form10q.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
x
|
Quarterly
Report Pursuant To Section 13 or 15(d) of The Securities Exchange
Act of
1934
|
For
The Quarterly Period Ended June 30,2007
OR
¨
|
Transition
Report Pursuant To Section 15(d) of The Securities Exchange Act of
1934
|
Commission
File Number: 000-51801
ROSETTA
RESOURCES INC.
(Exact
name of registrant as specified in its charter)
|
Delaware
|
|
43-2083519
|
|
|
(State
or other jurisdiction of incorporation or
organization)
|
|
(I.R.S.
Employer Identification No.)
|
|
|
|
|
|
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717
Texas, Suite 2800, Houston, TX
|
|
77002
|
|
|
(Address
of principal executive offices)
|
|
(Zip
Code)
|
|
Registrant's
telephone number, including area code: (713)
335-4000
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 whether the Registrant is a large accelerated filer, an
accelerated filer or a non-accelerated filer. See definition of
“accelerated filer and large accelerated filer” in Rule 12b-2 of the Securities
Exchange Act of 1934. Large accelerated filer £
Accelerated filer ¨
Non-Accelerated filer
x
Indicate
by check mark whether the registrant is a shell company (as defined by Rule
12b-2 of the Securities Exchange Act of 1934). Yes ¨ No x
The
number of shares of the registrant's Common Stock, $.001 par value per share,
outstanding as of August 2, 2007 was 50,776,158.
Part
I –
|
Financial
Information
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3
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18
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22
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23
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Part
II–
|
Other
Information
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23
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27
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28
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29
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29
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29
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30
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31
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32
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Rule
13a-14(a) Certification executed by Charles F. Chambers
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Rule
13a-14(a) Certification executed by Michael J. Rosinski
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Section
1350 Certification
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|
Part
I. Financial Information
Item
1. Financial Statements
Consolidated
Balance Sheet
(In
thousands, except share amounts)
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Unaudited)
|
|
|
|
|
Assets
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
11,769
|
|
|
$ |
62,780
|
|
Accounts
receivable
|
|
|
37,900
|
|
|
|
36,408
|
|
Derivative
instruments
|
|
|
4,035
|
|
|
|
20,538
|
|
Prepaid
expenses
|
|
|
19,585
|
|
|
|
8,761
|
|
Other
current assets
|
|
|
3,800
|
|
|
|
2,965
|
|
Total
current assets
|
|
|
77,089
|
|
|
|
131,452
|
|
Oil
and natural gas properties, full cost method, of which $41.2 million
at
June 30, 2007 and $37.8 million at December 31, 2006 were excluded
from
amortization
|
|
|
1,399,194
|
|
|
|
1,223,337
|
|
Other
fixed assets
|
|
|
5,378
|
|
|
|
4,562
|
|
|
|
|
1,404,572
|
|
|
|
1,227,899
|
|
Accumulated
depreciation, depletion, and amortization
|
|
|
(210,712 |
) |
|
|
(145,289 |
) |
Total
property and equipment, net
|
|
|
1,193,860
|
|
|
|
1,082,610
|
|
Deferred
loan fees
|
|
|
2,785
|
|
|
|
3,375
|
|
Other
assets
|
|
|
1,094
|
|
|
|
1,968
|
|
Total
other assets
|
|
|
3,879
|
|
|
|
5,343
|
|
Total
assets
|
|
$ |
1,274,828
|
|
|
$ |
1,219,405
|
|
|
|
|
|
|
|
|
|
|
Liabilities
and Stockholders' Equity
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
30,385
|
|
|
$ |
23,040
|
|
Accrued
liabilities
|
|
|
51,470
|
|
|
|
43,099
|
|
Royalties
payable
|
|
|
12,272
|
|
|
|
9,010
|
|
Prepayment
on gas sales
|
|
|
22,488
|
|
|
|
17,868
|
|
Deferred
income taxes
|
|
|
1,521
|
|
|
|
7,743
|
|
Total
current liabilities
|
|
|
118,136
|
|
|
|
100,760
|
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
|
Derivative
instruments
|
|
|
17,905
|
|
|
|
11,014
|
|
Long-term
debt
|
|
|
240,000
|
|
|
|
240,000
|
|
Asset
retirement obligation
|
|
|
11,989
|
|
|
|
10,253
|
|
Deferred
income taxes
|
|
|
48,744
|
|
|
|
35,089
|
|
Total
liabilities
|
|
|
436,774
|
|
|
|
397,116
|
|
Commitments
and contingencies (Note 8)
|
|
|
|
|
|
|
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|
Stockholders'
equity:
|
|
|
|
|
|
|
|
|
Common
stock, $0.001 par value; authorized 150,000,000 shares; issued 50,466,973
shares and 50,405,794 shares at June 30, 2007 and December 31, 2006,
respectively
|
|
|
50
|
|
|
|
50
|
|
Additional
paid-in capital
|
|
|
759,090
|
|
|
|
755,343
|
|
Treasury
stock, at cost; 91,217 and 85,788 shares at June 30, 2007 and December
31,
2006, respectively
|
|
|
(1,675 |
) |
|
|
(1,562 |
) |
Accumulated
other comprehensive (loss) income
|
|
|
(8,636 |
) |
|
|
6,315
|
|
Retained
earnings
|
|
|
89,225
|
|
|
|
62,143
|
|
Total
stockholders' equity
|
|
|
838,054
|
|
|
|
822,289
|
|
Total
liabilities and stockholders' equity
|
|
$ |
1,274,828
|
|
|
$ |
1,219,405
|
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Operations
(In
thousands, except per share amounts)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales
|
|
$ |
77,436
|
|
|
$ |
53,682
|
|
|
$ |
146,597
|
|
|
$ |
110,417
|
|
Oil
sales
|
|
|
9,438
|
|
|
|
9,699
|
|
|
|
16,073
|
|
|
|
17,508
|
|
Total
revenues
|
|
|
86,874
|
|
|
|
63,381
|
|
|
|
162,670
|
|
|
|
127,925
|
|
Operating
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expense
|
|
|
12,566
|
|
|
|
8,323
|
|
|
|
21,362
|
|
|
|
17,881
|
|
Depreciation,
depletion, and amortization
|
|
|
36,342
|
|
|
|
25,601
|
|
|
|
66,893
|
|
|
|
49,668
|
|
Treating
and transportation
|
|
|
882
|
|
|
|
831
|
|
|
|
1,645
|
|
|
|
1,726
|
|
Marketing
fees
|
|
|
669
|
|
|
|
484
|
|
|
|
1,332
|
|
|
|
1,108
|
|
Production
taxes
|
|
|
1,200
|
|
|
|
1,626
|
|
|
|
2,185
|
|
|
|
3,323
|
|
General
and administrative costs
|
|
|
9,898
|
|
|
|
7,078
|
|
|
|
17,967
|
|
|
|
16,329
|
|
Total
operating costs and expenses
|
|
|
61,557
|
|
|
|
43,943
|
|
|
|
111,384
|
|
|
|
90,035
|
|
Operating
income
|
|
|
25,317
|
|
|
|
19,438
|
|
|
|
51,286
|
|
|
|
37,890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
(income) expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense, net of interest capitalized
|
|
|
4,680
|
|
|
|
4,371
|
|
|
|
9,050
|
|
|
|
8,503
|
|
Interest
income
|
|
|
(257 |
) |
|
|
(1,115 |
) |
|
|
(1,229 |
) |
|
|
(2,252 |
) |
Other
(income) expense, net
|
|
|
(182 |
) |
|
|
152
|
|
|
|
(182 |
) |
|
|
177
|
|
Total
other expense
|
|
|
4,241
|
|
|
|
3,408
|
|
|
|
7,639
|
|
|
|
6,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before provision for income taxes
|
|
|
21,076
|
|
|
|
16,030
|
|
|
|
43,647
|
|
|
|
31,462
|
|
Provision
for income taxes
|
|
|
7,985
|
|
|
|
6,066
|
|
|
|
16,565
|
|
|
|
11,972
|
|
Net
income
|
|
$ |
13,091
|
|
|
$ |
9,964
|
|
|
$ |
27,082
|
|
|
$ |
19,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.26
|
|
|
$ |
0.20
|
|
|
$ |
0.54
|
|
|
$ |
0.39
|
|
Diluted
|
|
$ |
0.26
|
|
|
$ |
0.20
|
|
|
$ |
0.54
|
|
|
$ |
0.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
50,354
|
|
|
|
50,229
|
|
|
|
50,340
|
|
|
|
50,175
|
|
Diluted
|
|
|
50,625
|
|
|
|
50,370
|
|
|
|
50,565
|
|
|
|
50,361
|
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Cash Flows
(In
thousands)
(Unaudited)
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
Net
income
|
|
$ |
27,082
|
|
|
$ |
19,490
|
|
Adjustments
to reconcile net income to net cash from operating
activities
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
66,893
|
|
|
|
49,668
|
|
Deferred
income taxes
|
|
|
16,479
|
|
|
|
11,723
|
|
Amortization
of deferred loan fees recorded as interest expense
|
|
|
590
|
|
|
|
590
|
|
Income
from unconsolidated investments
|
|
|
(85 |
) |
|
|
(112 |
) |
Stock
compensation expense
|
|
|
3,176
|
|
|
|
3,322
|
|
Change
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(1,492 |
) |
|
|
15,121
|
|
Income
taxes receivable
|
|
|
-
|
|
|
|
6,000
|
|
Other
current assets
|
|
|
(11,659 |
) |
|
|
(2,624 |
) |
Other
assets
|
|
|
331 |
|
|
|
934 |
|
Accounts
payable
|
|
|
7,345
|
|
|
|
3,411
|
|
Accrued
liabilities
|
|
|
(2,247 |
) |
|
|
(5,385 |
) |
Royalties
payable
|
|
|
7,882
|
|
|
|
(8,707 |
) |
Net
cash provided by operating activities
|
|
|
114,295
|
|
|
|
93,431
|
|
Cash
flows from investing activities
|
|
|
|
|
|
|
|
|
Acquisition
of oil and gas properties
|
|
|
(38,656 |
) |
|
|
(11,580 |
) |
Purchases
of property and equipment
|
|
|
(128,139 |
) |
|
|
(87,983 |
) |
Disposals
of property and equipment
|
|
|
1,005
|
|
|
|
36
|
|
Deposits
|
|
|
25
|
|
|
|
25
|
|
Other
|
|
|
1
|
|
|
|
(14 |
) |
Net
cash used in investing activities
|
|
|
(165,764 |
) |
|
|
(99,516 |
) |
Cash
flows from financing activities
|
|
|
|
|
|
|
|
|
Equity
offering transaction fees
|
|
|
-
|
|
|
|
268
|
|
Proceeds
from issuances of common stock
|
|
|
571
|
|
|
|
296
|
|
Stock-based
compensation excess tax benefit
|
|
|
-
|
|
|
|
249
|
|
Purchases
of treasury stock
|
|
|
(113 |
) |
|
|
(1,246 |
) |
Net
cash provided by (used in) financing activities
|
|
|
458
|
|
|
|
(433 |
) |
|
|
|
|
|
|
|
|
|
Net
decrease in cash
|
|
|
(51,011 |
) |
|
|
(6,518 |
) |
Cash
and cash equivalents, beginning of period
|
|
|
62,780
|
|
|
|
99,724
|
|
Cash
and cash equivalents, end of period
|
|
$ |
11,769
|
|
|
$ |
93,206
|
|
|
|
|
|
|
|
|
|
|
Supplemental
non-cash disclosures:
|
|
|
|
|
|
|
|
|
Capital
expenditures included in accrued liabilities
|
|
$ |
6,020
|
|
|
$ |
2,281
|
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Notes
to Consolidated Financial Statements (unaudited)
(1)
|
Organization
and Operations of the
Company
|
Nature
of Operations. Rosetta Resources Inc. (together with
its consolidated subsidiaries, the “Company”) was formed in June 2005 to acquire
Calpine Natural Gas L.P., the domestic oil and natural gas business formerly
owned by Calpine Corporation and affiliates (“Calpine”). The Company acquired
Calpine Natural Gas L.P. in July 2005 (hereinafter, the “Acquisition”) and
together with all subsequently acquired oil and natural gas properties is
engaged in oil and natural gas exploration, development, production and
acquisition activities in the United States. The Company’s main operations are
primarily concentrated in the Sacramento Basin of California, the Lobo and
Perdido Trends in South Texas, the State Waters of Texas, the Gulf of Mexico
and
the Rocky Mountains.
These
interim financial statements have not been audited. However, in the
opinion of management, all adjustments, consisting of only normal recurring
adjustments, necessary for a fair presentation of the financial statements
have
been included. Results of operations for interim periods are not
necessarily indicative of the results of operations that may be expected for
the
entire year. In addition, these financial statements have been
prepared in accordance with the instructions to Form 10-Q and, therefore, do
not
include all disclosures required for financial statements prepared in conformity
with accounting principles generally accepted in the United States of
America. These financial statements and notes should be read in
conjunction with the Company’s audited Consolidated/Combined Financial
Statements and the notes thereto included in the Company’s Annual Report on Form
10-K for the year ended December 31, 2006.
Certain
reclassifications of prior year balances have been made to conform such amounts
to corresponding 2007 classifications. These reclassifications have
no impact on net income.
