
|
2,092 |
|
|
|
2,660 |
|
|
|
9,342 |
|
Oil
and gas price risk management (loss) gain, net
|
|
|
(5,645 |
) |
|
|
3,742 |
|
|
|
6,345 |
|
|
|
(1,686 |
) |
|
|
2,756 |
|
Other
income
|
|
|
226 |
|
|
|
2 |
|
|
|
1,894 |
|
|
|
50 |
|
|
|
2,172 |
|
Total
revenues
|
|
|
57,912 |
|
|
|
75,945 |
|
|
|
76,275 |
|
|
|
95,103 |
|
|
|
305,235 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas production costs and well operations costs
|
|
|
9,035 |
|
|
|
11,628 |
|
|
|
12,645 |
|
|
|
15,956 |
|
|
|
49,264 |
|
Cost
of natural gas marketing activities
|
|
|
21,512 |
|
|
|
28,780 |
|
|
|
19,810 |
|
|
|
30,482 |
|
|
|
100,584 |
|
Cost
of oil and gas well drilling
|
|
|
564 |
|
|
|
246 |
|
|
|
749 |
|
|
|
949 |
|
|
|
2,508 |
|
Exploration
expense
|
|
|
2,678 |
|
|
|
6,780 |
|
|
|
5,337 |
|
|
|
8,756 |
|
|
|
23,551 |
|
General
and administrative expense
|
|
|
7,424 |
|
|
|
6,886 |
|
|
|
7,513 |
|
|
|
9,145 |
|
|
|
30,968 |
|
Depreciation,
depletion and amortization
|
|
|
13,074 |
|
|
|
17,429 |
|
|
|
20,354 |
|
|
|
19,987 |
|
|
|
70,844 |
|
Total
costs and expenses
|
|
|
54,287 |
|
|
|
71,749 |
|
|
|
66,408 |
|
|
|
85,275 |
|
|
|
277,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
on sale of leaseholds
|
|
|
- |
|
|
|
25,600 |
|
|
|
- |
|
|
|
7,691 |
|
|
|
33,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from operations
|
|
|
3,625 |
|
|
|
29,796 |
|
|
|
9,867 |
|
|
|
17,519 |
|
|
|
60,807 |
|
Interest
income
|
|
|
1,143 |
|
|
|
454 |
|
|
|
462 |
|
|
|
603 |
|
|
|
2,662 |
|
Interest
expense
|
|
|
(831 |
) |
|
|
(1,450 |
) |
|
|
(2,544 |
) |
|
|
(4,454 |
) |
|
|
(9,279 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
3,937 |
|
|
|
28,800 |
|
|
|
7,785 |
|
|
|
13,668 |
|
|
|
54,190 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
1,436 |
|
|
|
10,749 |
|
|
|
3,326 |
|
|
|
5,470 |
|
|
|
20,981 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
2,501 |
|
|
$ |
18,051 |
|
|
$ |
4,459 |
|
|
$ |
8,198 |
|
|
$ |
33,209 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.17 |
|
|
$ |
1.22 |
|
|
$ |
0.30 |
|
|
$ |
0.56 |
|
|
$ |
2.25 |
|
Diluted
|
|
$ |
0.17 |
|
|
$ |
1.21 |
|
|
$ |
0.30 |
|
|
$ |
0.55 |
|
|
$ |
2.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average common and common equivalent shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
14,726 |
|
|
|
14,740 |
|
|
|
14,757 |
|
|
|
14,758 |
|
|
|
14,744 |
|
Diluted
|
|
|
14,854 |
|
|
|
14,860 |
|
|
|
14,827 |
|
|
|
14,859 |
|
|
|
14,841 |
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Schedule
II -VALUATION AND QUALIFYING ACCOUNTS
Description
|
|
Beginning
Balance
January 1
|
|
|
Charged
to
Costs
and Expenses
|
|
|
Deductions
|
|
|
Ending
Balance
December 31
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts
(a)
|
|
$ |
357 |
|
|
$ |
180 |
|
|
$ |
- |
|
|
$ |
537 |
|
Valuation
allowance for unproved oil and gas properties
(b)
|
|
$ |
2,365 |
|
|
$ |
12,798 |
|
|
$ |
2,293 |
|
|
$ |
12,870 |
|
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts
(a)
|
|
$ |
415 |
|
|
$ |
50 |
|
|
$ |
108 |
|
|
$ |
357 |
|
Valuation
allowance for unproved oil and gas properties
(b)
|
|
$ |
596 |
|
|
$ |
2,183 |
|
|
$ |
414 |
|
|
$ |
2,365 |
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts
(a)
|
|
$ |
409 |
|
|
$ |
7 |
|
|
$ |
1 |
|
|
$ |
415 |
|
Valuation
allowance for unproved oil and gas properties
(b)
|
|
$ |
33 |
|
|
$ |
653 |
|
|
$ |
90 |
|
|
$ |
596 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Deductions represent the write-off of accounts receivable deemed
uncollectible.
|
(b)
Deductions represent amortization of expired or abandoned unproved
oil and gas
properties.
|
F-48