- Quarterly Report (10-Q)

PLAINS EXPLORATION & PRODUCTION COMPANY

Date: August 6, 2009

/s/ Winston M. Talbert

Winston M. Talbert

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

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, 2009

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31470

PLAINS EXPLORATION & PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)

Delaware

33-0430755

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 579-6000

(Registrant’s telephone number, including area code)

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer x		Accelerated filer ¨

Non-accelerated filer ¨		Smaller reporting company ¨
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

122.0 million shares of Common Stock, $0.01 par value, issued and outstanding at July 31, 2009.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION

ITEM 1 . Unaudited Consolidated Financial Statements:


Consolidated Balance Sheets June 30, 2009 and December 31, 2008		1

Consolidated Statements of Income For the three months ended and six months ended June 30, 2009 and 2008		2

Consolidated Statements of Cash Flows For the six months ended June 30, 2009 and 2008		3

Consolidated Statement of Stockholders’ Equity For the six months ended June 30, 2009		4

Notes to Consolidated Financial Statements		5

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28

ITEM 3. Quantitative and Qualitative Disclosures About Market Risks		41

ITEM 4. Controls and Procedures		42

PART II. OTHER INFORMATION		43

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)


	June 30, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	455,845		$	311,875
Accounts receivable		175,875			175,896
Commodity derivative contracts		138,457			945,838
Inventories		19,718			23,368
Other current assets		35,775			19,464

		825,670			1,476,441


Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		7,808,889			7,106,785
Not subject to amortization		2,606,628			2,513,424
Other property and equipment		120,350			110,990

		10,535,867			9,731,199
Less allowance for depreciation, depletion, amortization and impairment		(5,391,935	)		(5,217,803	)

		5,143,932			4,513,396

Goodwill		535,265			535,265

Commodity Derivative Contracts		852			530,181

Other Assets		58,338			56,632

	$	6,564,057		$	7,111,915

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	350,542		$	363,713
Royalties and revenues payable		73,532			87,874
Interest payable		34,528			20,843
Income taxes payable		—			102,948
Deferred income taxes		91,385			285,426
Other current liabilities		114,234			132,841

		664,221			993,645

Long-Term Debt		2,024,129			2,805,000

Other Long-Term Liabilities
Asset retirement obligation		166,429			159,473
Other		45,125			32,061

		211,554			191,534

Deferred Income Taxes		955,124			744,456

Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common stock, $0.01 par value, 250.0 million shares authorized, 126.7 million and 112.9 million shares issued at June 30, 2009 and December 31, 2008, respectively		1,267			1,129
Additional paid-in capital		2,987,761			2,739,625
Retained earnings (deficit)		(36,254	)		(85,101	)
Accumulated other comprehensive income (loss)		—			(684	)
Treasury stock, at cost, 4.7 million shares and 5.3 million shares at June 30, 2009 and December 31, 2008, respectively		(243,745	)		(277,689	)

		2,709,029			2,377,280

	$	6,564,057		$	7,111,915

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Revenues
Oil sales	$	219,589		$	545,767		$	376,203		$	1,002,351
Gas sales		58,541			182,334			129,805			346,403
Other operating revenues		551			4,602			1,185			7,026

		278,681			732,703			507,193			1,355,780

Costs and Expenses
Production costs
Lease operating expenses		63,404			85,248			134,288			159,756
Steam gas costs		10,912			40,599			26,469			72,757
Electricity		12,368			10,661			23,310			22,298
Production and ad valorem taxes		10,457			24,181			22,078			50,409
Gathering and transportation expenses		8,671			2,462			15,318			10,951
General and administrative		37,554			45,203			74,647			85,131
Depreciation, depletion and amortization		90,822			130,749			178,936			271,602
Accretion		3,556			3,223			7,087			6,610
Legal settlement recovery		(87,272	)		—			(87,272	)		—
Other operating expenses		1,499			—			5,956			—

		151,971			342,326			400,817			679,514

Income from Operations		126,710			390,377			106,376			676,266
Other Income (Expense)
Gain on sale of assets		—			—			—			34,658
Interest expense		(15,935	)		(23,511	)		(37,932	)		(54,120	)
Debt extinguishment costs		(667	)		—			(10,910	)		(10,263	)
Loss on mark-to-market derivative contracts		(89,717	)		(51,427	)		(1,578	)		(60,908	)
Other income		899			1,686			192			1,661

Income Before Income Taxes		21,290			317,125			56,148			587,294
Income tax benefit (expense)
Current		43,730			(61,716	)		(12,061	)		(102,253	)
Deferred		(21,371	)		(52,491	)		4,760			(118,622	)

Net Income	$	43,649		$	202,918		$	48,847		$	366,419

Earnings per Share
Basic	$	0.37		$	1.88		$	0.43		$	3.33
Diluted	$	0.37		$	1.84		$	0.43		$	3.27
Weighted Average Shares Outstanding
Basic		118,145			107,707			112,979			109,939

Diluted		118,798			110,138			113,541			112,147

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)


	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	48,847		$	366,419
Items not affecting cash flows from operating activities
Gain on sale of assets		—			(34,658	)
Depreciation, depletion, and amortization		178,936			271,602
Accretion		7,087			6,610
Deferred income tax (benefit) expense		(4,760	)		118,622
Debt extinguishment costs		10,910			10,263
Loss on mark-to-market derivative contracts		1,578			60,908
Noncash compensation		32,566			40,451
Other noncash items		2,913			2,886
Change in assets and liabilities from operating activities
Accounts receivable and other assets		22,667			(99,046	)
Accounts payable and other liabilities		(15,130	)		(76,847	)
Stock appreciation rights		(305	)		(58,357	)
Income taxes receivable/payable and prepaid		(143,619	)		509

Net cash provided by operating activities		141,690			609,362

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(826,961	)		(441,123	)
Acquisition of oil and gas properties		—			(331,293	)
Acquisition of Pogo Producing Company		—			(74,844	)
Proceeds from sales of oil and gas properties and related assets, net of costs and expenses		—			1,717,781
Derivative settlements		1,380,322			(29,593	)
Decrease in restricted cash		—			59,092
Additions to other property and equipment		(9,360	)		(27,443	)
Other		—			(1,229	)

Net cash provided by investing activities		544,001			871,348

CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		2,240,090			4,237,756
Repayments		(3,545,090	)		(5,831,756	)
Proceeds from issuance of Senior Notes		523,099			400,000
Cost incurred in connection with financing arrangements		(12,114	)		(6,064	)
Derivative settlements		1,392			(13,088	)
Issuance of common stock		250,874			—
Purchase of treasury stock		—			(304,192	)
Other		28			13,682

Net cash used in financing activities		(541,721	)		(1,503,662	)

Net increase (decrease) in cash and cash equivalents		143,970			(22,952	)
Cash and cash equivalents, beginning of period		311,875			25,446

Cash and cash equivalents, end of period	$	455,845		$	2,494

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)


	Common Stock			Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Treasury Stock					Total
	Shares	Amount		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Shares		Amount			Total
Balance at December 31, 2008	112,874	$	1,129	$	2,739,625		$	(85,101	)	$	(684	)	(5,283	)	$	(277,689	)	$	2,377,280
Net income	—		—		—			48,847			—		—			—			48,847
Issuance of common stock	13,800		138		250,736			—			—		—			—			250,874
Restricted stock awards	—		—		31,289			—			—		—			27			31,316
Issuance of treasury stock for restricted stock awards	—		—		(33,917	)		—			—		615			33,917			—
Other comprehensive income	—		—		—			—			684		—			—			684
Exercise of stock options and other	—		—		28			—			—		—			—			28

Balance at June 30, 2009	126,674	$	1,267	$	2,987,761		$	(36,254	)	$	—		(4,668	)	$	(243,745	)	$	2,709,029

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Organization and Significant Accounting Policies

The accompanying consolidated financial statements of Plains Exploration & Production Company, a Delaware corporation (“PXP”, “us”, “our” or “we”), include the accounts of all its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated.

Certain reclassifications have been made to prior year statements to conform to the current year presentation. All adjustments, consisting only of normal recurring adjustments that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. The results of our operations for the six months ended June 30, 2009 are not necessarily indicative of the results to be expected for the full year.

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements and should be read in conjunction with the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2008.

We are an independent energy company that is engaged in the “upstream” oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are primarily located in the United States. We also have interests in an exploration prospect offshore Vietnam.

Asset Retirement Obligation . The following table reflects the changes in our asset retirement obligation during the six months ended June 30, 2009 (in thousands):


Asset retirement obligation - December 31, 2008	$	169,809
Settlements		(1,895	)
Accretion expense		7,087
Additions		1,074

Asset retirement obligation - June 30, 2009 ⁽¹⁾	$	176,075

⁽¹⁾

$9.7 million is included in other current liabilities.