(2)
|
Summary
of Significant Accounting
Policies
|
The
Company has provided a discussion of significant accounting policies, estimates
and judgments in its Annual Report on Form 10-K for the year ended December
31,
2006.
Principles
of Consolidation. The accompanying consolidated financial
statements as of June 30, 2007 and December 31, 2006 and for the three and
six
months ended June 30, 2007 and 2006 contain the accounts of Rosetta Resources
Inc. and its majority owned subsidiaries after eliminating all significant
intercompany balances and transactions.
Recent
Accounting Developments
The
Fair Value Option for Financial Assets and Financial Liabilities. In
February 2007, the Financial Accounting Standards Board (“FASB”) issued
Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value
Option For Financial Assets and Financial Liabilities - Including an Amendment
of FASB Statement No. 115” (“SFAS No. 159”), which permits an entity to choose
to measure certain financial assets and liabilities at fair value. SFAS No.
159
also revises provisions of SFAS No. 115 that apply to available-for-sale and
trading securities. This statement is effective for fiscal years beginning
after
November 15, 2007. The Company is currently evaluating the potential impact
of this standard.
Fair
Value Measurements. In September 2006, the FASB issued SFAS No.
157,“Fair Value Measurements” (“SFAS No. 157”), which addresses how
companies should measure fair value when companies are required to use a fair
value measure for recognition or disclosure purposes under generally accepted
accounting principles (“GAAP”). As a result of SFAS No. 157, there is now a
common definition of fair value to be used throughout GAAP. SFAS No. 157 is
effective for financial statements issued for fiscal years beginning after
November 15, 2007, and interim periods within those years. The Company does
not
expect the adoption of this standard to have a material impact on the Company’s
consolidated financial position, results of operations or cash
flows.
Accounting
for Uncertainty in Income Taxes. In June 2006, the FASB issued FASB
Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an
interpretation of FASB Statement No. 109” (“FIN
48”). This interpretation addresses the determination of whether tax
benefits claimed or expected to be claimed on a tax return should be recorded
in
the financial statements. Under FIN 48, the Company may recognize the tax
benefit from an uncertain tax position only if it is more likely than not that
the tax position will be sustained on examination by the taxing authorities,
based on the technical merits of the position. The tax benefits recognized
in
the financial statements from such a position should be measured based on the
largest benefit that has a greater than fifty percent likelihood of being
realized upon ultimate settlement. FIN 48 also provides guidance on
derecognition, classification, interest and penalties on income taxes,
accounting in interim periods and requires increased disclosures. The Company
adopted the provisions of FIN 48 on January 1, 2007. As a result of the
implementation of FIN 48, the Company did not have any unrecognized tax benefits
and there was no effect on our financial condition or results of operations
as a
result of implementing FIN 48. For additional information see Note 7 to the
Consolidated Financial Statements.
(3)
|
Property,
Plant and Equipment
|
The
Company’s total property, plant and equipment consists of the
following:
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$ |
1,342,654
|
|
|
$ |
1,170,223
|
|
Unproved
properties
|
|
|
32,796
|
|
|
|
35,178
|
|
Gas
gathering systems and compressor stations
|
|
|
23,744
|
|
|
|
17,936
|
|
Other
|
|
|
5,378
|
|
|
|
4,562
|
|
Total
|
|
|
1,404,572
|
|
|
|
1,227,899
|
|
Less:
Accumulated depreciation, depletion, and amortization
|
|
|
(210,712 |
) |
|
|
(145,289 |
) |
|
|
$ |
1,193,860
|
|
|
$ |
1,082,610
|
|
The
Company capitalizes internal costs directly identified with acquisition,
exploration and development activities. The Company capitalized $1.1 million
and
$2.4 million of internal costs for the three and six months ended June 30,
2007,
respectively, and $0.9 million and $1.7 million for the three and six months
ended June 30, 2006, respectively.
Included
in the Company’s oil and gas properties are asset retirement obligations of
$15.3 million and $9.6 million as of June 30, 2007 and December 31, 2006,
respectively.
Oil
and
gas properties include costs of $41.2 million and $37.8 million at June 30,
2007
and December 31, 2006, respectively, which were excluded from capitalized costs
being amortized. These amounts primarily represent unproved
properties and unevaluated exploration projects in which the Company owns a
direct interest. The increase in costs excluded during 2007 is
primarily related to the increase in exploration activities in the Offshore
and
Texas State Waters regions.
The
Company’s ceiling test computation was calculated using hedge adjusted market
prices at June 30, 2007, which were based on a Henry Hub price of $6.80 per
MMBtu and a West Texas Intermediate oil price of $69.63 per Bbl (adjusted for
basis and quality differentials). Cash flow hedges of natural gas production
in
place at June 30, 2007 increased the calculated ceiling value by approximately
$21.7 million (net of tax). There was no write-down recorded at June 30, 2007.
Due to the volatility of commodity prices, should natural gas prices decline
in
the future, it is possible that a write-down could occur.
In
April
2007, the Company acquired properties located in the Sacramento Basin from
Output Exploration, LLC and OPEX Energy, LLC at a total purchase price of $38.7
million, subject to final adjustments.
(4)
|
Commodity
Hedging Contracts and Other
Derivatives
|
In
the
second quarter of 2007, the Company entered into additional 5,000 MMBtu per
day
of financial fixed price swaps with an average underlying price of $8.08 per
MMBtu covering a portion of the Company’s 2008 production. The following
financial fixed price swaps were outstanding with associated notional volumes
and average underlying prices that represent hedged prices of commodities at
various market locations at June 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
of
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Total
of
|
|
|
Average
|
|
|
Proved
|
|
|
Fair
Market
|
|
|
|
|
|
Daily
|
|
|
Notional
|
|
|
Underlying
|
|
|
Natural
Gas
|
|
|
Value
|
|
Settlement
|
Derivative
|
Hedge
|
|
Volume
|
|
|
Volume
|
|
|
Prices
|
|
|
Production
|
|
|
Gain/(Loss)
|
|
Period
|
Instrument
|
Strategy
|
|
MMBtu
|
|
|
MMBtu
|
|
|
MMBtu
|
|
|
Hedged
(1)
|
|
|
(In
thousands)
|
|
2007
|
Swap
|
Cash
flow
|
|
55,316
|
|
|
|
10,178,200
|
|
|
7.80
|
|
|
45%
|
|
|
|
7,231
|
|
2008
|
Swap
|
Cash
flow
|
|
54,909
|
|
|
|
20,096,616
|
|
|
7.66
|
|
|
48%
|
|
|
|
(9,898 |
) |
2009
|
Swap
|
Cash
flow
|
|
26,141
|
|
|
|
9,541,465
|
|
|
6.99
|
|
|
26%
|
|
|
|
(12,221 |
) |
|
|
|
|
|
|
|
|
|
39,816,281
|
|
|
|
|
|
|
|
|
|
|
$ |
(14,888 |
) |
(1)
Estimated based on net gas reserves presented in the December 31, 2006
Netherland, Sewell, & Associates, Inc. reserve report.
The
following costless collar transactions were outstanding with associated notional
volumes and contracted ceiling and floor prices that represent hedge prices
at
various market locations at June 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
of
|
|
|
Fair
|
|
|
|
|
|
Notional
|
|
|
Total
of
|
|
|
Average
|
|
|
Average
|
|
|
Proved
|
|
|
Market
|
|
|
|
|
|
Daily
|
|
|
Notional
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Natural
Gas
|
|
|
Value
|
|
Settlement
|
Derivative
|
Hedge
|
|
Volume
|
|
|
Volume
|
|
|
Price
|
|
|
Price
|
|
|
Production
|
|
|
Gain/(Loss)
|
|
Period
|
Instrument
|
Strategy
|
|
MMBtu
|
|
|
MMBtu
|
|
|
MMBtu
|
|
|
MMBtu
|
|
|
Hedged
(1)
|
|
|
(In
thousands)
|
|
2007
|
Costless
Collar
|
Cash
flow
|
|
10,000
|
|
|
|
1,840,000
|
|
|
$ |
7.19
|
|
|
$ |
10.03
|
|
|
8%
|
|
|
$ |
1,026
|
|
|
|
|
|
|
|
|
|
|
1,840,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,026
|
|
(1)
Estimated based on net gas reserves presented in the December 31, 2006
Netherland, Sewell, & Associates, Inc. reserve report.
The
Company’s current cash flow hedge positions are with counterparties who are
lenders in the Company’s credit facilities. This eliminates the need
for independent collateral postings with respect to any margin obligation
resulting from a negative change in fair market value of the derivative
contracts in connection with the Company’s hedge related credit
obligations. As of June 30, 2007, the Company made no deposits for
collateral.
The
following table sets forth the results of third party hedge transactions for
the
respective period for the Consolidated Statement of Operations:
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
Natural
Gas
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Quantity
settled (MMBtu)
|
|
|
5,946,800
|
|
|
|
5,005,000
|
|
|
|
11,471,300
|
|
|
|
9,955,000
|
|
Increase
in natural gas sales revenue (In thousands)
|
|
$ |
2,433
|
|
|
$ |
9,127
|
|
|
$ |
7,477
|
|
|
$ |
10,690
|
|
The
Company expects to reclassify losses of $2.5 million based on market pricing
as
of June 30, 2007 to earnings from the balance in accumulated other comprehensive
income (loss) on the Consolidated Balance Sheet during the next twelve
months.
At
June
30, 2007, the Company had derivative assets of $4.0 million on the
Consolidated Balance Sheet. The Company also had derivative
liabilities of $17.9 million which was included in long-term liabilities on
the
Consolidated Balance Sheet at June 30, 2007. The derivative
instrument assets and liabilities relate to commodity hedges that represent
the
difference between hedged prices and market prices on hedged volumes of the
commodities as of June 30, 2007.
Gains
and
losses related to ineffectiveness and derivative instruments not designated
as
hedging instruments are included in other income (expense) and were immaterial
for the three and six months ended June 30, 2007 and 2006.
(5)
|
Asset
Retirement Obligation
|
Activity
related to the Company’s asset retirement obligation (“ARO”) is as
follows:
|
|
Six
Months Ended
|
|
|
|
June
30, 2007
|
|
|
|
(In
thousands)
|
|
ARO
as of January 1, 2007
|
|
$ |
10,689
|
|
Revision
of previous estimates
|
|
|
4,697
|
|
Liabilities
incurred during period
|
|
|
1,031
|
|
Accretion
expense
|
|
|
605
|
|
ARO
as of June 30, 2007
|
|
$ |
17,022
|
|
Of
the
total ARO, approximately $5.0 million is classified as a current liability
included in accrued liabilities on the Consolidated Balance Sheet at June 30,
2007.
The
Company’s credit facilities consist of a four-year senior secured revolving line
of credit (“Revolver”) of up to $400.0 million with a borrowing base which was
adjusted in May 2007 to $350.0 million and a five-year $75.0 million second
lien
term loan.
On
June
30, 2007, the Company had outstanding borrowings and letters of credit of $240.0
million and $1.0 million, respectively. Net borrowing availability
under the Revolver was $184.0 million at June 30, 2007.
The Company was in compliance with all covenants at June 30, 2007.
All
amounts drawn under the Revolver are due and payable on July 7,
2009. The principal balance associated with the second lien term loan
is due and payable on July 7, 2010.
The
Company did not have any unrecognized tax benefits and there was no effect
on
the Company’s financial condition, results of operations or cash flows as a
result of implementing FIN 48. The amount of unrecognized tax benefits did
not
materially change as of June 30, 2007.
Estimated
interest and penalties related to potential underpayment on any unrecognized
tax
benefits are classified as a component of tax expense in the Consolidated
Statement of Operations. As of the date of adoption of FIN 48, the Company
did
not have any accrued interest or penalties associated with any unrecognized
tax
benefits, nor was any interest expense recognized during the
quarter.
The
Company’s effective tax rate differs from the federal statutory rate primarily
due to state taxes, tax credits and other permanent differences. The
Company does not anticipate that total unrecognized tax benefits will
significantly change due to the settlement of audits and the expiration of
statute of limitations prior to June 30, 2008.
(8)
|
Commitment
and Contingencies
|
The
Company is party to various oil and natural gas litigation matters arising
out
of the normal course of business. The ultimate outcome of each of these matters
cannot be absolutely determined, and the liability the Company may ultimately
incur with respect to any one of these matters in the event of a negative
outcome may be in excess of amounts currently accrued for with respect to such
matters. Management does not believe any such matters will have a material
adverse effect on the Company’s financial position, results of operations or
cash flows.
Calpine
Bankruptcy
On
December 20, 2005, Calpine and certain of its subsidiaries filed for
protection under the federal bankruptcy laws in the United States Bankruptcy
Court of the Southern District of New York (the “Bankruptcy
Court”).