Earnings Per Share. For the three and six months ended June 30, 2009 and 2008 the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):


	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008	2009	2008
Weighted average common shares outstanding - basic	118,145	107,707	112,979	109,939
Unvested restricted stock, restricted stock units and stock options	653	2,431	562	2,208

Weighted average common shares outstanding - diluted	118,798	110,138	113,541	112,147

In the three and six months ended June 30, 2009, 3.0 million and 3.2 million restricted stock units, respectively, were excluded in computing diluted earnings per share because they were antidilutive due to the impact of the unrecognized compensation cost on the calculation of assumed proceeds in the application of the treasury stock method. In computing earnings per share, no adjustments were made to reported net income.

Inventories . Oil inventories are carried at the lower of the cost to produce or market value, and materials and supplies inventories are stated at the lower of cost or market with cost determined on an average cost method. At June 30, 2009 and December 31, 2008, inventories consisted of (in thousands):


	June 30, 2009		December 31, 2008
Oil	$	6,224	$	6,689
Materials and supplies		13,494		16,679

	$	19,718	$	23,368

Impairment of oil and gas properties. Under the SEC’s full cost accounting rules for oil and gas activities, we review the carrying value of our proved oil and gas properties each quarter. Under these rules, capitalized costs of oil and gas properties (net of accumulated depreciation, depletion, amortization and impairment and related deferred income taxes) may not exceed a “ceiling” equal to:

•

the present value discounted at 10% of estimated future net cash flows from proved oil and gas reserves, net of estimated future income taxes; plus

•

the lower of cost or fair value of unproved properties not included in the costs being amortized (net of related tax effects).

These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts that qualify and are designated for hedge accounting treatment. None of our derivative contracts were designated as hedges during 2008 or 2009. The rules require an impairment if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time.

During the fourth quarter of 2008, oil and gas prices declined significantly and we recorded an impairment of our oil and gas properties related to our year-end ceiling test. At June 30, 2009 and March 31, 2009, the ceiling with respect to our oil and gas properties exceeded the net capitalized costs of those properties by approximately 28% and 4%, respectively, and we did not record an impairment. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline in the future, additional impairments of our oil and gas properties could occur. Impairments required by these rules do not impact our cash flows from operating activities.

Goodwill. In a purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed, including deferred income taxes recorded in connection with the transaction, over the fair value of the net assets acquired. At June 30, 2009, goodwill totaled $535.3 million and represented approximately 8% of our total assets.

We account for goodwill in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 142, Goodwill and Other Intangible Assets (“SFAS 142”). Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. A two-step impairment test is used to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized, if any. The first step of the goodwill impairment test compares the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired, thus the second step of the impairment test is unnecessary.

The second step of the goodwill impairment test, used to measure the amount of impairment loss, compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. If the carrying amount of that reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of goodwill.

As discussed above, we follow the full cost method of accounting for oil and gas activities and all of our producing properties are located in the United States. We have determined that for the purpose of performing an impairment test in accordance with SFAS 142, we have one reporting unit. SFAS 142 states that quoted market prices in active markets are the best evidence of fair value and should be used as the basis for the fair value measurement, if available. Accordingly, we use the quoted market price of our common stock as a starting point in determining the fair value of our reporting unit.

We perform our goodwill impairment test annually as of December 31. We also perform interim impairment tests if events occur or circumstances change that would indicate the fair value of our reporting unit may be below its carrying amount. Due to the adverse market conditions that continued to have a pervasive impact on the U.S. business climate in the first quarter of 2009, we performed an interim goodwill impairment test as of March 31, 2009. In determining the fair value of our reporting unit in the first step of the goodwill impairment test, we applied a control premium to the quoted market price of our common stock, and we concluded that our goodwill was not impaired as of that date. We determined the control premium through reference to control premiums in merger and acquisition transactions for our industry and other comparable industries. If the price of our common stock declines, we could have an impairment of our goodwill in future periods.

An impairment of goodwill could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders’ equity.

Stock-Based Compensation. Stock-based compensation for the three and six months ended June 30, 2009 and 2008 was (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Stock-based compensation included in:
General and administrative expense	$	15,397	$	20,571	$	29,914	$	32,316
Lease operating expenses		2,671		7,807		2,652		8,135
Oil and natural gas properties		4,872		8,704		8,272		11,543

Total stock-based compensation	$	22,940	$	37,082	$	40,838	$	51,994

During the first six months of 2009, we granted 1.3 million restricted stock units at an average fair value of $22.27 per share and 836 thousand stock appreciation rights with an average exercise price of $21.15 per share.

Comprehensive Income. Other comprehensive income for the three and six months ended June 30, 2009 and 2008 consisted of (in thousands):


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
Net Income	$	43,649	$	202,918		$	48,847	$	366,419
Other Comprehensive Income
Pension liability adjustment, net of tax benefit		678		(23	)		684		(47	)

Comprehensive Income	$	44,327	$	202,895		$	49,531	$	366,372

When we acquired Pogo Producing Company on November 6, 2007, we assumed responsibility for a defined benefit pension plan for Pogo employees. In May 2009, we made final lump sum distributions and annuity purchases in settlement of the plan’s obligations and cleared the remaining balance in accumulated other comprehensive income.

Recent Accounting Pronouncements . In December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which is effective January 1, 2010 for reporting 2009 oil and gas reserve information. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure also requires companies to include nontraditional resources such as oil sands, shale, coalbeds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently the SEC requires that reserve volumes are determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the prior twelve-month period rather than year-end prices. The twelve-month average price will also be used for purposes of calculating future net cash flows from proved oil and gas reserves for the SEC full cost ceiling limitations, and the results will not be subject to a single day pricing mechanism. Although the Financial Accounting Standards Board (“FASB”) currently requires the price on the last day of the reporting period to be used for accounting purposes, the FASB has added it to their agenda to conform with the SEC. The new requirements also will allow companies to disclose their probable and possible reserves to investors and will require companies to report the independence and qualifications of their reserve preparer or auditor. We will adopt the provisions of the release as of December 31, 2009 for our 2009 Annual Report on Form 10-K. We are currently evaluating the impact of the release.

In April 2009, the FASB issued FASB Staff Position (“FSP”) FAS 157-4 Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”) and FSP FAS 107-1 and APB 28-1 Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). These FSPs are effective for interim reporting periods ending after June 15, 2009, with early adoption permitted; however, early adoption requires that the FSPs are adopted concurrently.

We early adopted these FSPs effective January 1, 2009, and the FSPs did not have a material impact on our consolidated financial position, results of operations or cash flows:

•

FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157, Fair Value Measurements (“SFAS 157”), when the volume and level of activity for the asset or liability have significantly decreased, as well as guidance for identifying circumstances that indicate a transaction is not orderly. This FSP emphasizes that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date under current market conditions.

•

FSP FAS 107-1 and APB 28-1 amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments , to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28, Interim Financial Reporting , to require those disclosures in summarized financial information at interim reporting periods.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS 165”) , which establishes principles and requirements for subsequent events. This statement defines the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, and the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements. SFAS 165 also sets forth the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 is effective for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 did not have an impact on our consolidated financial position, results of operations or cash flows. We have evaluated events or transactions through August 6, 2009, in conjunction with our preparation of these financial statements.

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation (“FIN”) No. 46(R) (“FIN 46(R)”), (“SFAS 167”) . The amendments include: (1) the elimination of the exemption for qualifying special purpose entities, (2) a new approach for determining who should consolidate a variable-interest entity, and (3) changes to when it is necessary to reassess who should consolidate a variable-interest entity. This statement is effective for fiscal years beginning after November 15, 2009, and for interim periods within that first annual reporting period. We are currently evaluating the impact of the standard.

Note 2—Long-Term Debt

At June 30, 2009 and December 31, 2008, long-term debt consisted of (in thousands):


	June 30,		December 31,
	2009		2008
Senior revolving credit facility	$	—	$	1,305,000
7 ³ / ₄ % Senior Notes due 2015		600,000		600,000
10% Senior Notes due 2016 (less unamortized discount of $40.9 million)		524,129		—
7% Senior Notes due 2017		500,000		500,000
7 ⁵ / ₈ % Senior Notes due 2018		400,000		400,000

	$	2,024,129	$	2,805,000

On March 13, 2009, we entered into an amendment to our senior revolving credit facility. The amendment reduced the borrowing base and commitments from $2.7 billion and $2.3 billion, respectively, to $1.5 billion. This reduction gives consideration to our derivative monetization (See Note 3 – Derivative Instruments). Our borrowing base and commitments were further reduced to $1.34 billion in recognition of our issuances of $565 million of 10% senior notes due 2016, which closed in March and April 2009 (“10% Senior Notes”). We recognized $10.9 million of debt extinguishment costs in connection with the reductions in our commitments.

In addition, the amendment increased the cost of borrowings under the facility. Amounts borrowed under our senior revolving credit facility bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 2.00% to 2.75%; (ii) the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus ¹ / 2 of 1%, and (3) the adjusted LIBOR rate plus 1%; or (iii) the over-night federal funds rate plus an additional variable amount ranging from 2.00% to 2.75% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under our senior revolving credit facility to the conforming borrowing base, and (2) our long-term debt ratings. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and our long-term debt rating and range from 2.0% to 2.75%. Commitment fees are 0.50% of the amount available for borrowing.

Our senior revolving credit facility is secured by 100% of the shares of stock in certain of our domestic and 65% of certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic oil and gas properties. Our senior revolving credit facility, as amended, contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into take-or-pay or other prepayment arrangements, merge or consolidate and enter into transactions with affiliates. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined) of no greater than 4.25 to 1.

As of June 30, 2009, we had no borrowings outstanding, $1.3 million in letters of credit outstanding and approximately $1.34 billion available for future secured borrowings under our senior revolving credit facility.

In March 2009, we issued $365 million of 10% Senior Notes due 2016, which were sold to the public at 92.373% of the face value to yield 11.625% to maturity. In April 2009, an additional $200 million of 10% Senior Notes due 2016 were sold to the public at 92.969% of the face value, plus interest accrued from March 6, 2009, to yield 11.5% to maturity. The 10% Senior Notes were issued under one indenture. We received approximately $330 million and $181 million of net proceeds, respectively, after deducting the underwriting discount, original issue discount and offering expenses. The net proceeds were used to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes, including capital expenditures. We may redeem all or part of the 10% Senior Notes on or after March 1, 2013 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to March 1, 2012 we may, at our option, redeem up to 35% of the 10% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 10% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 10% Senior Notes are general unsecured senior obligations. The 10% Senior Notes are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. The 10% Senior Notes rank senior in right of payment to all of our existing and future subordinated indebtedness; pari passu in right of payment with any of our existing and future unsecured indebtedness that is not by its terms subordinated to the 10% Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries.

Note 3—Derivative Instruments

General

We are exposed to various market risks, including volatility in oil and gas commodity prices, interest rates and foreign currency exchange rates. The level of derivative activity we engage in depends on our view of market conditions, available derivative prices and operating strategy. A variety of derivative instruments may be utilized to manage our exposure to the volatility of oil and gas commodity prices, such as swaps, collars, puts, calls and various combinations of these instruments. Currently, we do not use derivatives to manage our interest rate or foreign currency risk. Our senior notes are at fixed interest rates, and our revolving credit facility is at variable interest rates, although there are no amounts outstanding under our revolving credit facility as of June 30, 2009. Our foreign currency risk in Vietnam has been minimal due to the size of our operations.

All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized in our income statement as a gain or loss on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. We do not currently use hedge accounting for our derivative instruments.

Under SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS 149”), certain of our derivatives were deemed to contain a significant financing element. Cash settlements with respect to such derivatives are required to be reflected as financing activities in the Statement of Cash Flows. Cash settlements with respect to derivatives that are not accounted for under hedge accounting and do not have a significant financing element are reflected as investing activities in the Statement of Cash Flows.

For put options, we pay a premium to the counterparty in exchange for the sale of a put option. If the index price is below the strike price of the put option, we receive the difference between the strike price and the index price multiplied by the contract volumes less the premium. If the market price settles at or above the strike price of the put option, we pay only the option premium.

In a typical collar transaction, if the floating price based on a market index is below the floor price in the derivative contract, we receive from the counterparty an amount equal to this difference multiplied by the specified volume. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specified quantity. If we have less production than the volumes we have specified under the collar transaction when the floating price exceeds the ceiling price, we must make payments against which there are no offsetting revenues from production.

In the first quarter of 2009, we monetized our 2009 and 2010 crude oil put option contracts on 40,000 BOPD with weighted average strike prices of $106.16 per barrel and $111.49 per barrel, respectively. In addition, we terminated our crude oil swaps on 20,000 BOPD in 2009. As a result of this monetization, we received approximately $1.1 billion in net proceeds, which we used to reduce the outstanding balance on our senior revolving credit facility and for other general corporate purposes.

As of June 30, 2009, we had the following outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedging instruments:


Period	Instrument Type	Daily Volumes	Average Price ⁽¹⁾	Average Deferred Premium	Index
Sales of Crude Oil Production
2009
July - Dec	Put options	32,500 Bbls	$55.00 Strike price	$3.38 per Bbl	WTI

2010
Jan - Dec	Put options	40,000 Bbls	$55.00 Strike price	$5.00 per Bbl ⁽²⁾	WTI

Sales of Natural Gas Production
2009
July - Dec	Collars	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	$0.346 per MMBtu	Henry Hub

2010
Jan - Dec	Three-way collars ⁽³⁾	85,000 MMBtu	$6.12 Floor with a $4.64 Limit	$0.034 per MMBtu	Henry Hub
			$8.00 Ceiling

⁽¹⁾	The average strike prices do not reflect the cost to purchase the put options or collars.

⁽²⁾	In addition to the deferred premium, a premium averaging $3.86 per barrel was paid from the proceeds of our first quarter 2009 derivative monetization upon entering into these derivative contracts.

⁽³⁾	If NYMEX is less than the $6.12 per MMBtu floor, we receive the difference between NYMEX and the $6.12 per MMBtu floor up to a maximum of $1.48 per MMBtu. We pay the difference between NYMEX and $8.00 per MMBtu if NYMEX is greater than the $8.00 ceiling.

Balance Sheet

At June 30, 2009 and December 31, 2008, we had the following outstanding commodity derivative contracts, none of which were designated as hedging instruments, recorded in our consolidated balance sheets (in thousands):


		Estimated Fair Value
Instrument Type	Balance Sheet Classification	June 30, 2009		December 31, 2008
Derivative assets not designated as hedging instruments
Crude oil puts	Commodity derivative contracts - current assets	$	21,300	$	882,179
Crude oil swaps	Commodity derivative contracts - current assets		—		5,124
Natural gas collars	Commodity derivative contracts - current assets		161,017		215,391
Crude oil puts	Commodity derivative contracts - non-current assets		20,930		693,148
Natural gas collars	Commodity derivative contracts - non-current assets		1,391		—

Total derivative assets		$	204,638	$	1,795,842

The following table provides supplemental information to reconcile the fair value of our derivative assets to our consolidated balance sheets at June 30, 2009 and December 31, 2008, considering the deferred premiums and accrued interest and related settlement (payable) receivable amounts which are not included in the fair value disclosed in the table above (in thousands):


	June 30, 2009			December 31, 2008
Net fair value asset	$	204,638		$	1,795,842
Deferred premium and accrued interest on puts and collars		(102,002	)		(333,156	)
Settlement (payable) receivable		(3,294	)		13,333

Net commodity derivative asset	$	99,342		$	1,476,019


Commodity derivative contracts - current asset	$	138,457		$	945,838
Commodity derivative contracts - non-current asset		852			530,181
Commodity derivative contracts - current liability		(24,935	) ⁽¹⁾		—
Commodity derivative contracts - non-current liability		(15,032	) ⁽²⁾		—

	$	99,342		$	1,476,019

⁽¹⁾

Amount is included in other current liabilities.

⁽²⁾

Amount is included in other long-term liabilities.

We present the fair value of our derivatives on a net basis in accordance with FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts an interpretation of APB Opinion No. 10 and FASB Statement No. 105 (“FIN 39”).

Income Statement

During the three and six months ended June 30, 2009 and 2008, pre-tax amounts recognized in our consolidated statements of income were as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Loss on mark-to-market derivative contracts	$	(89,717	)	$	(51,427	)	$	(1,578	)	$	(60,908	)

Cash Payments and Receipts

During the six months ended June 30, 2009 and 2008, cash receipts (payments) for derivatives were as follows (in thousands):


	Six Months Ended June 30,
	2009		2008
Mark-to-market derivative contracts
Oil sales
Settlements	$	159,592	$	(43,108	)
Monetization of crude oil puts and swaps		1,074,361		—
Gas sales		147,761		427

	$	1,381,714	$	(42,681	)

Credit Risk

We do not require collateral or other security to support derivative instruments subject to credit risk. However, the agreements with each of the counterparties to our derivative instruments contain netting provisions within the agreements. If a default occurs under the agreements, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contracts with the amount due from the defaulting party under the derivatives contracts. As a result of the netting provisions under the agreements, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that we would incur if all the counterparties to our derivative contracts failed to perform according to the terms of the derivative contracts at June 30, 2009 is $100.5 million.