Calpine’s
Lawsuit Against Rosetta
On
June
29, 2007, Calpine filed an adversary proceeding against the Company in the
Bankruptcy Court. The complaint alleges that the purchase by the
Company of the domestic oil and natural gas assets formally owned by Calpine
(the “Assets”) in July 2005 for $1.05 billion, prior to Calpine filing for
bankruptcy, was completed when Calpine was insolvent and was for less than
a
reasonably equivalent value. Calpine is seeking (i) monetary damages
for the alleged shortfall in value it received for these assets which it
estimates to be approximately $400 million dollars, plus interest, or (ii)
in
the alternative, return of the Assets from the Company. The Company
believes that these allegations are wholly baseless, intends to vigorously
defend against all claims made by Calpine and is further considering additional
steps it may take to fully protect the Company's interests. The
Company continues to believe that it is unlikely that this challenge by the
Calpine debtors to the fairness of the Acquisition will be successful upon
ultimate disposition after appeals, if any. The deadline for the
Company to answer or file its responsive pleading is September 10, 2007, and
the
Company has advised the Bankruptcy Court that it intends to file a motion to
dismiss the complaint on or before the answer date. Calpine has requested a
trial date in December 2007, but at the present time, no trial date has
been set by the Bankruptcy Court.
Remaining
Issues with Respect to the Acquisition
Separate
from the Calpine lawsuit, Calpine has taken the position that the Purchase
and
Sale Agreement and interrelated agreements concurrently executed therewith,
dated July 7, 2005, by and among Calpine, the Company, and various other
signatories thereto (collectively, the “Purchase Agreement”) are “executory
contracts”, which Calpine may assume or reject. Following the July 7,
2005 closing of the Acquisition and as of the date of Calpine’s bankruptcy
filing, there were open issues regarding legal title to certain properties
included in the Purchase Agreement. On June 20, 2007, Calpine filed
with the Bankruptcy Court its proposed Plan of Reorganization under
Chapter 11 of the Bankruptcy Code, together with the accompanying
Disclosure Statement, in which Calpine revealed it had not yet made a decision
as to whether to assume or reject its remaining duties and obligations under
the
Purchase Agreement. If the Court were to determine that the Purchase
Agreement is an executory contract, the various agreements entered into as
part
of the transaction constitute a single contract for purposes of assumption
or
rejection under the Bankruptcy Code, and the Company contends that Calpine
cannot choose to assume certain of the agreements and to reject
others. This issue may be contested by Calpine. If the
Purchase Agreement is held to be executory, the deadline by when Calpine must
exercise its decision to assume or reject the Purchase Agreement and the further
duties and obligations required therein is the date on which Calpine’s Plan of
Reorganization is confirmed.
Open
Issues Regarding Legal Title to Certain Properties
Under
the
Purchase Agreement, Calpine is required to resolve the open issues regarding
legal title to certain properties. At the closing of the Acquisition
on July 7, 2005, the Company retained approximately $75 million of the
purchase price in respect to Non-Consent Properties identified by Calpine as
requiring third-party consents or waivers of preferential rights to purchase
that were not received by the parties before closing ("Non-Consent
Properties"). Those Non-Consent Properties were therefore not
included in the conveyances delivered at the closing. Subsequent
analysis determined that a significant portion of the Non-Consent Properties
did
not require consents or waivers. For that portion of the Non-Consent
Properties for which third-party consents were in fact required and for which
either the Company or Calpine obtained the required consents or waivers, as
well
as for all Non-Consent Properties that did not require consents or waivers,
the
Company contends Calpine was and is obligated to have transferred to it the
record title, free of any mortgages and other liens.
The
approximate allocated value under the Purchase Agreement for the portion of
the
Non-Consent Properties subject to a third-party’s preferential right to purchase
is $7.4 million. The Company has retained $7.1 million of the
purchase price under the Purchase Agreement for the Non-Consent Properties
subject to the third-party preferential right, and, in addition, a post-closing
adjustment is required to credit the Company for approximately $0.3 million
for
a property which was transferred to it but, if necessary, will be transferred
to
the appropriate third party under its exercised preferential purchase right
upon
Calpine’s performance of its obligations under the Purchase
Agreement.
The
Company believes all conditions precedent for its receipt of record title,
free
of any mortgages or other liens, for substantially all of the Non-Consent
Properties (excluding that portion of these properties subject to the
third-party preferential right) were satisfied earlier, and certainly no later,
than December 15, 2005, when the Company tendered once again the amounts
necessary to conclude the settlement of the Non-Consent Properties.
The
Company believes it is the equitable owner of each of the Non-Consent Properties
for which Calpine was and is obligated to have transferred the record title
and
that such properties are not part of Calpine’s bankruptcy
estate. Upon the Company’s receipt from Calpine of record title, free
of any mortgages or other liens, to these Non-Consent Properties and further
assurances required to eliminate any open issues on title to the remaining
properties discussed below, the Company is prepared to pay Calpine approximately
$68 million, subject to appropriate adjustment, if any. The Company’s
statement of operations for the six months ended June 30, 2007, the year ended
December 31, 2006 and six months ended December 31, 2005, does not include
any
net revenues or production from any of the Non-Consent Properties, including
those properties subject to preferential rights.
If
Calpine does not provide the Company with record title, free of any mortgages
for all of these properties and other liens, to any of the Non-Consent
Properties (excluding that portion of these properties subject to a validly
exercised third party’s preferential right to purchase), the Company will have a
total of approximately $68 million available to them for general corporate
purposes, including for the purpose of acquiring additional
properties. The Company also has approximately $7.1 million,
previously withheld for that portion of the Non-Consent Properties subject
to a
third party’s preferential right to purchase, which will also be available for
general corporate purposes, including for the purpose of acquiring additional
properties should that third party properly exercise the preferential
rights.
In
addition, as to certain of the other oil and natural gas properties the Company
purchased from Calpine in the Acquisition and for which payment was made on
July
7, 2005, the Company is seeking additional documentation from Calpine to
eliminate any open issues in the Company’s title or resolve any issues as to the
clarity of the Company’s ownership. Requests for additional documentation are
customary in connection with transactions similar to the Acquisition. In the
Acquisition, certain of these properties require ministerial governmental action
approving the Company as qualified assignee and operator, which is typically
required even though in most cases Calpine has already conveyed the properties
to the Company free and clear of mortgages and liens by Calpine’s creditors. As
to certain other properties, the documentation delivered by Calpine at closing
under the Purchase Agreement was incomplete. The Company remains hopeful that
Calpine will work cooperatively with the Company to secure these ministerial
governmental approvals and to accomplish the curative corrections for all of
these properties. In addition, as to all properties acquired by the Company
in
the Acquisition, Calpine contractually agreed to provide the Company with such
further assurances as the Company may reasonably request. Nevertheless, as
a
result of Calpine’s bankruptcy filing, it remains uncertain as to whether
Calpine will respond cooperatively. If Calpine does not fulfill its contractual
obligations (as a result of rejection of the Purchase Agreement or otherwise)
and does not complete the documentation necessary to resolve these issues,
the
Company will pursue all available remedies, including but not limited to a
declaratory judgment to enforce the Company’s rights and actions to quiet title.
After pursuing these matters, if the Company experiences a loss of ownership
with respect to these properties without receiving adequate consideration for
any resulting loss to the Company, an outcome the Company’s management considers
to be unlikely upon ultimate disposition, including appeals, if any, then
the Company could experience losses which could have a material adverse effect
on the Company’s financial condition, statement of operations and cash
flows.
Sale
of Natural Gas to Calpine
In
addition, the issues involving legal title to certain properties, the Company
executed, as part of the interrelated agreements that constitute the Purchase
Agreement, certain natural gas supply agreements with Calpine Energy Services,
L.P. (“CES”), which also filed for bankruptcy on December 20,
2005. During the period following Calpine’s filing for bankruptcy,
CES has continued to make the required deposits into the Company’s margin
account and to timely pay for natural gas production it purchases from the
Company’s subsidiaries under these various natural gas supply
agreements. Although Calpine has indicated in a supplement to its
recently proposed plan of reorganization that it intends to assume the CES
natural gas supply agreements with the Company, the Company disagrees that
Calpine may assume anything less than the entire Purchase Agreement and intends
to oppose any effort by Calpine to do less.
Calpine’s
Marketing of the Company’s Production
Additionally,
Calpine Producer Services, L.P. (“CPS”), which also filed for bankruptcy,
entered into a Marketing and Services Agreement (“MSA”) with the Company as part
of the interrelated agreements that constitute the Purchase
Agreement. Under the MSA, CPS provided marketing and sales of the
Company’s natural gas production to third-parties and charged the Company a
fee. The MSA, however, expired by its terms on June 30,
2007. Through a recently executed letter agreement, CPS and the
Company agreed to extend the MSA until September 30, 2007, subject to and
to enable the parties to negotiate and execute a New Marketing and Services
Agreement (“New MSA”). On August 3, 2007, as part of the Partial
Transfer and Release Agreement, discussed in greater detail below, the Company
and CPS concurrently executed the New MSA, which, if approved by the Bankruptcy
Court, will be effective as of July 1, 2007 and extend CPS’ obligation to
provide such services until June 30, 2009. The New MSA is subject to
earlier termination by the Company upon the occurrence of certain
events. In the interim, CPS is generally performing its obligations
under the MSA.
Events
Within Calpine’s Bankruptcy Case
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases that Calpine had previously
sold or agreed to sell to the Company in the Acquisition, to the extent those
leases constitute “unexpired leases of non-residential real property” and were
not fully transferred to the Company at the time of Calpine’s filing for
bankruptcy. The oil and gas leases identified in Calpine’s motion
are, in large part, those properties with open issues in regards to their legal
title in which Calpine contends it may possess some legal
interest. According to this motion, Calpine filed it in order to
avoid the automatic forfeiture of any interest it may have in these leases
by
operation of a bankruptcy code deadline. Calpine’s motion did not
request that the Bankruptcy Court determine whether these properties belong
to
the Company or Calpine, but the Company understands it was meant to allow
Calpine to preserve and avoid forfeiture under the Bankruptcy Code of whatever
interest Calpine may possess, if any, in these oil and natural gas
leases. The Company disputes Calpine’s contention that it may have an
interest in any significant portion of these oil and natural gas leases and
intends to take the necessary steps to protect all of the Company’s rights and
interest in and to the leases.
On
July
7, 2006, the Company filed an objection in response to Calpine’s motion, wherein
the Company asserted that oil and natural gas leases constitute interests in
real property that are not subject to “assumption” under the Bankruptcy Code. In
the objection, the Company also requested that (a) the Bankruptcy Court
eliminate from the order certain Federal offshore leases from the Calpine motion
because these properties were fully conveyed to the Company in July 2005, and
the Minerals Management Service has subsequently recognized the Company as
owner
and operator of all but three of these properties, and (b) any order entered
by
the Bankruptcy Court be without prejudice to, and fully preserve the Company’s
rights, claims and legal arguments regarding the characterization and ultimate
disposition of the remaining described oil and natural gas
properties. In the Company’s objection, the Company also urged the
Bankruptcy Court to require the parties to promptly address and resolve any
remaining issues under the pre-bankruptcy definitive agreements with Calpine
and
proposed to the Bankruptcy Court that the parties could seek mediation to
complete the following:
|
·
|
Calpine’s
conveyance of the Non-Consent Properties to the
Company;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which the Company
has already paid Calpine; and
|
|
·
|
Resolution
of the final amounts the Company is to pay Calpine, which the Company
had
at that time concluded was approximately $79 million, consisting of
roughly $68 million for the Non-Consent Properties and approximately
$11
million in other true-up payment obligations. The Company is currently
updating these calculations.
|
At
a
hearing held on July 12, 2006, the Bankruptcy Court took the following
steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion those
leases issued by the United States (and managed by the Minerals Management
Service of the United States Department of Interior) (the “MMS Oil and Gas
Leases”) and the State of California (and managed by the California State
Lands Commission) (the “CSLC Leases”). Calpine and both the Department of
Justice and the State of California agreed to an extension of the
existing
deadline to November 15, 2006 to assume or reject the MMS Oil and
Gas
Leases and CSLC Leases under Section 365 of the Bankruptcy Code,
to the
extent the MMS Oil and Gas Leases and CSLC Leases are leases subject
to
Section 365. The effect of these actions was to render the objection
of
the Company inapplicable at that time;
and
|
|
·
|
The
Bankruptcy Court also encouraged Calpine and the Company to arrive
at a
business solution to all remaining issues including approximately
$68
million payable to Calpine for conveyance of the Non-Consent
Properties.
|
On
August
1, 2006, the Company filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts as well as unliquidated damages in amounts that
can not presently be determined. In the event that Calpine elects to
reject the Purchase Agreement or otherwise refuses to perform its remaining
obligations therein, the Company anticipates it will be allowed to amend its
proofs of claim to assert any additional damages it suffers as a result of
the
ultimate impact of Calpine’s refusal or failure to perform under the Purchase
Agreement. In the bankruptcy, Calpine may elect to contest or dispute
the amount of damages the Company seeks in its proofs of claim. The
Company will assert all right to offset any of its damages against any funds
it
possesses that may be owed to Calpine. Until the allowed amount of
the Company’s claims are finally established and the Bankruptcy Court issues its
rulings with respect to Calpine’s plan confirmation, the Company can not predict
what amounts it may recover from the Calpine bankruptcy should Calpine reject
or
refuse to perform under the Purchase Agreement.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases and the
CSLC Leases respectively, these parties have further extended this deadline
by
stipulation. The deadline was first extended to January 31, 2007, was further
extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April
30, 2007 with respect to the CSLC Leases, was further extended again to
September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15,
2007
and more recently, October 31, 2007 with respect to the CSLC Leases. The
Bankruptcy Court entered Orders related to the MMS Oil and Gas Leases and CSLC
Leases which included appropriate language that the Company negotiated with
Calpine for the Company’s protection in this regard.