At June 30, 2009, we had the following commodity derivative net asset (liability) balances with counterparties rated by Standard & Poor’s (“S&P”) (in thousands):


S&P Rating	Fair Value ⁽¹⁾		Deferred Premium Liability		Net Asset (Liability)
AA / Negative	$	17,892	$	34,815	$	(16,923	)
AA- /Negative		5,607		324		5,283
A+ / Stable		105,355		9,839		95,516
A / Negative		75,784		57,024		18,760

	$	204,638	$	102,002	$	102,636

⁽¹⁾

The fair value is reduced by approximately $1.2 million, representing an estimate of the effect of the credit quality of our counterparties as of June 30, 2009. The fair value does not include the settlements payable of $3.3 million at June 30, 2009.

Contingent Features

The counterparties to our commodity derivative contracts consist of eight financial institutions. Our counterparties or their affiliates are generally also lenders under our senior revolving credit facility. As a result, the counterparties to our derivative agreements share in the collateral supporting our senior revolving credit facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.

Certain of our derivative agreements contain provisions that require cross defaults and acceleration of those instruments to any material debt. If we were to default on any of our material debt agreements, it would be a violation of these provisions, and the counterparties to the derivative instruments could request immediate payment on derivative instruments that are in a net liability position at that time. As of June 30, 2009, we are in a net liability position with three of the counterparties to our derivative instruments, totaling $36.1 million.

Note 4—Fair Value Measurements of Assets and Liabilities

We adopted SFAS No. 157 on January 1, 2008 for our financial assets and liabilities measured on a recurring basis. On January 1, 2009, we adopted FSP FAS 157-2 Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”) for our nonfinancial assets and liabilities, such as asset retirement obligations, goodwill and other property and equipment, which we disclose or recognize at fair value on a nonrecurring basis. As none of our assets and liabilities within the scope of this statement are impaired at the end of the second quarter and no other fair value measurements were required to be recognized on a nonrecurring basis, no additional disclosures are provided at June 30, 2009. The adoption of FSP FAS 157-2 did not have a material impact on our consolidated financial position, results of operations or cash flows. We early adopted FSP FAS 157-4 and FSP FAS 107-1 and APB 28-1 during the first quarter of 2009 as described in Note 1.

SFAS No. 157 defines fair value and establishes disclosure requirements for assets and liabilities presented at fair value on our consolidated balance sheets. Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor. SFAS No. 157 establishes a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments which are directly or indirectly observable for substantially the full term of the asset or liability. Level 3 valuations are derived from significant inputs which are unobservable.

The following table presents, for each fair value hierarchy level, our commodity derivative assets which are measured at fair value on a recurring basis as of June 30, 2009 (in thousands):


	Fair Value ⁽¹⁾		Fair Value Measurements at Reporting Date Using
	Fair Value ⁽¹⁾		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
June 30, 2009
Commodity derivative assets	$	204,638	$	—	$	42,230	$	162,408

⁽¹⁾	Option premium, interest and settlement payable are not included in the fair value of derivatives.

We estimate the fair values of our derivative instruments, including crude oil put options and natural gas collars, using an option-pricing model, which uses various inputs including NYMEX price quotations, volatilities, interest rates and contract terms. We adjust the valuations from the model for credit quality, using the counterparty’s credit quality for asset balances and our credit quality for liability balances. For asset balances, we use the credit default swap value for counterparties when available, or the spread between the risk-free interest rate and the yield on the counterparty’s publicly-traded debt for similar maturities. We consider the impact of netting agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability.

We classify derivatives that have identical assets or liabilities with quoted, unadjusted prices in active markets as Level 1. We classify our derivatives as Level 2 if the inputs used in the valuation model are directly or indirectly observable for substantially the full term of the instrument; however, if the significant inputs are not observable for substantially the full term of the instrument, we classify those derivatives as Level 3. We determine whether the market for our derivative instruments is active or inactive based on transaction volume for such instruments and classify as Level 3 those instruments that are not actively traded. For these inputs, we utilize pricing and volatility information from other instruments with similar characteristics and extrapolate data between data points for thinly traded instruments. Our crude oil put options are classified as Level 2, and our natural gas collars are classified as Level 3 instruments.

The following table presents a reconciliation of changes in fair value of financial assets and liabilities classified as Level 3 for the six months ended June 30, 2009 (in thousands):


	Six Months Ended June 30, 2009 ⁽¹⁾
Fair value at beginning of period	$	1,790,718
Realized and unrealized gains included in earnings ⁽²⁾		204,568
Purchases and settlements		(1,708,188	)
Transfers		(124,690	)

Fair value at end of period	$	162,408


Change in unrealized gains and losses relating to assets and liabilities held as of the end of the period ⁽²⁾	$	59,077

⁽¹⁾

Deferred option premiums and accrued interest are not included in the fair value of derivatives.

⁽²⁾

Realized and unrealized gains and losses included in earnings for the period are reported as loss on mark-to-market derivative contracts in our consolidated statement of income.

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, Disclosures About Fair Value of Financial Instruments (“SFAS 107”) and FSP FAS 107-1 and APB 28-1, which we early adopted effective January 1, 2009 as described in Note 1. The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value; however, certain of our derivative financial instruments have a deferred premium, including our crude oil put option contracts and natural gas collars. We offset the fair value of the derivative financial instruments by the amount of deferred premium in accordance with FIN 39.

The carrying amounts and fair values of our other financial instruments are as follows (in thousands):


	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Current Liability
Deferred premium on derivative contracts	$	65,501	$	65,501	$	170,189	$	170,189
Non-Current Liability
Deferred premium on derivative contracts		36,501		36,501		162,967		162,967
Long-Term Debt
Senior revolving credit facility		—		—		1,305,000		1,125,945
7 ³ / ₄ % Senior Notes		600,000		561,000		600,000		453,000
10% Senior Notes		565,000		580,538		—		—
7% Senior Notes		500,000		436,250		500,000		342,500
7 ⁵ / ₈ % Senior Notes		400,000		358,000		400,000		274,000

The fair value of our senior revolving credit facility as of December 31, 2008 is based on rates then available for debt instruments with similar terms and average maturities from companies with similar credit ratings in our industry. The fair value of our Senior Notes is based on quoted market prices from trades of such debt.

Note 5—Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items which are recorded in the period that the specific item occurs. For the three months ended June 30, 2009, our income tax benefit was approximately negative 105% of pre-tax income, and for the six months ended June 30, 2009, income tax expense was approximately 13% of pretax income. Variances in our estimated annual effective tax rate from the 35% federal statutory rate primarily result from the tax effects of estimated annual permanent differences, including (1) expenses that are not deductible because of Internal Revenue Service limitations, (2) the special deduction for domestic production, and (3) state income taxes. Specific items affecting our income tax benefit (expense) for both the three months and six months ended June 30, 2009 included significant changes to our balance of unrecognized tax positions and adjustments to deferred taxes for differences in certain expenses between our consolidated financial statements and tax.

In the second quarter of 2009, the IRS completed the field work related to its examination of certain of our federal income tax returns for 2000 through 2004 and issued revenue agent reports for all of these years. As a result of these second quarter events, we reduced the balance of our net unrecognized tax positions related to certain deductions and tax credits by approximately $29 million which positively impacted our net income by approximately $24 million in the second quarter. We had approximately $47.2 million of gross unrecognized tax benefits at December 31, 2008. At June 30, 2009, we had approximately $16.5 million of gross unrecognized tax benefits. If all of our unrecognized tax benefits are recognized in future periods, approximately $15.7 million will impact our effective tax rate.

For the second quarter of 2009, our current tax benefit was approximately negative 205% of pre-tax income. This unusual rate is primarily the result of a significant increase in our estimated tax deductions associated with oil and gas drilling expenditures for 2009, together with the effects of temporary differences between the book and tax recognition of income attributable to our oil and gas derivative positions.

Note 6—Commitments and Contingencies

Environmental matters . As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.

Plugging, Abandonment and Remediation Obligations. Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we receive an indemnity with respect to those costs. We cannot provide assurance that we will be able to collect on these indemnities.

In connection with the sale of certain properties offshore California in December 2004 we retained the responsibility for certain abandonment costs, including removing, dismantling and disposing of the existing offshore platforms. The present value of such abandonment costs, $42 million ($84 million undiscounted), is included in our asset retirement obligation as reflected on our consolidated balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $66 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At June 30, 2009, the escrow account had a balance of $12 million. The fair value of our guarantee at June 30, 2009 was $0.7 million and is included in other long-term liabilities in our consolidated balance sheet.

Operating risks and insurance coverage . Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, oil spills, releases of gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to additional liabilities. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.

In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. During the first half of 2009, the volatility and disruption in the financial and credit markets reached unprecedented levels, which may adversely affect the credit quality of our insurers and impact their ability to pay out claims.