On
June
20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure
Statement with the Bankruptcy Court. Calpine has indicated in its
filings with the Court that it believes substantial payments in the form of
cash
or newly issued stock, or some combination thereof, will be made to unsecured
creditors under its proposed Plan of Reorganization that could conceivably
result in payment of 100% of allowed claims and possibly provide some payment
to
its equity holders. The amounts any plan ultimately distributes to
its various claimants of the Calpine estate, including unsecured creditors,
will
depend on the Court’s conclusion with regard to Calpine’s enterprise value and
the amount of allowed claims that remain following the objection
process.
On
June
29, 2007, Calpine filed a notice with the Bankruptcy Court that it was in
discussions with unnamed third parties regarding alternative plans of
reorganization that might yield guaranteed payments to equity holders, thus
paying all unsecured creditors, and requested an extension of time to allow
such
discussions to continue. Although the deadlines with respect to
confirming any plan would be pushed back by approximately one month, Calpine
stated in its notice that its beneficial financing terms required it emerge
from
bankruptcy by January 31, 2008.
On
August
3, 2007, the Company and Calpine executed a Partial Transfer and Release
Agreement (“PTRA”), subject to Bankruptcy Court approval, resolving certain open
issues without prejudice to Calpine’s avoidance action and, if the Court
concludes the Purchase Agreement is executory, Calpine’s ability to assume or
reject the Purchase Agreement. The principle terms are as
follows:
|
·
|
The
Company will extend its existing natural gas marketing agreement
with
Calpine until June 30, 2009. This agreement is subject to
earlier termination right by the Company upon the occurrence of certain
events;
|
|
·
|
Calpine
will deliver to the Company documents that resolve title issues pertaining
to certain previously purchased oil and gas properties located in
the Gulf
of Mexico, California and Wyoming (“Properties”);
|
|
·
|
The
Company will assume all Calpine's rights and obligations for an audit
by
the California State Lands Commission on part of the Properties;
and
|
|
·
|
The
Company will assume all rights and obligations for the Properties,
including all plugging and abandonment
liabilities.
|
A
number
of the properties that, after the closing of the Acquisition, had open issues
in
regards to legal title will be resolved by the PTRA, if approved by the
Bankruptcy Court. Until a final order is received approving Calpine’s
entry into the PTRA, the possibility remains that the PTRA will not become
binding obligations of the parties.
As
a
result of Calpine’s bankruptcy, there remains the possibility that there will be
issues between the Company and Calpine that could amount to material
contingencies in relation to the litigation filed by Calpine against the Company
or the Purchase Agreement, including unasserted claims and assessments with
respect to (i) the still pending Purchase Agreement and the amounts that will
be
payable in connection therewith, (ii) whether or not Calpine and its affiliated
debtors will, in fact, perform their remaining obligations in connection with
the Purchase Agreement; and (iii) the ultimate disposition of the remaining
Non-Consent Properties (and related revenues).
Arbitration
between Calpine Corp./RROLP and Pogo Producing
Company
On
September 1, 2004, Calpine and Calpine Natural Gas L.P. sold their New Mexico
oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course
of that sale, Pogo made three title defect claims on properties sold by Calpine
(valued at approximately $2.7 million in the aggregate, subject to a $0.5
million deductible assuming no reconveyance) claiming that certain leases
subject to the sale had expired because of lack of production. Calpine had
undertaken without success to resolve this matter by obtaining ratifications
of
a majority of the questionable leases. Calpine filed for bankruptcy protection
before Pogo filed arbitration against it. Even though this is a retained
liability of Calpine, Calpine declined to accept the Company’s tender of defense
and indemnity when Pogo filed for arbitration against the
Company. The Company filed a motion to stay this arbitration under
the automatic stay provision of the Bankruptcy Code which motion was granted
by
the Bankruptcy Court on April 24, 2007 for a period of time of the earlier
of
fifteen months from the date of entry of the stay order or the effective date
of
a final order confirming Calpine’s plan of reorganization. This is a
retained liability of Calpine and it is too early for management to determine
whether or in what amount, if any, this matter will have on the
Company.
Environmental
Environmental
expenditures are expensed or capitalized, as appropriate, depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations, and that do not have future economic benefit, are
expensed. Liabilities related to future costs are recorded on an undiscounted
basis when environmental assessments and/or remediation activities are probable
and the cost can be reasonably estimated. The Company performed an environmental
remediation study for two sites in California and correspondingly, recorded
a
liability, which at June 30, 2007 and December 31, 2006 was $0.1 million. The
Company does not expect that the outcome of the environmental matters discussed
above will have a material adverse effect on the Company’s financial position,
results of operations or cash flows.
Participation
in a Regional Carbon Sequestration Partnership
The
Company has made preliminary preparations in connection with its participating
in the United States Department of Energy’s (“DOE”) Regional Carbon
Sequestration Partnership program (“WESTCARB”) with the California Energy
Commission and the University of California Lawrence Berkeley Laboratory. The
Company has been selected by the DOE for this project. Under WESTCARB, the
Company would be required to drill a carbon injection well, recondition an
idle
well for use as an observation well and provide WESTCARB with certain
proprietary well data and technical assistance related to the evaluation and
injection of carbon dioxide into a suitable natural gas reservoir in the
Sacramento Basin. The Company’s maximum contribution to WESTCARB is $1.0
million and will be limited to 20% of the total contributions to the project.
The Company will not have any obligation under the WESTCARB project until it
has
entered into an acceptable contract and the project has obtained proper and
necessary local, state and federal regulatory approvals, land use authorizations
and third party property rights. No accrual was recorded at June 30, 2007 or
December 31, 2006 as the study is still in the preliminary stage.
|
The
Company’s total comprehensive income (loss) is shown
below.
|
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Accumulated
other comprehensive (loss) income beginning of period
|
|
|
|
|
$ |
(16,979 |
) |
|
|
|
|
$ |
(19,615 |
) |
|
|
|
|
$ |
6,315
|
|
|
|
|
|
$ |
(50,731 |
) |
Net
income
|
|
|
13,091
|
|
|
|
|
|
|
|
9,964
|
|
|
|
|
|
|
|
27,082
|
|
|
|
|
|
|
|
19,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in fair value of derivative hedging instruments
|
|
|
8,570
|
|
|
|
|
|
|
|
21,648
|
|
|
|
|
|
|
|
(16,521 |
) |
|
|
|
|
|
|
73,398
|
|
|
|
|
|
Hedge
settlements reclassed to income
|
|
|
(2,433 |
) |
|
|
|
|
|
|
(9,127 |
) |
|
|
|
|
|
|
(7,477 |
) |
|
|
|
|
|
|
(10,690 |
) |
|
|
|
|
Tax
provision related to hedges
|
|
|
2,206
|
|
|
|
|
|
|
|
(4,758 |
) |
|
|
|
|
|
|
9,047
|
|
|
|
|
|
|
|
(23,829 |
) |
|
|
|
|
Total
other comprehensive income (loss)
|
|
|
8,343
|
|
|
|
8,343
|
|
|
|
7,763
|
|
|
|
7,763
|
|
|
|
(14,951 |
) |
|
|
(14,951 |
) |
|
|
38,879
|
|
|
|
38,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income
|
|
|
21,434
|
|
|
|
|
|
|
|
17,727
|
|
|
|
|
|
|
|
12,131
|
|
|
|
|
|
|
|
58,369
|
|
|
|
|
|
Accumulated
other comprehensive loss
|
|
|
|
|
|
$ |
(8,636 |
) |
|
|
|
|
|
$ |
(11,852 |
) |
|
|
|
|
|
$ |
(8,636 |
) |
|
|
|
|
|
$ |
(11,852 |
) |
Basic
earnings per share is computed by dividing income available to common
stockholders by the weighted average number of shares outstanding for the
period. Diluted earnings per share reflects the potential dilution
that could occur if contracts to issue common stock and related stock options
were exercised at the end of the period.
The
following is a calculation of basic and diluted weighted average shares
outstanding:
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Basic
weighted average number of shares outstanding
|
|
|
50,354
|
|
|
|
50,229
|
|
|
|
50,340
|
|
|
|
50,175
|
|
Dilution
effect of stock option and awards at the end of the period
|
|
|
271
|
|
|
|
141
|
|
|
|
225
|
|
|
|
186
|
|
Diluted
weighted average number of shares outstanding
|
|
|
50,625
|
|
|
|
50,370
|
|
|
|
50,565
|
|
|
|
50,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
awards and shares excluded from diluted earnings per share due to
anti-dilutive effect
|
|
|
268
|
|
|
|
206
|
|
|
|
407
|
|
|
|
154
|
|
(11)
|
Geographic
Area Information
|
The
Company has one reportable segment, oil and natural gas exploration and
production, as determined in accordance with SFAS No. 131, “Disclosure
About Segments of an Enterprise and Related Information”.
The
Company owns oil and natural gas interests in eight main geographic areas all
within the United States or its territorial waters. Geographic revenue and
property, plant and equipment information below are based on physical location
of the assets at the end of each period.
Oil and Natural Gas Revenue
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2007
(1)
|
|
|
2006
(1)
|
|
|
2007
(1)
|
|
|
2006
(1)
|
|
|
|
(In
thousands)
|
|
California
|
|
$ |
28,504
|
|
|
$ |
15,715
|
|
|
$ |
55,596
|
|
|
$ |
36,110
|
|
Rocky
Mountains
|
|
|
2,760
|
|
|
|
622
|
|
|
|
4,286
|
|
|
|
964
|
|
Mid-Continent
|
|
|
551
|
|
|
|
431
|
|
|
|
1,356
|
|
|
|
910
|
|
Gulf
of Mexico
|
|
|
10,908
|
|
|
|
6,394
|
|
|
|
16,381
|
|
|
|
15,921
|
|
Lobo
|
|
|
28,391
|
|
|
|
13,673
|
|
|
|
53,267
|
|
|
|
29,082
|
|
Perdido
|
|
|
7,570
|
|
|
|
6,962
|
|
|
|
13,338
|
|
|
|
16,784
|
|
State
Waters
|
|
|
838
|
|
|
|
2,142
|
|
|
|
1,647
|
|
|
|
5,289
|
|
Other
Onshore
|
|
|
4,919
|
|
|
|
8,315
|
|
|
|
9,322
|
|
|
|
12,175
|
|
|
|
$ |
84,441
|
|
|
$ |
54,254
|
|
|
$ |
155,193
|
|
|
$ |
117,235
|
|
|
(1)
|
Excludes
the effects of hedging of $2.4 million and $9.1 million for the three
months ended June 30, 2007 and 2006, respectively, and $7.5 million
and
$10.7 million for the six months ended June 30, 2007 and 2006,
respectively.
|
Oil
and Natural Gas Properties
|
|
June
30, 2007
|
|
|
December
31, 2006
|
|
|
|
(In
thousands)
|
|
California
|
|
$ |
497,077
|
|
|
$ |
435,167
|
|
Rocky
Mountains
|
|
|
58,441
|
|
|
|
44,455
|
|
Mid-Continent
|
|
|
14,149
|
|
|
|
9,584
|
|
Gulf
of Mexico
|
|
|
144,254
|
|
|
|
125,425
|
|
Lobo
|
|
|
467,500
|
|
|
|
426,348
|
|
Perdido
|
|
|
64,445
|
|
|
|
52,702
|
|
State
Waters
|
|
|
46,204
|
|
|
|
26,922
|
|
Other
Onshore
|
|
|
107,124
|
|
|
|
102,734
|
|
Other
|
|
|
5,378
|
|
|
|
4,562
|
|
|
|
$ |
1,404,572
|
|
|
$ |
1,227,899
|
|
In
July
2007, Chairman, President and Chief Executive Officer (“CEO”) B.A. Berilgen
resigned. The Company’s Executive Vice President, Charles F.
Chambers, is serving as acting President and CEO. D. Henry Houston,
chair of the Company's Audit Committee and current director, has been named
Chairman of the Board and will lead the Board in the search for a permanent
President and CEO. The Company has not filled the
vacancy on the Board caused by Mr. Berilgen’s
resignation.
CAUTIONARY NOTE
REGARDING FORWARD-LOOKING STATEMENTS
This
report includes various “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical fact included or incorporated by reference in this
report are forward-looking statements, including without limitation all
statements regarding future plans, business objectives, strategies, expected
future financial position or performance, expected future operational position
or performance, budgets and projected costs, future competitive position, or
goals and/or projections of management for future operations. In some cases,
you
can identify a forward-looking statement by terminology such as “may”, “will”,
“could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”,
“believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”,
the negative of such terms or variations thereon, or other comparable
terminology.