Other commitments and contingencies . As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and gas properties and the marketing, transportation and storage of oil. It is management’s belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

On July 7, 2008, we acquired from a subsidiary of Chesapeake Energy Corporation, or Chesapeake, a 20% interest in Chesapeake’s Haynesville Shale leasehold as of June 30, 2008 for approximately $1.65 billion in cash. In connection with the acquisition we also agreed, over a multi-year period, to fund 50% of Chesapeake’s drilling and completion costs associated with future Haynesville Shale wells, up to an additional $1.65 billion. As of June 30, 2009 approximately $1.4 billion of this commitment remains. On February 20, 2009, we and Chesapeake entered into certain amended agreements which, among other matters, provides us with a one-time option, exercisable without further monetary obligation, between June 15, 2010 and June 30, 2010, to reduce our obligation to pay 50% of Chesapeake’s drilling and completion costs by $800 million in exchange for an assignment to Chesapeake, effective December 31, 2010, of 50% of all of our interest in the Haynesville properties. On August 5, 2009, we entered into another amendment to our agreement in which we agreed to pay $1.1 billion for the remaining commitments for future Haynesville Shale wells due to Chesapeake as of September 30, 2009, estimated at $1.25 billion (See Note 9—Subsequent Event).

As of June 30, 2009, we had four participation agreements to drill wells in the Gulf of Mexico and we are committed to drill one remaining well offshore Vietnam under our Production Sharing Contract with PetroVietnam. We have a remaining commitment of approximately $164.2 million for these projects. Additionally, we have a drilling rig commitment through December 31, 2009. The minimum commitment under this contract is approximately $4.5 million.

On November 15, 2005, the United States Court of Federal Claims issued a ruling granting the plaintiffs’ motion for summary judgment as to liability and partial summary judgment as to damages in the breach of contract lawsuit Amber Resources Company et al. v. United States, Case No. 02-30c. The court’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold 36 federal leases offshore California. The court further ruled that the Government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On October 31, 2006, the court issued an unfavorable decision on the plaintiff’s motion for partial summary judgment concerning plaintiffs’ additional claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas in the disputed lease area, and other matters. Plaintiffs filed a motion for final judgment on November 29, 2006 and the court granted such motion on January 11, 2007. Judgment on the $1 billion on 35 leases was filed January 12, 2007. The United States filed an appeal and Plaintiffs filed a cross-appeal concerning the Court’s October 31, 2006 decision. The United States Court of Appeals for the Federal Circuit affirmed on August 25, 2008 the trial courts’ judgment in all respects concluding that the lessees may recover $1 billion in lease bonuses paid. The United States filed combined petitions for rehearing and rehearing en banc in October 2008, but the United States Court of Appeals for the Federal Circuit denied the Government’s combined petitions on December 5, 2008. On December 24, 2008, the United States Court of Appeals for the Federal Circuit agreed to stay the mandate for 90 days pending consideration of the Government’s possible filing of a petition for writ of certiorari and on March 13, 2009, the Court agreed to grant a 30 day extension of such deadline. No petition for writ was filed by the deadline so all appeals have either been waived or exhausted. On April 10, 2009, Plaintiffs filed with the United States Court of Federal Claims a motion to enforce the $1 billion judgment. Oral arguments on such motion were heard on May 6, 2009.

On May 11, 2009, the United States Government certified payment of the $1 billion judgment in full to all lessees of the 35 leases. In the second quarter, we received a net recovery of $87.3 million as our share of the $1 billion award.

We are a defendant in various other lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and could have a material adverse effect on our financial position, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

Note 7—Stockholders’ Equity

During the second quarter, we sold to the public 13.8 million shares of our common stock priced at $18.70 per share and we received $250.9 million of net proceeds after deducting the underwriting discount and offering expenses. The net proceeds are being used for general corporate purposes, including future capital expenditures.

Note 8—Consolidating Financial Statements

We are the issuer of $600 million of 7 ³ / 4 % Senior Notes, $565 million of 10% Senior Notes, $500 million of 7% Senior Notes and $400 million of 7 ⁵ / ₈ % Senior Notes as of June 30, 2009, which are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries (referred to as “Guarantor Subsidiaries”). Certain of our subsidiaries do not guarantee the Senior Notes (referred to as “Non-Guarantor Subsidiaries”).

The following financial information presents consolidating financial statements, which include:

•

PXP (the “Issuer”);

•

the Guarantor Subsidiaries on a combined basis;

•

the Non-Guarantor Subsidiaries on a combined basis;

•

elimination entries necessary to consolidate the Issuer, Guarantor Subsidiaries and Non-Guarantor Subsidiaries; and

•

PXP on a consolidated basis.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

JUNE 30, 2009

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	455,090		$	12		$	743		$	—		$	455,845
Accounts receivable and other current assets		296,609			88,736			3,721			(19,241	)		369,825

		751,699			88,748			4,464			(19,241	)		825,670

Property and Equipment, at cost
Oil and natural gas properties-full cost method		3,768,263			6,605,249			42,005			—			10,415,517
Other property and equipment		48,100			35,647			36,603			—			120,350

		3,816,363			6,640,896			78,608			—			10,535,867
Less allowance for depreciation, depletion, amortization and impairment		(2,107,099	)		(4,430,877	)		(34	)		1,146,075			(5,391,935	)

		1,709,264			2,210,019			78,574			1,146,075			5,143,932

Investment in and Advances to Affiliates		3,470,051			(521,497	)		(84,032	)		(2,864,522	)		—

Other Assets		19,957			574,498			—			—			594,455

	$	5,950,971		$	2,351,768		$	(994	)	$	(1,737,688	)	$	6,564,057

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	397,912		$	279,520		$	6,030		$	(19,241	)	$	664,221
Long-Term Debt		2,024,129			—			—			—			2,024,129
Other Long-Term Liabilities		150,920			60,634			—			—			211,554
Deferred Income Taxes		668,981			(189,269	)		2,064			473,348			955,124
Stockholders’ Equity		2,709,029			2,200,883			(9,088	)		(2,191,795	)		2,709,029

	$	5,950,971		$	2,351,768		$	(994	)	$	(1,737,688	)	$	6,564,057

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2008

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	309,362		$	285		$	2,228		$	—		$	311,875
Accounts receivable and other current assets		1,045,947			161,469			1,765			(44,615	)		1,164,566

		1,355,309			161,754			3,993			(44,615	)		1,476,441

Property and Equipment, at cost
Oil and natural gas properties-full cost method		3,465,656			6,139,111			15,442			—			9,620,209
Other property and equipment		45,689			35,048			30,253			—			110,990

		3,511,345			6,174,159			45,695			—			9,731,199
Less allowance for depreciation, depletion, amortization and impairment		(2,011,763	)		(3,481,169	)		(24	)		275,153			(5,217,803	)

		1,499,582			2,692,990			45,671			275,153			4,513,396

Investment in and Advances to Affiliates		3,130,150			(152,601	)		(40,606	)		(2,936,943	)		—

Other Assets		552,498			569,580			—			—			1,122,078

	$	6,537,539		$	3,271,723		$	9,058		$	(2,706,405	)	$	7,111,915

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	758,476		$	278,375		$	1,409		$	(44,615	)	$	993,645
Long-Term Debt		2,805,000			—			—			—			2,805,000
Other Long-Term Liabilities		132,621			58,913			—			—			191,534
Deferred Income Taxes		464,162			174,991			2,527			102,776			744,456
Stockholders’ Equity		2,377,280			2,759,444			5,122			(2,764,566	)		2,377,280

	$	6,537,539		$	3,271,723		$	9,058		$	(2,706,405	)	$	7,111,915

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2009

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	181,842		$	37,747		$	—		$	—		$	219,589
Gas sales		13,044			45,497			—			—			58,541
Other operating revenues		239			312			—			—			551

		195,125			83,556			—			—			278,681

Costs and Expenses
Production costs		69,523			36,289			—			—			105,812
General and administrative		23,926			13,456			172			—			37,554
Depreciation, depletion, amortization and accretion		51,613			44,442			6			(1,683	)		94,378
Impairment of oil and gas properties		—			231,629			—			(231,629	)		—
Legal settlement recovery		(81,790	)		(5,482	)		—			—			(87,272	)
Other operating expenses		597			902			—			—			1,499

		63,869			321,236			178			(233,312	)		151,971

Income (Loss) from Operations		131,256			(237,680	)		(178	)		233,312			126,710
Other Income (Expense)
Equity in earnings of subsidiaries		77,737			(199	)		—			(77,538	)		—
Interest expense		(10,990	)		(3,402	)		(1,543	)		—			(15,935	)
Debt extinguishment costs		(667	)		—			—			—			(667	)
Loss on mark-to-market derivative contracts		(89,717	)		—			—			—			(89,717	)
Other income (expense)		990			(70	)		(21	)		—			899

Income (Loss) Before Income Taxes		108,609			(241,351	)		(1,742	)		155,774			21,290
Income tax (expense) benefit		(64,960	)		91,684			579			(4,944	)		22,359