The
forward-looking statements contained in this report are largely based on our
expectations for the future, which reflect certain estimates and assumptions
made by our management. These estimates and assumptions reflect our best
judgment based on currently known market conditions, operating trends, and
other
factors. Although we believe such estimates and assumptions to be reasonable,
they are inherently uncertain and involve a number of risks and uncertainties
that are beyond our control. As such, management’s assumptions about future
events may prove to be inaccurate. For a more detailed description of the risks
and uncertainties involved, see Item 1A. Risk Factors in our Annual Report
on
Form 10-K for the year ended December 31, 2006 as updated by this report. We
do
not intend to publicly update or revise any forward-looking statements as a
result of new information, future events, changes in circumstances, or
otherwise. These cautionary statements qualify all forward-looking statements
attributable to us, or persons acting on our behalf. Management cautions all
readers that the forward-looking statements contained in this report are not
guarantees of future performance, and we cannot assure any reader that such
statements will be realized or that the events and circumstances they describe
will occur. Factors that could cause actual results to differ materially from
those anticipated or implied in the forward-looking statements herein include,
but are not limited to:
·
|
The
supply and demand for oil, natural gas, and other products and
services;
|
·
|
The
price of
oil, natural gas, and other products and services;
|
·
|
Conditions
in the energy markets;
|
·
|
Changes
or advances in technology;
|
·
|
Currency
exchange rates and inflation;
|
·
|
The
availability and cost of relevant raw materials, goods and
services;
|
·
|
Future
processing volumes and pipeline
throughput;
|
·
|
Conditions
in the securities and/or capital
markets;
|
·
|
The
occurrence of property acquisitions or
divestitures;
|
·
|
Drilling
and exploration risks;
|
·
|
The
availability and cost of processing and
transportation;
|
·
|
Developments
in oil-producing and natural gas-producing
countries;
|
·
|
Competition
in the oil and natural gas
industry;
|
·
|
The
ability and willingness of our current or potential counterparties or
vendors to enter into transactions with us and/or to fulfill their
obligations to us;
|
·
|
Our
ability to access the capital markets on favorable terms or at
all;
|
·
|
Our
ability to obtain credit and/or capital in desired amounts and/or
on
favorable terms;
|
·
|
Present
and possible future claims, litigation and enforcement
actions;
|
·
|
Effects
of the application of applicable laws and regulations, including
changes
in such regulations or the interpretation
thereof;
|
·
|
Relevant
legislative or regulatory changes, including retroactive royalty
or
production tax regimes, changes in environmental regulation, environmental
risks and liability under federal, state and foreign environmental
laws
and regulations;
|
·
|
General
economic conditions, either internationally, nationally or in
jurisdictions affecting our
business;
|
·
|
The
amount of resources expended in connection with Calpine’s bankruptcy,
including costs for lawyers, consultant experts and related expenses,
as
well as all lost opportunity costs associated with our internal
resources
dedicated to these matters;
|
·
|
Disputes
with mineral lease and royalty owners regarding calculation and
payment of
royalties;
|
·
|
The
weather, including the occurrence of any adverse weather conditions
and/or
natural disasters affecting our business;
and
|
·
|
Any
other factors that impact or could impact the exploration of oil
or
natural gas resources, including but not limited to the geology
of a
resource, the total amount and costs to develop recoverable reserves,
and
legal title, regulatory, natural gas administration, marketing
and
operational factors relating to the extraction of oil and natural
gas.
|
ITEM
2. Management’s Discussion and Analysis of Financial Condition
and Results of Operations
Overview
The
following discussion addresses material changes in the results of operations
for
the three and six months ended June 30, 2007 compared to the three and six
months ended June 30, 2006, and the material changes in financial condition
since December 31, 2006. It is presumed that readers have read or
have access to our 2006 Annual Report on Form 10-K for the year ended December
31, 2006, which includes disclosures regarding critical accounting policies
as
part of Management’s Discussion and Analysis of Financial Condition and Results
of Operations.
We
continue to execute our strategy to increase value per share. The
following summarizes our performance for the first six months of 2007 as
compared to the same period for 2006:
·
|
Production
increased 31%;
|
·
|
The
average revenue price, including the effects of hedging, decreased
$0.25
per Mcfe or 3%;
|
·
|
Total
revenue, including the effects of hedging, increased $34.7 million
or
27%;
|
·
|
Net
income increased $7.6 million or
39%;
|
·
|
Earnings
per share increased $0.15 or 38%;
|
·
|
Capital
expenditures increased by $71 million or 70% including acquisition of
oil and gas properties; and
|
·
|
Drilled
94 gross wells with a success rate of
85%.
|
We
have
significantly grown our oil and natural gas production operations since we
acquired Calpine Natural Gas L.P. in July 2005 (the “Acquisition”), and
management believes it has the ability to continue growing production by
drilling already identified locations on our current existing
leases.
In
April
2007, the Company acquired properties located in the Sacramento Basin from
Output Exploration, LLC and OPEX Energy, LLC at a total purchase price
of $38.7 million, subject to final adjustments.
In
addition, in April 2007, we entered into additional 5,000 MMBtu per day of
financial fixed price swaps with an average underlying price of $8.08 per MMBtu
covering a portion of our 2008 production.
Critical
Accounting Policies and Estimates
In
our
Annual Report on Form 10-K for the year ended December 31, 2006, we identified
our most critical accounting policies upon which our financial condition depends
as those relating to oil and natural gas reserves, full cost method of
accounting, derivative transactions and hedging activities, income taxes and
stock-based compensation.
We
assess
the impairment for oil and natural gas properties for the full cost pool
quarterly using a ceiling test to determine if impairment is necessary. If
the
net capitalized costs of oil and natural gas properties exceed the cost center
ceiling, we are subject to a ceiling test write-down to the extent of such
excess. A ceiling test write-down is a charge to earnings and cannot be
reinstated even if the cost ceiling increases at a subsequent reporting date.
If
required, it would reduce earnings and impact shareholders’ equity in the period
of occurrence and result in a lower depreciation, depletion and amortization
expense in the future.
Our
ceiling test computation was calculated using hedge adjusted market prices
at
June 30, 2007, which were based on a Henry Hub price of $6.80 per MMBtu and
a
West Texas Intermediate oil price of $69.63 per Bbl (adjusted for basis and
quality differentials). Cash flow hedges of natural gas production in place
at
June 30, 2007 increased the calculated ceiling value by approximately $21.7
million (net of tax). There was no write-down recorded at June 30, 2007. Due
to
the volatility of commodity prices, should natural gas prices decline in the
future, it is possible that a write-down could occur.
Recent
Accounting Developments
For
a discussion of recent accounting developments, see
Note 2 to the Consolidated Financial Statements.
Results
of Operations
Revenues. Our
revenues are derived from the sale of our oil and natural gas production, which
includes the effects of qualifying hedge contracts. Our revenues may
vary significantly from period to period as a result of changes in commodity
prices or volumes of production sold. Total revenue for the first six
months of 2007 was $162.7 million which is an increase of $34.7 million, or
27%,
from the six months ended June 30, 2006. Approximately 90% of revenue
was attributable to natural gas sales on total volumes of 20.6
Bcfe.
The
following table presents information regarding our revenues and production
volumes:
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
|
|
|
|
|
|
%
Change
|
|
|
|
|
|
|
|
|
%
Change
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
|
(In
thousands, except percentages and per unit
amounts)
|
|
Total
revenues
|
|
$ |
86,874
|
|
|
$ |
63,381
|
|
|
|
37 |
% |
|
$ |
162,670
|
|
|
$ |
127,925
|
|
|
|
27 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(Bcf)
|
|
|
10.0
|
|
|
|
7.1
|
|
|
|
41 |
% |
|
|
19.0
|
|
|
|
14.0
|
|
|
|
36 |
% |
Oil
(MBbls)
|
|
|
149.4
|
|
|
|
143.6
|
|
|
|
4 |
% |
|
|
269.3
|
|
|
|
270.8
|
|
|
|
(1 |
%) |
Total
Equivalents (Bcfe)
|
|
|
10.9
|
|
|
|
8.0
|
|
|
|
36 |
% |
|
|
20.6
|
|
|
|
15.7
|
|
|
|
31 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
Gas Price per Mcf
|
|
$ |
7.74
|
|
|
$ |
7.56
|
|
|
|
2 |
% |
|
$ |
7.72
|
|
|
$ |
7.89
|
|
|
|
(2 |
%) |
Avg.
Gas Price per Mcf excluding Hedging
|
|
|
7.50
|
|
|
|
6.28
|
|
|
|
19 |
% |
|
|
7.32
|
|
|
|
7.12
|
|
|
|
3 |
% |
Avg.
Oil Price per Bbl
|
|
|
63.17
|
|
|
|
67.54
|
|
|
|
(6 |
%) |
|
|
59.68
|
|
|
|
64.65
|
|
|
|
(8 |
%) |
Avg.
Revenue per Mcfe
|
|
|
7.97
|
|
|
|
7.92
|
|
|
|
1 |
% |
|
|
7.90
|
|
|
|
8.15
|
|
|
|
(3 |
%) |
Natural
Gas. For the three months ended June 30, 2007,
natural gas revenue increased by $23.7 million, including the realized impact
of
derivative instruments, from the comparable period in 2006, to $77.4
million. This increase is primarily due to an increase in production
in the California, the Rocky Mountains, the Offshore and the Lobo
regions. Also, the acquisition of the Sacramento Basin properties
from Output Exploration, LLC and OPEX Energy, LLC (“OPEX Properties”) in April
2007 contributed to the overall increase in production. The increase
in natural gas sales were offset by a decrease in the gain related to hedging
activities of $6.7 million.
For
the six months ended June 30, 2007, natural gas revenue increased to $146.6
million from $110.4 million for the comparable period in 2006. This
increase of $36.2 million is primarily due to an increase in the number of
wells
producing in 2007 as well as an increase in production volumes associated with
the California, the Rocky Mountains, the Offshore and the Lobo
regions. Also, the acquisition of the OPEX Properties in April 2007
contributed to the overall increase in production. The 2007 realized average
natural gas price was $7.72 as compared to $7.89 for 2006.
Crude
Oil. For the three months ended June 30, 2007,
oil revenue was $9.4 million as compared to $9.7 million for the same period
in
2006. This decrease is attributable to a decrease in the average
realized gas prices from $67.54 per Bbl to $63.17 per Bbl. The
effects of the decrease in the average realized price was offset by an increase
in production volume of 4% primarily as a result of new wells producing in
the
Offshore region.
For
the
six months ended June 30, 2007, oil revenue decreased by $1.4 million due to
the
decrease in the average realized oil price of $4.97 from $64.65 per Bbl to
$59.68 per Bbl. The production volumes were 269.3 MBbls for the six
months ended June 30, 2007 which is comparable to the same period in
2006.
Operating
Expenses
The
following table presents information regarding our operating
expenses:
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
|
|
|
|
|
|
%
Change
|
|
|
|
|
|
|
|
|
%
Change
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
|
(In
thousands, except percentages and per unit
amounts)
|
|
Lease
operating expense
|
|
$ |
12,566
|
|
|
$ |
8,323
|
|
|
|
51 |
% |
|
$ |
21,362
|
|
|
$ |
17,881
|
|
|
|
19 |
% |
Depreciation,
depletion and amortization
|
|
|
36,342
|
|
|
|
25,601
|
|
|
|
42 |
% |
|
|
66,893
|
|
|
|
49,668
|
|
|
|
35 |
% |
General
and administrative costs
|
|
|
9,898
|
|
|
|
7,078
|
|
|
|
40 |
% |
|
|
17,967
|
|
|
|
16,329
|
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
lease operating expense per Mcfe
|
|
$ |
1.15
|
|
|
$ |
1.04
|
|
|
|
11 |
% |
|
$ |
1.04
|
|
|
$ |
1.14
|
|
|
|
(9 |
%) |
Avg.
DD&A per Mcfe
|
|
|
3.33
|
|
|
|
3.20
|
|
|
|
4 |
% |
|
|
3.25
|
|
|
|
3.16
|
|
|
|
3 |
% |
Avg.
G&A per Mcfe
|
|
|
0.91
|
|
|
|
0.88
|
|
|
|
3 |
% |
|
|
0.87
|
|
|
|
1.04
|
|
|
|
(16 |
%) |
Our
operating expenses are primarily related to the following items:
Lease
Operating Expense. Lease operating expense increased $4.2
million for the three months ended June 30, 2007 as compared to the three months
ended June 30, 2006. This increase is primarily due to an increase in
Ad Valorem tax related to property appraisals in California. In
addition, the increase in production of 36% contributed to higher costs for
equipment rentals, maintenance and repairs, and costs associated with
non-operated properties.
Lease
operating expense increased $3.5 million for the six months ended June 30,
2007
as compared to the six months ended June 30, 2006. This increase is primarily
due to an increase in Ad Valorem tax related to property appraisals in
California. In addition, the increase in production of 31% for 2007
contributed to higher costs for equipment rentals, maintenance and repairs,
and
costs associated with non-operated properties. In the first six
months of 2006, we incurred $1.2 million more in workover expenses associated
with the Offshore region which was not incurred in 2007.
Depreciation,
Depletion, and Amortization. Depreciation, depletion and
amortization expense increased $10.7 million for the three months ended June
30,
2007 as compared to the three months ended June 30, 2006. The
increase is due to a 36% increase in total production and a higher depletion
rate for 2007 as compared to 2006. The depletion rate for the second
quarter of 2007 was $3.25 per Mcfe while the rate for the second quarter of
2006
was $3.16 per Mcfe.
Depreciation,
depletion and amortization expense increased $17.2 million for the six months
ended June 30, 2007 as compared to the six months ended June 30,
2006. The increase is due to a 31% increase in total
production and a higher depletion rate for 2007 as compared to
2006. The depletion rate for the respective period in 2007 was $3.15
per Mcfe while the rate for the same period in 2006 was $3.11 per
Mcfe.
General
and Administrative Costs. General and administrative costs
increased by $2.8 million for the three months ended June 30, 2007 as compared
to the three months ended June 30, 2006. This increase is primarily
associated with legal fees, payroll expenses and costs associated with the
first
year implementation of Section 404 of the Sarbanes-Oxley Act. In
addition, $0.3 million of the increase is due to an increase in stock
compensation expense which was $1.8 million for the three months ended June
30,
2007 as compared to $1.5 million for the respective period in 2006.
General
and administrative costs increased by $1.6 million for the six months ended
June
30, 2007 as compared to the six months ended June 30, 2006. This
increase is net of decreases in audit and consulting fees related to higher
costs in the first six months of 2006 associated with becoming a public company,
which was not incurred in 2007. The costs in the current period are
primarily associated with legal fees, payroll expenses and costs associated
with
the first year implementation of Section 404 of the Sarbanes-Oxley
Act. In addition, stock compensation expense of $3.2 million for the
six months ended June 30, 2007 was comparable to the 2006 expense of $3.3
million.
Total
Other Expense
Other
expense includes interest expense, interest income and other income/expense,
net
which increased $0.8 million and $1.2 million for the three and six months
ended
June 30, 2007, respectively, as compared to the respective periods in
2006. The increase in other expense is the result of less interest
income in 2007 to offset expenses as compared to 2006. The interest
income is earned on the cash balance, which was greater at June 30, 2006 than
at
June 30, 2007. Approximately $35 million was expended during the
fourth quarter of 2006 to fund various asset acquisitions and approximately
$38
million was expended during the second quarter of 2007 for the acquisition
of
the OPEX Properties.
Provision
for Income Taxes
The
effective tax rate for the six months ended June 30, 2007 was 37.9%, which
is
comparable to the tax rate for the six months ended June 30, 2006 of
38.1%. The effective tax rate for the three months ended June 30,
2007 and 2006 was 37.8%. The provision for income taxes differs from
the tax computed at the federal statutory income tax rate primarily due to
state
income taxes, tax credits and other permanent differences.
Liquidity
and Capital Resources
Our
primary source of liquidity and capital is our operating cash flow. We also
maintain a revolving line of credit, which can be accessed as needed to
supplement operating cash flow.
Operating
Cash Flow. Our cash flows depend on many factors, including the
price of oil and natural gas and the success of our development and exploration
activities as well as future acquisitions. We actively manage our exposure
to
commodity price fluctuations by executing derivative transactions to hedge
the
change in prices of our production, thereby mitigating our exposure to price
declines, but these transactions will also limit our earnings potential in
periods of rising natural gas prices. This derivative transaction activity
will
allow us the flexibility to continue to execute our capital plan if prices
decline during the period in which our derivative transactions are in place.
The
effects of these derivative transactions on our natural gas sales are discussed
above under “Results of Operations – Natural Gas”. In addition, the
majority of our capital expenditures are discretionary and could be curtailed
if
our cash flows decline from expected levels.
Senior
Secured Revolving Line of Credit. BNP Paribas, in
July 2005 provided us with a senior secured revolving line of credit
concurrent with the Acquisition, in the amount of up to $400.0 million
(“Revolver”). This Revolver was syndicated to a group of lenders on
September 27, 2005. Availability under the Revolver is restricted to the
borrowing base, which initially was $275.0 million and was reset to $325.0
million, upon amendment, as a result of the hedges put in place in
July 2005 and the favorable effects of the exercise of the over-allotment
option we granted in our private equity offering in July 2005. In July 2005,
we
repaid $60.0 million of the $225.0 million in original borrowings on the
Revolver. The borrowing base is subject to review and adjustment on a
semi-annual basis and other interim adjustments, including adjustments based
on
our hedging arrangements. In May 2007, the borrowing base was adjusted to $350.0
million. Initial amounts outstanding under the Revolver bore
interest, as amended, at specified margins over the London Interbank Offered
Rate (“LIBOR”) of 1.25% to 2.00%. These rates over LIBOR were
adjusted in May to be 1.00% to 1.75%. Such margins will fluctuate
based on the utilization of the facility. Borrowings under the Revolver are
collateralized by perfected first priority liens and security interests on
substantially all of our assets, including a mortgage lien on oil and natural
gas properties having at least 80% of the SEC PV-10 pretax reserve value, a
guaranty by all of our domestic subsidiaries, a pledge of 100% of the stock
of
domestic subsidiaries and a lien on cash securing the Calpine gas purchase
and
sale contract. These collateralized amounts under the mortgages are subject
to
semi-annual reviews based on updated reserve information. We are subject to
the
financial covenants of a minimum current ratio of not less than 1.0 to 1.0
as of
the end of each fiscal quarter and a maximum leverage ratio of not greater
than
3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal
quarters then ended, measured quarterly with the pro forma effect of
acquisitions and divestitures. At June 30, 2007, our current ratio was 2.2
to
1.0, as adjusted per current agreements, and our leverage ratio was 2.9 to
1.0.
In addition, we are subject to covenants limiting dividends and other restricted
payments, transactions with affiliates, incurrence of debt, changes of control,
asset sales and liens on properties. We were in compliance with all covenants
at
June 30, 2007. All amounts drawn under the Revolver are due and payable on
July 7, 2009.
Second
Lien Term Loan. In July 2005, BNP Paribas provided us with
a second lien term loan in the amount of $100.0 million (“Term Loan”). On
September 27, 2005, we repaid $25.0 million of borrowings on the Term Loan,
reducing the balance to $75.0 million and syndicated the Term Loan to a group
of
lenders including BNP Paribas. Borrowings under the Term Loan initially bore
interest at LIBOR plus 5.00%. As a result of the hedges put in place in July
2005 and the favorable effects of our private equity placement, as described
above, the interest rate for the Term Loan has been reduced to LIBOR plus 4.00%.
The Term Loan is collateralized by second priority liens on substantially all
of
our assets. We are subject to the financial covenants of a minimum asset
coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of
not
more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the
four
fiscal quarters then ended, measured quarterly with the pro forma effect of
acquisitions and divestitures. In addition, we are subject to covenants limiting
dividends and other restricted payments, transactions with affiliates,
incurrence of debt, changes of control, asset sales, and liens on properties.
We
were in compliance with all covenants at June 30, 2007. The revised principal
balance of the Term Loan is due and payable on July 7, 2010.
Availability.
Availability under the revolving line of credit was $184.0 million at
June 30, 2007.
Cash
Flows
The
following table presents information regarding the change in our cash
flow:
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Cash
flows provided by operating activities
|
|
$ |
114,295
|
|
|
$ |
93,431
|
|
Cash
flows used in investing activities
|
|
|
(165,764 |
) |
|
|
(99,516 |
) |
Cash
flows provided by (used in) financing activities
|
|
|
458
|
|
|
|
(433 |
) |
Net
decrease in cash and cash equivalents
|
|
$ |
(51,011 |
) |
|
$ |
(6,518 |
) |
Operating
Activities. Key drivers of net cash provided by operating activities are
commodity prices, production volumes and costs and expenses, which primarily
include operating costs, taxes other than income taxes, transportation and
general and administrative expenses. Net cash provided by operating
activities (“Operating Cash Flow”) continued to be a primary source of liquidity
and capital used to finance our capital expenditures for the six months ended
June 30, 2007.
Cash
flows provided by operating activities increased by $20.9 million for the six
months ended June 30, 2007 as compared to the same period for
2006. The increase in 2007 primarily resulted from higher oil and gas
production in 2007. In addition, at June 30, 2007, we had a working
capital deficit of $41.0 million. This deficit was largely caused by
the decrease in our cash balance to fund capital expenditures, including
property acquisitions. For the six months ended June 30, 2007, we
incurred approximately $172.8 million in capital expenditures as compared to
$101.8 million for the six months ended June 30, 2006.
Investing
Activities. The primary driver of cash used in investing
activities is capital spending.
Cash
flows used in investing activities increased by $66.2 million for the six months
ended June 30, 2007 as compared to the same period for 2006. During
the six months ended June 30, 2007, we participated in the drilling of 94 gross
wells and acquired the OPEX Properties.
Financing
Activities. The primary driver of cash provided by or used in
financing activities are equity transactions.
Cash
flows provided by financing activities increased by $0.9 million as compared
to
the same period for 2006. The net increase is primarily
related to an increase in the issuance of common stock and fewer repurchases of
treasury stock. The repurchases of stock were surrendered by certain
employees to pay tax withholding upon vesting of restricted stock
awards. These repurchases are not part of a publicly announced
program to repurchase shares of our common stock, nor do we have a publicly
announced program to repurchase shares of common stock.
Capital
Expenditures
Our
capital expenditures for the six months ended June 30, 2007 increased by $71.0
million to $172.8 million, over the comparable period in
2006. Included in the current year capital expenditures is $38.7
million for the acquisition of the OPEX Properties. During the six
months ended June 30, 2007, we participated in the drilling of 94 gross wells
with the majority of these being in the Rocky Mountains and the Lobo
regions. Our positive Operating Cash Flow, along with the
availability under our revolving credit facility, are projected to be sufficient
to fund our budgeted capital expenditures for 2007, which are currently
projected to be $250.0 million. Currently, we are evaluating increasing our
capital activity for the year.
Calpine
Matters
On
December 20, 2005 Calpine and certain of its subsidiaries filed for protection
under federal bankruptcy laws in the United States Bankruptcy Court of the
Southern District of New York (the “Bankruptcy Court”). The filing raises
certain concerns and disputes regarding aspects of our relationship with
Calpine
which we will continue to closely monitor as the Calpine bankruptcy proceeds.
Additionally, on June 29, 2007, Calpine filed an adversary proceeding against
us
seeking $400 million, plus interest as a result of alleged shortfall in value
received for the assets involved in the Acquisition or in the alternative,
a
return of the domestic oil and gas assets sold to us by Calpine. See Part
II.
Item 1. Legal Proceedings for further information regarding the Calpine
bankruptcy.
Item
3. Quantitative and Qualitative Disclosures About
Market Risk
We
are
currently exposed to market risk primarily related to adverse changes in oil
and
natural gas prices and interest rates. We use derivative instruments to manage
our commodity price risk caused by fluctuating prices. We do not
enter into derivative instruments for trading purposes. For information
regarding our exposure to certain market risks, see Item 7A. “Quantitative and
Qualitative Disclosure About Market Risks” in our annual report filed on Form
10-K for the year ended December 31, 2006. There have been no significant
changes in our market risk from what was disclosed in our Annual Report filed
on
Form 10-K for the year ended December 31, 2006.
Item
4. Controls and Procedures
Under
the
supervision and with the participation of our management, including
our Chief Executive Officer and Chief Financial Officer, we conducted an
evaluation of the effectiveness of the design and operation of our disclosure
controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under
the
Securities Exchange Act of 1934, as amended (“Exchange Act”), as of June 30,
2007. Based on that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that, as of June 30, 2007, our disclosure controls
and procedures were effective in providing reasonable assurance that information
required to be disclosed by us in the reports filed or submitted by us under
the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the SEC’s rules and forms, and that such information is
accumulated and communicated to the Company’s management, including the Chief
Executive Officer and Chief Financial Officer, as appropriate, to allow timely
decisions regarding required disclosure.
There
were no changes in the Company’s internal control over financial reporting that
occurred during the most recent fiscal quarter that have materially affected,
or
are reasonable likely to materially affect, the Company’s internal control over
financial reporting.
PART
II. Other Information
Item
1. Legal Proceedings
We
and
our subsidiaries are parties to various oil and natural gas litigation matters
arising out of the ordinary course of business. While the outcome of
these proceedings cannot be predicted with certainty, we do not expect these
matters to have a material adverse effect on the financial
statements.
Calpine
Bankruptcy
On
December 20, 2005, Calpine and certain of its subsidiaries filed for
protection under the federal bankruptcy laws in the United States Bankruptcy
Court of the Southern District of New York (the “Bankruptcy
Court”).
Calpine’s
Lawsuit Against Rosetta
On
June
29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy
Court. The complaint alleges that our purchase of the domestic oil
and natural gas assets formally owned by Calpine (the “Assets”) in July 2005 for
$1.05 billion, prior to Calpine filing for bankruptcy, was completed when
Calpine was insolvent and was for less than a reasonably equivalent
value. Calpine is seeking (i) monetary damages for the alleged
shortfall in value it received for these assets which it estimates to be
approximately $400 million dollars, plus interest, or (ii) in the alternative,
return of the Assets from us. We believe that these allegations are
wholly baseless, intend to vigorously defend against all claims made by Calpine
and are further considering additional steps we may take to fully protect our
interests. We continue to believe that it is unlikely that this
challenge by the Calpine debtors to the fairness of the Acquisition will be
successful upon ultimate disposition after appeals, if any. The deadline
for us to answer or file our responsive pleading is September 10, 2007, and
we have advised the Bankruptcy Court that we intend to file a motion to dismiss
the complaint on or before the answer date. Calpine has requested a trial date
in December 2007, but at the present time, no trial date has been set by
the Bankruptcy Court.