Net Income (Loss)	$	43,649		$	(149,667	)	$	(1,163	)	$	150,830		$	43,649

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2008

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	400,971		$	144,796		$	—	$	—		$	545,767
Gas sales		15,489			166,845			—		—			182,334
Other operating revenues		296			4,306			—		—			4,602

		416,756			315,947			—		—			732,703

Costs and Expenses
Production costs		107,528			55,623			—		—			163,151
General and administrative		28,704			16,499			—		—			45,203
Depreciation, depletion, amortization and accretion		54,023			77,164			—		2,785			133,972

		190,255			149,286			—		2,785			342,326

Income from Operations		226,501			166,661			—		(2,785	)		390,377
Other Income (Expense)
Equity in earnings of subsidiaries		94,323			733			—		(95,056	)		—
Interest expense		(15,914	)		(8,136	)		—		539			(23,511	)
Loss on mark-to-market derivative contracts		(23,991	)		(27,436	)		—		—			(51,427	)
Other income		664			827			734		(539	)		1,686

Income Before Income Taxes		281,583			132,649			734		(97,841	)		317,125
Income tax (expense) benefit		(78,665	)		(36,507	)		1		964			(114,207	)

Net Income	$	202,918		$	96,142		$	735	$	(96,877	)	$	202,918

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2009

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	312,450		$	63,753		$	—		$	—		$	376,203
Gas sales		30,738			99,067			—			—			129,805
Other operating revenues		560			625			—			—			1,185

		343,748			163,445			—			—			507,193

Costs and Expenses
Production costs		146,285			75,178			—			—			221,463
General and administrative		50,865			23,433			349			—			74,647
Depreciation, depletion, amortization and accretion		104,197			84,882			10			(3,066	)		186,023
Impairment of oil and gas properties		—			867,856			—			(867,856	)		—
Legal settlement recovery		(81,790	)		(5,482	)		—			—			(87,272	)
Other operating expenses		5,054			902			—			—			5,956

		224,611			1,046,769			359			(870,922	)		400,817

Income (Loss) from Operations		119,137			(883,324	)		(359	)		870,922			106,376
Other Income (Expense)
Equity in earnings of subsidiaries		7,468			(392	)		—			(7,076	)		—
Interest expense		(18,303	)		(18,086	)		(1,543	)		—			(37,932	)
Debt extinguishment costs		(10,910	)		—			—			—			(10,910	)
Loss on mark-to-market derivative contracts		(1,578	)		—			—			—			(1,578	)
Other income (expense)		906			(681	)		(33	)		—			192

Income (Loss) Before Income Taxes		96,720			(902,483	)		(1,935	)		863,846			56,148
Income tax (expense) benefit		(47,873	)		341,006			579			(301,013	)		(7,301	)

Net Income (Loss)	$	48,847		$	(561,477	)	$	(1,356	)	$	562,833		$	48,847

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2008

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	709,076		$	293,275		$	—		$	—		$	1,002,351
Gas sales		21,161			325,242			—			—			346,403
Other operating revenues		939			6,087			—			—			7,026

		731,176			624,604			—			—			1,355,780

Costs and Expenses
Production costs		191,307			124,864			—			—			316,171
General and administrative		52,063			33,068			—			—			85,131
Depreciation, depletion, amortization and accretion		103,483			170,437			—			4,292			278,212

		346,853			328,369			—			4,292			679,514

Income from Operations		384,323			296,235			—			(4,292	)		676,266
Other Income (Expense)
Equity in earnings of subsidiaries		173,077			655			—			(173,732	)		—
Interest expense		(26,947	)		(42,253	)		—			15,080			(54,120	)
Debt extinguishment costs		(10,263	)		—			—			—			(10,263	)
Loss on mark-to-market derivative contracts		(23,557	)		(37,351	)		—			—			(60,908	)
Other income		15,562			35,179			658			(15,080	)		36,319

Income Before Income Taxes		512,195			252,465			658			(178,024	)		587,294
Income tax expense		(145,776	)		(78,471	)		(3	)		3,375			(220,875	)

Net Income	$	366,419		$	173,994		$	655		$	(174,649	)	$	366,419

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2009

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	48,847		$	(561,477	)	$	(1,356	)	$	562,833		$	48,847
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		104,197			952,738			10			(870,922	)		186,023
Equity in earnings of subsidiaries		(7,468	)		392			—			7,076			—
Deferred income tax benefit		(32,932	)		(341,821	)		(579	)		370,572			(4,760	)
Debt extinguishment costs		10,910			—			—			—			10,910
Loss on mark-to-market derivative contracts		1,578			—			—			—			1,578
Noncash compensation		27,359			5,207			—			—			32,566
Other noncash items		2,796			46			71			—			2,913
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(16,777	)		41,392			(1,948	)		—			22,667
Accounts payable and other liabilities		4,619			(19,929	)		180			—			(15,130	)
Stock appreciation rights		(305	)		—			—			—			(305	)
Income taxes receivable/payable and prepaid		(143,619	)		—			—			—			(143,619	)

Net cash (used in) provided by operating activities		(795	)		76,548			(3,622	)		69,559			141,690


CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(362,986	)		(441,773	)		(22,202	)		—			(826,961	)
Derivative settlements		1,380,322			—			—			—			1,380,322
Additions to other property and equipment		(2,411	)		(600	)		(6,349	)		—			(9,360	)

Net cash provided by (used in) investing activities		1,014,925			(442,373	)		(28,551	)		—			544,001


CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		2,240,090			—			—			—			2,240,090
Repayments		(3,545,090	)		—			—			—			(3,545,090	)
Proceeds from issuance of Senior Notes		523,099			—			—			—			523,099
Cost incurred in connection with financing arrangements		(12,114	)		—			—			—			(12,114	)
Derivative settlements		1,392			—			—			—			1,392
Issuance of common stock		250,874			—			—			—			250,874
Investment in and advances to affiliates		(326,681	)		365,552			30,688			(69,559	)		—
Other		28			—			—			—			28

Net cash (used in) provided by financing activities		(868,402	)		365,552			30,688			(69,559	)		(541,721	)

Net increase (decrease) in cash and cash equivalents		145,728			(273	)		(1,485	)		—			143,970
Cash and cash equivalents, beginning of period		309,362			285			2,228			—			311,875

Cash and cash equivalents, end of period	$	455,090		$	12		$	743		$	—		$	455,845

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2008

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	366,419		$	173,994		$	655		$	(174,649	)	$	366,419
Items not affecting cash flows from operating activities
Gain on sale of assets		—			(34,658	)		—			—			(34,658	)
Depreciation, depletion, amortization and accretion		103,483			170,437			—			4,292			278,212
Equity in earnings of subsidiaries		(173,077	)		(655	)		—			173,732			—
Deferred income tax expense		102,801			19,758			—			(3,937	)		118,622
Debt extinguishment costs		10,263			—			—			—			10,263
Loss on mark-to-market derivative contracts		23,557			37,351			—			—			60,908
Noncash compensation		25,495			14,992			(36	)		—			40,451
Other noncash items		1,499			1,711			(324	)		—			2,886
Change in assets and liabilities from operating activities
Accounts receivable and other assets		11,474			(113,881	)		3,361			—			(99,046	)
Accounts payable and other liabilities		(26,545	)		(49,366	)		(936	)		—			(76,847	)
Stock appreciation rights		(58,357	)		—			—			—			(58,357	)
Income taxes receivable/payable		509			—			—			—			509

Net cash provided by operating activities		387,521			219,683			2,720			(562	)		609,362


CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(165,483	)		(270,576	)		(5,064	)		—			(441,123	)
Acquisition of oil and gas properties		—			(406,137	)		—			—			(406,137	)
Proceeds from sales of oil and gas properties and related assets, net of costs and expenses		1,717,781			—			—			—			1,717,781
Derivative settlements		(29,593	)		—			—			—			(29,593	)
Decrease in restricted cash		—			59,092			—			—			59,092
Other		(20,200	)		(676	)		(7,796	)		—			(28,672	)

Net cash provided by (used in) investing activities		1,502,505			(618,297	)		(12,860	)		—			871,348


CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		4,237,756			—			—			—			4,237,756
Repayments		(5,831,756	)		—			—			—			(5,831,756	)
Proceeds from issuance of Senior Notes		400,000			—			—			—			400,000
Derivative settlements		(13,088	)		—			—			—			(13,088	)
Purchase of treasury stock		(304,192	)		—			—			—			(304,192	)
Investment in and advances to affiliates		(402,498	)		396,718			5,218			562			—
Other		7,960			(342	)		—			—			7,618

Net cash (used in) provided by financing activities		(1,905,818	)		396,376			5,218			562			(1,503,662	)


Net decrease in cash and cash equivalents		(15,792	)		(2,238	)		(4,922	)		—			(22,952	)
Cash and cash equivalents, beginning of period		15,897			2,261			7,288			—			25,446

Cash and cash equivalents, end of period	$	105		$	23		$	2,366		$	—		$	2,494

Note 9 — Subsequent Event

On August 6, 2009, we announced an amendment to the joint venture agreement with Chesapeake that accelerates the payment of our remaining commitment to fund 50% of Chesapeake’s share of drilling and completion costs for future Haynesville Shale wells, which we refer to as the Haynesville Carry. In an amendment to the Haynesville Shale participation agreement, we agree to pay $1.1 billion for the remaining Haynesville Carry balance due to Chesapeake as of September 30, 2009, estimated at $1.25 billion. This payment represents an approximate 12% reduction in the total amount due. Additionally, Chesapeake has committed to drill at least 150 wells per year under the participation agreement for the three year period starting October 1, 2009. Further, we have agreed to terminate our one-time option exercisable in June of 2010 to avoid paying the last $800 million of the Haynesville Carry in exchange for an assignment to Chesapeake of 50% of our interest in our Haynesville acreage. Closing of the transaction is expected to occur September 29, 2009.

ITEM 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report and our Form 10-K for the year ended December 31, 2008.

Company Overview

We are an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas properties in the United States. Our core areas of operations are:

•

Onshore California;

•

Offshore California;

•

the Gulf of Mexico;

•

the Gulf Coast Region;

•

the Mid-Continent Region; and

•

the Rocky Mountains.

We also have an interest in an exploration prospect offshore Vietnam.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on derivative contracts on our income statement as changes occur in the NYMEX price indices. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. See Item 3 – Quantitative and Qualitative Disclosures About Market Risks.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. Our primary sources of liquidity are cash generated from our operations, our cash balances, our senior revolving credit facility and periodic public offerings of debt and equity. At June 30, 2009, we had approximately $1.34 billion available for future secured borrowings under our senior revolving credit facility and $455.8 million in cash and cash equivalents. We believe that we have sufficient liquidity through our forecasted cash flow from operations, cash balances, projected cash settlements from our derivative contracts and borrowing capacity under our senior revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies and anticipated capital expenditures.

Capital and Credit Markets

During the first half of 2009, the extreme volatility and disruption in the capital and credit markets continued to exist. The volatility and disruption have created conditions that may adversely affect the financial condition of the lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, our insurers and our oil and gas purchasers. See Liquidity and Capital Resources.

Recent Developments

Haynesville Shale Joint Venture

Derivatives

In the first quarter of 2009, we monetized our 2009 and 2010 crude oil put option contracts on 40,000 BOPD with weighted average strike prices of $106.16 per barrel and $111.49 per barrel, respectively. In addition, we terminated our crude oil swaps on 20,000 BOPD in 2009. As a result of this monetization, we received approximately $1.1 billion in net proceeds, which we used to reduce the outstanding balance on our senior revolving credit facility and for other general corporate purposes.

Legal Settlement Recovery

On May 11, 2009, the United States Government certified payment of the $1 billion judgment in full to all lessees of the 35 leases involved in the lawsuit Amber Resources Company et al. v. United States, Case No. 02-30c. In the second quarter, we received a net recovery of $87.3 million as our share of the $1 billion award.

General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter to determine a ceiling value of our properties. The rules require an impairment if our capitalized costs exceed the allowed “ceiling.” During the fourth quarter of 2008, oil and gas prices declined significantly, and we recorded an impairment of our oil and gas properties related to our year-end ceiling test. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline in the future, additional impairment of our oil and gas properties could occur. Impairment charges required by these rules do not impact our cash flows from operating activities.

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities (including stock-based compensation), steam gas costs, electricity costs, maintenance costs, production, ad valorem and severance taxes, and other costs necessary to operate our producing properties. Depletion of capitalized costs of producing oil and gas properties is provided using the units of production method based upon estimated proved reserves. For the purpose of computing depletion, estimated proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary.

General and administrative expenses (“G&A”) consist primarily of salaries and related benefits of administrative personnel (including stock-based compensation), office rent, systems costs and other administrative costs.

Results Overview

In the first half of 2009, we reported net income of $48.8 million, or $0.43 per diluted share, compared to net income of $366.4 million, or $3.27 per diluted share, in the first half of 2008. The decrease primarily reflects lower commodity prices.

Results of Operations

The following table reflects the components of our oil and gas production and sales prices and sets forth our operating revenues and costs and expenses on a BOE basis:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Sales Volumes
Oil and liquids sales (MBbls)		4,441		5,019		8,886		10,265
Gas (MMcf)
Production		17,972		18,232		35,607		39,598
Used as fuel		584		547		1,230		1,135
Sales		17,388		17,685		34,377		38,463
MBOE
Production		7,435		8,057		14,820		16,864
Sales		7,338		7,966		14,615		16,675
Daily Average Volumes
Oil and liquids sales (Bbls)		48,792		55,153		49,092		56,399
Gas (Mcf)
Production		197,500		200,358		196,727		217,573
Used as fuel		6,422		6,015		6,797		6,236
Sales		191,078		194,343		189,930		211,337
BOE
Production		81,710		88,546		81,880		92,662
Sales		80,638		87,543		80,747		91,622
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	59.79	$	123.80	$	51.68	$	111.12
Gas		3.50		10.90		4.17		9.50
Average Realized Sales Price Before
Derivative Transactions
Oil (per Bbl)	$	49.44	$	108.74	$	42.33	$	97.65
Gas (per Mcf)		3.37		10.31		3.77		9.01
Per BOE		37.90		91.40		34.62		80.89
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	8.64	$	10.70	$	9.19	$	9.58
Steam gas costs		1.49		5.10		1.81		4.36
Electricity		1.69		1.34		1.59		1.34
Production and ad valorem taxes		1.43		3.04		1.51		3.02
Gathering and transportation		1.18		0.31		1.05		0.66
Depreciation, depletion and amortization of oil and gas properties (“DD&A”)	$	11.49	$	15.70	$	11.49	$	15.73

Comparisons between the periods are affected by the February 2008 divestiture of 50% of our working interest in the Piceance and Permian Basins, the San Juan Basin and Barnett Shale, the April 2008 acquisition of South Texas properties and the divestiture of the remainder of our interest in the Piceance and Permian Basins effective December 1, 2008.

The following table reflects cash (payments)/receipts made with respect to derivative contracts that settled during the periods presented (in thousands):


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009		2008			2009		2008
Mark-to-market derivative contracts
Oil sales
Settlements	$	2,716	$	(20,844	)	$	159,592	$	(43,108	)
Monetization of crude oil puts and swaps		—		—			1,074,361		—
Gas sales		83,449		—			147,761		427

	$	86,165	$	(20,844	)	$	1,381,714	$	(42,681	)

Comparison of Three Months Ended June 30, 2009 to Three Months Ended June 30, 2008

Oil and gas revenues. Oil and gas revenues decreased $450.0 million, to $278.1 million for 2009 from $728.1 million for 2008 primarily due to a decrease in realized prices of $53.50 per BOE and an 8% decrease in sales volumes.

Oil revenues decreased $326.2 million to $219.6 million for 2009 from $545.8 million for 2008 reflecting lower average realized prices ($297.6 million) and lower sales volumes ($28.6 million). Our average realized price for oil decreased $59.30 to $49.44 per Bbl for 2009 from $108.74 per Bbl for 2008. The decrease is primarily attributable to a decline in the NYMEX oil price, which averaged $59.79 per Bbl in 2009 versus $123.80 per Bbl in 2008. Oil sales volumes decreased 6.4 MBbls per day to 48.8 MBbls per day in 2009 from 55.2 MBbls per day in 2008, primarily reflecting the divestments in 2008 (5.9 MBbls per day), partially offset by increased production from our Flatrock and South Texas properties.

Gas revenues decreased $123.8 million to $58.5 million in 2009 from $182.3 million in 2008 due to a decrease in realized prices ($122.8 million) and decreased sales volumes ($1.0 million). Our average realized price for gas was $3.37 per Mcf in 2009 compared to $10.31 per Mcf in 2008. Our realized price for gas decreased primarily due to a decrease in the NYMEX natural gas price, which averaged $3.50 per MMBtu in 2009 versus $10.90 per MMBtu in 2008. Gas sales volumes decreased from 194.3 MMcf per day in 2008 to 191.1 MMcf per day in 2009, primarily reflecting the divestments in 2008 (47.1 MMcf per day), partially offset by increased production from our Flatrock and Haynesville Shale properties.

Lease operating expenses . Lease operating expenses decreased $21.8 million, to $63.4 million in 2009 from $85.2 million in 2008. Excluding costs associated with the properties sold in 2008, lease operating expenses decreased by $15.9 million, primarily reflecting the implementation of our program to reduce expenses, as well as a decrease in stock-based compensation expense. On a per unit basis, lease operating expenses decreased to $8.64 per BOE in 2009 versus $10.70 per BOE in 2008 due primarily to the implementation of our cost reduction program.