Remaining
Issues with Respect to the Acquisition
Separate
from the Calpine lawsuit, Calpine has taken the position that the Purchase
and
Sale Agreement and interrelated agreements concurrently executed therewith,
dated July 7, 2005, by and among Calpine, us, and various other signatories
thereto (collectively, the “Purchase Agreement”) are “executory contracts”,
which Calpine may assume or reject. Following the July 7, 2005
closing of the Acquisition and as of the date of Calpine’s bankruptcy filing,
there were open issues regarding legal title to certain properties included
in
the Purchase Agreement. On June 20, 2007, Calpine filed with the
Bankruptcy Court its proposed Plan of Reorganization under Chapter 11 of
the Bankruptcy Code, together with the accompanying Disclosure Statement, in
which Calpine revealed it had not yet made a decision as to whether to assume
or
reject its remaining duties and obligations under the Purchase Agreement.
If the Court were to determine that the Purchase Agreement is an executory
contract, the various agreements entered into as part of the transaction
constitute a single contract for purposes of assumption or rejection under
the
Bankruptcy Code, and we contend that Calpine cannot choose to assume certain
of
the agreements and to reject others. This issue may be contested by
Calpine. If the Purchase Agreement is held to be executory, the
deadline by when Calpine must exercise its decision to assume or reject the
Purchase Agreement and the further duties and obligations required therein
is
the date on which Calpine’s Plan of Reorganization is confirmed.
Open
Issues Regarding Legal Title to Certain Properties
Under
the
Purchase Agreement, Calpine is required to resolve the open issues regarding
legal title to certain properties. At the closing of the Acquisition
on July 7, 2005, we retained approximately $75 million of the purchase
price in respect to Non-Consent Properties identified by Calpine as requiring
third-party consents or waivers of preferential rights to purchase that were
not
received by the parties before closing (“Non-Consent
Properties”). Those Non-Consent Properties were therefore not
included in the conveyances delivered at the closing. Subsequent
analysis determined that a significant portion of the Non-Consent Properties
did
not require consents or waivers. For that portion of the Non-Consent
Properties for which third-party consents were in fact required and for which
either us or Calpine obtained the required consents or waivers, as well as
for
all Non-Consent Properties that did not require consents or waivers, we contend
Calpine was and is obligated to have transferred to us the record title, free
of
any mortgages and other liens.
The
approximate allocated value under the Purchase Agreement for the portion of
the
Non-Consent Properties subject to a third-party’s preferential right to purchase
is $7.4 million. We have retained $7.1 million of the purchase price
under the Purchase Agreement for the Non-Consent Properties subject to the
third-party preferential right, and, in addition, a post-closing adjustment
is
required to credit us for approximately $0.3 million for a property which was
transferred to us but, if necessary, will be transferred to the appropriate
third party under its exercised preferential purchase right upon Calpine’s
performance of its obligations under the Purchase Agreement.
We
believe all conditions precedent for our receipt of record title, free of any
mortgages or other liens, for substantially all of the Non-Consent Properties
(excluding that portion of these properties subject to the third-party
preferential right) were satisfied earlier, and certainly no later, than
December 15, 2005, when we tendered once again the amounts necessary to conclude
the settlement of the Non-Consent Properties.
We
believe we are the equitable owner of each of the Non-Consent Properties for
which Calpine was and is obligated to have transferred the record title and
that
such properties are not part of Calpine’s bankruptcy estate. Upon our
receipt from Calpine of record title, free of any mortgages or other liens,
to
these Non-Consent Properties and further assurances required to eliminate any
open issues on title to the remaining properties discussed below, we are
prepared to pay Calpine approximately $68 million, subject to appropriate
adjustment, if any. Our statement of operations for the six months ended June
30, 2007, the year ended December 31, 2006 and six months ended December 31,
2005, does not include any net revenues or production from any of the
Non-Consent Properties, including those properties subject to preferential
rights.
If
Calpine does not provide us with record title, free of any mortgages for all
of
these properties and other liens, to any of the Non-Consent Properties
(excluding that portion of these properties subject to a validly exercised
third
party’s preferential right to purchase), we will have a total of approximately
$68 million available to us for general corporate purposes, including for the
purpose of acquiring additional properties. We also have
approximately $7.1 million, previously withheld for that portion of the
Non-Consent Properties subject to a third party’s preferential right to
purchase, which will also be available for general corporate purposes, including
for the purpose of acquiring additional properties should that third party
properly exercise the preferential rights.
In
addition, as to certain of the other oil and natural gas properties we purchased
from Calpine in the Acquisition and for which payment was made on July 7, 2005,
we are seeking additional documentation from Calpine to eliminate any open
issues in our title or resolve any issues as to the clarity of our ownership.
Requests for additional documentation are customary in connection with
transactions similar to the Acquisition. In the Acquisition, certain of these
properties require ministerial governmental action approving us as qualified
assignee and operator, which is typically required even though in most cases
Calpine has already conveyed the properties to us free and clear of mortgages
and liens by Calpine’s creditors. As to certain other properties, the
documentation delivered by Calpine at closing under the Purchase Agreement
was
incomplete. We remain hopeful that Calpine will work cooperatively with us
to
secure these ministerial governmental approvals and to accomplish the curative
corrections for all of these properties. In addition, as to all properties
acquired by us in the Acquisition, Calpine contractually agreed to provide
us
with such further assurances as we may reasonably request. Nevertheless, as
a
result of Calpine’s bankruptcy filing, it remains uncertain as to whether
Calpine will respond cooperatively. If Calpine does not fulfill its contractual
obligations (as a result of rejection of the Purchase Agreement or otherwise)
and does not complete the documentation necessary to resolve these issues,
we
will pursue all available remedies, including but not limited to a declaratory
judgment to enforce our rights and actions to quiet title. After pursuing these
matters, if we experiences a loss of ownership with respect to these properties
without receiving adequate consideration for any resulting loss to us, an
outcome our management considers to be unlikely upon ultimate disposition
including appeals, if any, then we could experience losses which could have
a material adverse effect on our financial condition, statement of operations
and cash flows.
Sale
of Natural Gas to Calpine
In
addition, the issues involving legal title to certain properties, we executed,
as part of the interrelated agreements that constitute the Purchase Agreement,
certain natural gas supply agreements with Calpine Energy Services, L.P.
(“CES”), which also filed for bankruptcy on December 20, 2005. During
the period following Calpine’s filing for bankruptcy, CES has continued to make
the required deposits into our margin account and to timely pay for natural
gas
production it purchases from our subsidiaries under these various natural gas
supply agreements. Although Calpine has indicated in a supplement to
its recently proposed plan of reorganization that it intends to assume the
CES
natural gas supply agreements with us, we disagree that Calpine may assume
anything less than the entire Purchase Agreement and intend to oppose any effort
by Calpine to do less.
Calpine’s
Marketing of the Company’s Production
Additionally,
Calpine Producer Services, L.P. (“CPS”), which also filed for bankruptcy,
entered into a Marketing and Services Agreement (“MSA”) with us as part of the
interrelated agreements that constitute the Purchase Agreement. Under
the MSA, CPS provided marketing and sales of our natural gas production to
third-parties and charged us a fee. The MSA, however, expired by its
terms on June 30, 2007. Through a recently executed letter agreement,
we and CPS agreed to extend the MSA until September 30, 2007, subject to
and to enable the parties to negotiate and execute a New Marketing and Services
Agreement (“New MSA”). On August 3, 2007, as part of the Partial
Transfer and Release Agreement, discussed in greater detail below, we and CPS
concurrently executed the New MSA, which, if approved by the Bankruptcy Court,
will be effective as of July 1, 2007 and extend CPS’ obligation to provide such
services until June 30, 2009. The New MSA is subject to earlier
termination by us upon the occurrence of certain events. In the interim, CPS
is
generally performing its obligations under the MSA.
Events
Within Calpine’s Bankruptcy Case
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases that Calpine had previously
sold or agreed to sell to us in the Acquisition, to the extent those leases
constitute “unexpired leases of non-residential real property” and were not
fully transferred to us at the time of Calpine’s filing for
bankruptcy. The oil and gas leases identified in Calpine’s motion
are, in large part, those properties with open issues in regards to their legal
title in which Calpine contends it may possess some legal
interest. According to this motion, Calpine filed it in order to
avoid the automatic forfeiture of any interest it may have in these leases
by
operation of a bankruptcy code deadline. Calpine’s motion did not
request that the Bankruptcy Court determine whether these properties belong
to
us or Calpine, but we understand it was meant to allow Calpine to preserve
and
avoid forfeiture under the Bankruptcy Code of whatever interest Calpine may
possess, if any, in these oil and natural gas leases. We dispute Calpine’s
contention that it may have an interest in any significant portion of these
oil
and natural gas leases and intend to take the necessary steps to protect all
of
our rights and interest in and to the leases.
On
July
7, 2006, we filed an objection in response to Calpine’s motion, wherein we
asserted that oil and natural gas leases constitute interests in real property
that are not subject to “assumption” under the Bankruptcy Code. In the
objection, we also requested that (a) the Bankruptcy Court eliminate from the
order certain Federal offshore leases from the Calpine motion because these
properties were fully conveyed to us in July 2005, and the Minerals Management
Service has subsequently recognized us as owner and operator of all but three
of
these properties, and (b) any order entered by the Bankruptcy Court be without
prejudice to, and fully preserve our rights, claims and legal arguments
regarding the characterization and ultimate disposition of the remaining
described oil and natural gas properties. In our objection, we also
urged the Bankruptcy Court to require the parties to promptly address and
resolve any remaining issues under the pre-bankruptcy definitive agreements
with
Calpine and proposed to the Bankruptcy Court that the parties could seek
mediation to complete the following:
|
·
|
Calpine’s
conveyance of the Non-Consent Properties to
us;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which we
have already paid Calpine; and
|
|
·
|
Resolution
of the final amounts we are to pay Calpine, which we had at
that time concluded was approximately $79 million, consisting of
roughly
$68 million for the Non-Consent Properties and approximately $11
million
in other true-up payment obligations. We are currently updating these
calculations.
|
At
a
hearing held on July 12, 2006, the Bankruptcy Court took the following
steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion those
leases issued by the United States (and managed by the Minerals Management
Service of the United States Department of Interior) (the “MMS Oil and Gas
Leases”) and the State of California (and managed by the California State
Lands Commission) (the “CSLC Leases”). Calpine and both the Department of
Justice and the State of California agreed to an extension of the
existing
deadline to November 15, 2006 to assume or reject the MMS Oil and
Gas
Leases and CSLC Leases under Section 365 of the Bankruptcy Code,
to the
extent the MMS Oil and Gas Leases and CSLC Leases are leases subject
to
Section 365. The effect of these actions was to render our
objection inapplicable at that time;
and
|
|
·
|
The
Bankruptcy Court also encouraged Calpine and us to arrive at a business
solution to all remaining issues including approximately $68 million
payable to Calpine for conveyance of the Non-Consent
Properties.
|
On
August
1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts as well as unliquidated damages in amounts that
can not presently be determined. In the event that Calpine elects to
reject the Purchase Agreement or otherwise refuses to perform its remaining
obligations therein, we anticipate we will be allowed to amend our
proofs of claim to assert any additional damages we suffer as a result of
the ultimate impact of Calpine’s refusal or failure to perform under the
Purchase Agreement. In the bankruptcy, Calpine may elect to contest
or dispute the amount of damages we seek in our proofs of claim. We
will assert all right to offset any of our damages against any
funds we possess that may be owed to Calpine. Until the allowed
amount of our claims are finally established and the Bankruptcy Court issues
its
rulings with respect to Calpine’s plan confirmation, we can not predict what
amounts we may recover from the Calpine bankruptcy should Calpine reject or
refuse to perform under the Purchase Agreement.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases and the
CSLC Leases respectively, these parties have further extended this deadline
by
stipulation. The deadline was first extended to January 31, 2007, was further
extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April
30, 2007 with respect to the CSLC Leases, was further extended again to
September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15,
2007
and more recently, October 31, 2007 with respect to the CSLC Leases. The
Bankruptcy Court entered Orders related to the MMS Oil and Gas Leases and CSLC
Leases which included appropriate language that we negotiated with Calpine
for
our protection in this regard.
On
June
20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure
Statement with the Bankruptcy Court. Calpine has indicated in its
filings with the Court that it believes substantial payments in the form of
cash
or newly issued stock, or some combination thereof, will be made to unsecured
creditors under its proposed Plan of Reorganization that could conceivably
result in payment of 100% of allowed claims and possibly provide some payment
to
its equity holders. The amounts any plan ultimately distributes to
its various claimants of the Calpine estate, including unsecured creditors,
will
depend on the Court’s conclusion with regard to Calpine’s enterprise value and
the amount of allowed claims that remain following the objection
process.
On
June
29, 2007, Calpine filed a notice with the Bankruptcy Court that it was in
discussions with unnamed third parties regarding alternative plans of
reorganization that might yield guaranteed payments to equity holders, thus
paying all unsecured creditors, and requested an extension of time to allow
such
discussions to continue. Although the deadlines with respect to
confirming any plan would be pushed back by approximately one month, Calpine
stated in its notice that its beneficial financing terms required it emerge
from
bankruptcy by January 31, 2008.
On
August
3, 2007, we executed a Partial Transfer and Release Agreement (“PTRA”) with
Calpine, subject to Bankruptcy Court approval, resolving certain open issues
without prejudice to Calpine’s avoidance action and, if the Court concludes the
Purchase Agreement is executory, Calpine’s ability to assume or reject the
Purchase Agreement. The principle terms are as follows:
|
·
|
We
will extend our existing natural gas marketing agreement with Calpine
until June 30, 2009. This agreement is subject to earlier
termination right by us upon the occurrence of certain
events;
|
|
·
|
Calpine
will deliver to us documents that resolve title issues pertaining
to
certain previously purchased oil and gas properties located in the
Gulf of
Mexico, California and Wyoming (“Properties”);
|
|
·
|
We
will assume all Calpine's rights and obligations for an audit by
the
California State Lands Commission on part of the Properties;
and
|
|
·
|
We will
assume all rights and obligations for the Properties, including all
plugging and abandonment
liabilities.
|
A
number
of the properties that, after the closing of the Acquisition, had open issues
in
regards to legal title will be resolved by the PTRA, if approved by the
Bankruptcy Court. Until a final order is received approving Calpine’s
entry into the PTRA, the possibility remains that the PTRA will not become
binding obligations of the parties.
As
a
result of Calpine’s bankruptcy, there remains the possibility that there will be
issues between us and Calpine that could amount to material contingencies in
relation to the litigation filed by Calpine against us or the Purchase
Agreement, including unasserted claims and assessments with respect to (i)
the
still pending Purchase Agreement and the amounts that will be payable in
connection therewith, (ii) whether or not Calpine and its affiliated debtors
will, in fact, perform their remaining obligations in connection with the
Purchase Agreement; and (iii) the ultimate disposition of the remaining
Non-Consent Properties (and related revenues).
Other
than with respect to the risk factors below, there have been no material changes
in our risk factors from those disclosed in Item 1A of our Annual Report on
Form
10-K for the year ended December 31, 2006. The following risk factor
was disclosed on form 10-K and has been updated as of June 30,
2007.
Calpine’s
bankruptcy filing may adversely affect us in several
respects.
Calpine,
its creditors or interest holders may challenge the fairness of some or all
of
the Acquisition.
On
June
29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy
Court. The complaint alleges that the purchase by us of the domestic
oil and natural gas assets formally owned by Calpine (the “Assets”) in July 2005
for $1.05 billion, prior to Calpine's declaring bankruptcy, was completed when
Calpine was insolvent and was for less than reasonably equivalent
value. Calpine is seeking (i) monetary damages for the alleged
shortfall in value it received for the Assets which it estimates to be
approximately $400 million dollars, plus interest, or (ii) in the alternative,
return of the Assets from us. We deny and intend to vigorously
defend against all claims made by Calpine, and we are considering
additional steps we may take to fully protect our interests. Our
deadline to file our responsive pleading or answer is September 10, 2007,
and the trial has not yet been scheduled. If after a trial on the merits, the
Bankruptcy Court was to determine that the Debtors have met their burden of
proof, it could void the transfer or take other actions against us, including
(i) setting aside the Acquisition and returning our purchase price and give
us a
first lien on all the properties and assets we purchased in the Acquisition
or
(ii) sustaining the Acquisition subject to our being required to pay the
Debtors the amount, if any, by which the fair value of the business transferred,
as determined by the Bankruptcy Court as of July 7, 2005, exceeded the
purchase price determined and paid in July 2005. If the Bankruptcy Court should
set aside the Acquisition, it would have a material adverse effect upon our
results of operation and financial condition in that substantially all our
properties conveyed at the time of the Acquisition would be returned to Calpine,
subject to our right (as a good faith transferee) to retain a lien in our favor
to secure the return of the purchase price we paid for the properties.
Additionally, if the Bankruptcy Court should so rule, any requirement to pay
an
increased purchase price could have a material adverse effect upon our results
of operation and financial condition depending on the amount we might be
required to pay. See Item 1. Legal Proceedings for further information regarding
the Calpine bankruptcy.
The
bankruptcy proceeding may prevent, frustrate or delay our ability to receive
record legal title to certain properties originally determined to be Non-Consent
Properties which we are entitled to receive under the Purchase
Agreement.
On
June
20, 2007, Calpine filed with the Bankruptcy Court its proposed plan of
reorganization and disclosure statement. In the disclosure statement,
Calpine revealed that it had not yet made a decision on whether to assume or
reject its remaining obligations and duties under the Purchase and Sale
Agreement and interrelated agreements, which set forth the terms and agreements
related to Calpine’s sale of its oil and gas assets to us. In its
proposed supplement to the plan filed on the same date, however, Calpine
indicated its desire to assume the NAESB agreement under which we sell gas
to
Calpine and the CPS Marketing Agreement under which CPS sells our production
to
third parties on our behalf. We contend that all of the
transaction documents constitute one agreement and must therefore be assumed
or
rejected in their entirety as one agreement and will vigorously oppose any
effort by Calpine to treat any aspect of the transaction as a stand-alone
document.
Although
Calpine has not made its election to assume or reject the Purchase Agreement,
on
August 3, 2007, we executed a Partial Transfer and Release Agreement (“PTRA”)
with Calpine, subject to Bankruptcy Court approval, without prejudice to the
other pending claims, disputes, and defenses between Calpine and
us. As part of the PTRA, we agreed to extend the CPS marketing
agreement by two years, until June 30, 2009; however, the marketing agreement
is
subject to earlier termination by us upon the occurrence of certain
events. In return, Calpine has provided documents to resolve legal
title issues as to certain previously purchased oil and gas properties located
in the Gulf of Mexico, California and Wyoming (“Properties”). Under
the PTRA, we have also agreed to assume all liabilities with respect
to those Properties, such as plugging and abandonment, as well as all
liabilities and rights associated with any under- or over-payment to the State
of California as it relates to certain state land. We anticipate that the
Bankruptcy Court will address Calpine’s to-be-filed request for approval of the
PTRA in a hearing scheduled for September 11, 2007. If the Bankruptcy Court
does
not approve the PTRA, our New Marketing and Services Agreement will not take
effect, and we will discontinue using Calpine Producer Services, L.P. to market
and sell our gas. Further, we will argue that the
liabilities we were to assume under the PTRA will remain obligations
of Calpine. We will continue our efforts to resolve open issues in
regard to legal title of the properties; however, if Calpine were also to refuse
to perform under the Purchase Agreement and the Bankruptcy Court were to rule
against certain legal arguments we would raise such that the resolution of
open issues involving legal title on any remaining properties (including any
leases) does not occur, the portion of the purchase price we held back pending
consent or waiver will be retained and will be available to us for general
corporate purposes.
The
bankruptcy proceeding may prevent, frustrate or delay our ability to receive
corrective documentation from Calpine for certain properties that we bought
from
Calpine and paid for, in cases where Calpine delivered incomplete documentation,
including documentation related to certain ministerial governmental
approvals.
Certain
of the properties we purchased from Calpine and paid Calpine for on July 7,
2005, require certain additional documentation, depending on the particular
facts and circumstances surrounding the particular properties involved, such
documentation was to be delivered by Calpine to quiet title related to our
ownership of these properties following closing. Certain of these properties
are
subject to ministerial governmental action approving us as qualified assignee
and operator, even though in most cases there had been a conveyance by Calpine
and release of mortgages and liens by Calpine’s creditors. For
certain other properties, the documentation delivered by Calpine at closing
was
incomplete. While Calpine has not made a decision on whether to perform its
remaining obligations under the Purchase Agreement with us and thus perform
these required further assurances as to title, Calpine has agreed to resolve
title issues on a significant number of those properties requiring the
additional documentation to address title issues. As noted, we
reached agreement with Calpine upon and executed the PTRA on August 3, 2007,
subject to Bankruptcy Court approval, without prejudice to the other pending
claims, disputes and defenses between them. Among other obligations
and rights of the parties under PTRA, Calpine has provided documents to resolve
legal title issues as to certain previously purchased oil and gas properties
located in the Gulf of Mexico, California and Wyoming
(“Properties”). We anticipate that the Bankruptcy Court will address
Calpine’s to-be-filed request for approval of the PTRA in a hearing scheduled
for September 11, 2007. The PTRA does not address the Non-Consent
Properties which Calpine withheld from the July 2005 closing due to lack of
lessor consents determined at that time (in many instances mistakenly) as
needed for transfer and for which we withheld approximately $75 million of
the purchase price.
We
have expended and may continue to expend significant resources in connection
with Calpine’s bankruptcy.
We
have
expended and may continue to expend significant resources in connection with
Calpine’s bankruptcy. These resources include our increased costs for
lawyers, consultant experts and related expenses, as well as lost opportunity
costs associated with our dedicating internal resources to these
matters. If we continue to expend significant resources and our
management is distracted from the operational matters by the Calpine bankruptcy,
our business, results of operations, financial position or cash flows could
be
adversely affected.
Item
2.
|
Unregistered
Sales of Equity Securities and Use of
Proceeds
|
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers for the three
months ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Number of
|
|
|
Maximum
Number (or
|
|
|
|
|
|
|
|
|
|
Shares
Purchased
|
|
|
Approximate
Dollar Value)
|
|
|
|
|
|
|
|
|
|
as
Part of Publicly
|
|
|
of
Shares that May yet Be
|
|
|
|
Total
Number of
|
|
|
Average
Price
|
|
|
Announced
Plans
|
|
|
Purchased
Under the Plans
|
|
Period
|
|
Shares
Purchased (1)
|
|
|
Paid
per Share
|
|
|
or
Programs
|
|
|
or
Programs
|
|
April
1 - April 30
|
|
|
82
|
|
|
$ |
22.07
|
|
|
|
-
|
|
|
|
-
|
|
May
1 - May 31
|
|
|
1,413
|
|
|
|
23.01
|
|
|
|
-
|
|
|
|
-
|
|
June
1 - June 30
|
|
|
835
|
|
|
|
24.35
|
|
|
|
-
|
|
|
|
-
|
|
(1)
|
All
of the shares repurchased were surrendered by employees to pay tax
withholding upon the vesting of restricted stock awards. These
repurchases were not part of a publicly announced program to repurchase
shares of our common stock, nor do we have a publicly announced program
to
repurchase shares of our common
stock.
|
Issuance
of Unregistered Securities
None.
Item
3.
|
Defaults
Upon Senior
Securities
|
None.
Item
4.
|
Submission
of Matters to a Vote of Security
Holders
|
On
May
15, 2007, we held our Annual Meeting of Shareholders. At the meeting,
shareholders voted on election of all of our directors to serve until the next
annual meeting of shareholders. The following is a summary of the
votes on this item:
|
Votes
For
|
Votes
Withheld
|
B.A.
"Bill" Berilgen (1)
|
46,354,693
|
771,204
|
Richard
W. Beckler
|
44,417,081
|
2,708,316
|
Donald
D. Patteson, Jr.
|
46,269,282
|
856,615
|
D.
Henry Houston (1)
|
44,415,131
|
2,708,516
|
G.
Louis Graziadio, III
|
37,861,923
|
9,263,474
|
Josiah
O. Low, III
|
46,416,241
|
709,156
|
(1)
In
July 2007, Chairman, President and Chief Executive Officer (“CEO”) B.A. Berilgen
resigned. The Company’s Executive Vice President, Charles F.
Chambers, is serving as acting President and CEO. D. Henry Houston,
chair of our Audit Committee and current director, has been named Chairman
of the Board and will lead the Board in the search for a permanent President
and
CEO. We have not filled the vacancy on the Board caused by
Mr. Berilgen’s resignation.
Rosetta
reported on Form 8-K during the
quarter covered by this report all information required to be reported on such
form.
|
31.1
|
Certification
of Periodic Financial Reports by Charles F. Chambers in satisfaction
of
Section 302 of the Sarbanes-Oxley Act of
2002
|
|
31.2
|
Certification
of Periodic Financial Reports by Michael J. Rosinski in satisfaction
of
Section 302 of the Sarbanes-Oxley Act of
2002
|
|
32.1
|
Certification
of Periodic Financial Reports by Charles F. Chambers and Michael
J.
Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act
of 2002
and 18 U.S.C. Section 1350
|
Pursuant
to the requirements 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.
|
ROSETTA
RESOURCES INC.
|
|
|
By:
|
/s/
MICHAEL J. ROSINSKI
|
|
|
Michael
J. Rosinski
|
|
|
Executive
Vice President and Chief Financial Officer
|
|
|
|
|
|
(Duly
Authorized Officer and Principal Financial Officer)
|
|
Date:
August 13, 2007
ROSETTA
RESOURCES INC.
Exhibit
Number
|
|
Description
|
|
|
Certification
of Periodic Financial Reports by Charles F. Chambers in satisfaction
of
Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
Certification
of Periodic Financial Reports by Michael J. Rosinski in satisfaction
of
Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
Certification
of Periodic Financial Reports by Charles F. Chambers and Michael
J.
Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act
of 2002
and 18 U.S.C. Section 1350
|