Steam gas costs . Steam gas costs decreased $29.7 million, to $10.9 million in 2009 from $40.6 million in 2008, primarily reflecting the lower cost of gas used in steam generation. In 2009, we burned approximately 3.7 billion cubic feet (“Bcf”) of natural gas at a cost of approximately $2.94 per MMBtu compared to 4.2 Bcf at a cost of approximately $9.70 per MMBtu in 2008.

Electricity. Electricity increased $1.7 million, to $12.4 million in 2009 from $10.7 million in 2008, primarily reflecting an increase in usage. On a per unit basis, electricity was $1.69 per BOE in 2009 compared to $1.34 per BOE in 2008.

Production and ad valorem taxes. Production and ad valorem taxes decreased $13.7 million, to $10.5 million in 2009 from $24.2 million in 2008, primarily reflecting the divestments in 2008 and lower commodity prices.

Gathering and transportation expense. Gathering and transportation expenses increased $6.2 million, to $8.7 million in 2009 from $2.5 million in 2008, primarily reflecting an increase in production from our Haynesville Shale and Flatrock properties.

General and administrative expense . G&A expense decreased $7.6 million, to $37.6 million in 2009 from $45.2 million in 2008. The decrease is primarily due to a decrease in stock-based compensation and the implementation of a cost reduction program.

Depreciation, depletion and amortization, or DD&A. DD&A expense decreased $39.9 million, to $90.8 million in 2009 from $130.7 million in 2008. The decrease is attributable to our oil and gas depletion, primarily due to a lower per unit rate ($33.9 million) and decreased production ($7.1 million). Our oil and gas unit of production rate decreased to $11.49 per BOE in 2009 compared to $15.70 per BOE in 2008. The decrease primarily reflects the 2008 year-end impairment of our oil and gas properties, which has reduced our DD&A rate in subsequent periods.

Legal Settlement Recovery. In the second quarter, we received a net recovery of $87.3 million as our share of the $1 billion judgment for all lessees of the 35 leases involved in the lawsuit Amber Resources Company et al. v. United States, Case No. 02-30c.

Interest expense . The following table reflects our interest expense and capitalized interest for the three months ended June 30, 2009 and 2008 (in thousands):


	Three Months Ended
	June 30,
	2009			2008
Interest expense	$	45,464		$	35,561
Capitalized interest		(29,529	)		(12,050	)

Total interest expense	$	15,935		$	23,511

Interest expense decreased due to an increase in capitalized interest of $17.5 million offset by an increase in interest expense before capitalization of $9.9 million. The increase in interest expense before capitalization is attributable to a higher average interest rate associated with the 7 ⁵ / ₈ % Senior Notes issued in May 2008 and the 10% Senior Notes issued in 2009. The increase in capitalized interest is attributable to higher unevaluated property balances associated with our Haynesville Shale properties and a higher average interest rate.

Loss on mark-to-market derivative contracts . We do not currently use hedge accounting for our derivative instruments. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in our making a payment to or receiving a payment from the counterparty.

We recognized an $89.7 million loss related to mark-to-market derivative contracts in the second quarter of 2009, which was primarily associated with a decrease in the fair value of our crude oil puts due to higher crude oil prices. In the second quarter of 2008, we recognized a $51.4 million loss related to mark-to-market derivative contracts.

Income taxes. During interim periods income tax expense is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items recorded in the period that the specific item occurs. As income before income taxes changes in future quarters, our effective tax rate may increase or decrease. The variance in our estimated annual effective tax rate from the 35% federal statutory rate primarily results from the tax effects of estimated annual permanent differences, including (1) expenses that are not deductible because of Internal Revenue Service limitations, (2) the special deduction for domestic production, and (3) state income taxes.

For the second quarter of 2009, our income tax benefit was approximately negative 105% of pre-tax income. The effective tax rate of negative 105% for the quarter results primarily from changes in the relationship of 2009 estimated pre-tax income relative to estimated permanent differences together with specific items affecting income tax expense for the quarter which included a significant reduction in our balance of unrecognized tax positions. For the second quarter of 2008, income tax expense was approximately 36% of pre-tax income.

For the second quarter of 2009, our current tax benefit was approximately negative 205% of pre-tax income. This unusual rate is primarily the result of a significant increase in our estimated tax deductions associated with oil and gas drilling expenditures for 2009 together with the effects of temporary differences between the book and tax recognition of income attributable to our oil and gas derivative positions.

Comparison of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2008

Oil and gas revenues. Oil and gas revenues decreased $842.7 million, to $506.0 million for 2009 from $1.3 billion for 2008 primarily due to a decrease in realized prices of $46.27 per BOE and a 12% decrease in volumes primarily associated with our 2008 property sales.

Oil revenues decreased $626.1 million to $376.2 million for 2009 from $1.0 billion for 2008 reflecting lower average realized prices ($567.7 million) and lower sales volumes ($58.4 million). Our average realized price for oil decreased $55.32 to $42.33 per Bbl for 2009 from $97.65 per Bbl for 2008. The decrease is primarily attributable to a decrease in the NYMEX oil price, which averaged $51.68 per Bbl in 2009 versus $111.12 per Bbl in 2008. Oil sales volumes decreased 7.3 MBbls per day to 49.1 MBbls per day in 2009 from 56.4 MBbls per day in 2008, primarily reflecting the divestments in 2008 (8.0 MBbls per day), partially offset by increased production from our Flatrock and South Texas properties.

Gas revenues decreased $216.6 million to $129.8 million in 2009 from $346.4 million in 2008 due to a decrease in realized prices ($201.2 million) and decreased sales volumes ($15.4 million). Our average realized price for gas was $3.77 per Mcf in 2009 compared to $9.01 per Mcf in 2008. Our realized price for gas decreased primarily due to a decrease in the NYMEX natural gas price, which averaged $4.17 per MMBtu in 2009 versus $9.50 per MMBtu in 2008. Gas sales volumes decreased from 211.3 MMcf per day in 2008 to 189.9 MMcf per day in 2009, primarily reflecting the divestments in 2008 (65.2 MMcf per day), partially offset by increased production from our Flatrock and Haynesville Shale properties.

Lease operating expenses . Lease operating expenses decreased $25.5 million, to $134.3 million in 2009 from $159.8 million in 2008. Excluding costs associated with the properties sold in 2008, lease operating expenses decreased by $7.0 million due to lower stock-based compensation and our cost reduction program. On a per unit basis, lease operating expenses decreased to $9.19 per BOE in 2009 versus $9.58 per BOE in 2008 due primarily to lower costs in 2009.

Steam gas costs . Steam gas costs decreased $46.3 million, to $26.5 million in 2009 from $72.8 million in 2008, primarily reflecting lower cost of gas used in steam generation. In 2009, we burned approximately 7.6 Bcf of natural gas at a cost of approximately $3.49 per MMBtu compared to 8.4 Bcf at a cost of approximately $8.70 per MMBtu in 2008.

Production and ad valorem taxes. Production and ad valorem taxes decreased $28.3 million, to $22.1 million in 2009 from $50.4 million in 2008, primarily reflecting the divestments in 2008 and lower commodity prices.

Gathering and transportation expense. Gathering and transportation expenses increased $4.3 million, to $15.3 million in 2009 from $11.0 million in 2008, primarily reflecting an increase in production from our Haynesville Shale and Flatrock properties.

General and administrative expense . G&A expense decreased $10.5 million, to $74.6 million in 2009 from $85.1 million in 2008. The decrease is primarily due to a decrease in stock-based compensation and the implementation of a cost reduction program.

Depreciation, depletion and amortization, or DD&A. DD&A expense decreased $92.7 million, to $178.9 million in 2009 from $271.6 million in 2008. The decrease is attributable to our oil and gas DD&A, primarily due to a lower per unit rate ($71.5 million) and decreased production ($23.5 million). Our oil and gas unit of production rate decreased to $11.49 per BOE in 2009 compared to $15.73 per BOE in 2008. The decrease primarily reflects the 2008 year-end impairment of our oil and gas properties, which has reduced our depletion rate in subsequent periods.

Other Operating Expense. Other operating expense in 2009 consists primarily of a restocking fee related to a cancelled purchase order, a valuation adjustment for materials and supplies inventory and idle drilling equipment costs resulting from unused contract commitments.

Gain on sale of assets. In February 2008, we completed the sale to a subsidiary of Occidental Petroleum Corporation of 50% of the entity that held our investment in Collbran Valley Gas Gathering System and recorded a gain on the sale of $34.7 million.

Interest expense . The following table reflects our interest expense and capitalized interest for the six months ended June 30, 2009 and 2008 (in thousands):


	Six Months Ended
	June 30,
	2009			2008
Interest expense	$	87,165		$	83,818
Capitalized interest		(49,233	)		(29,698	)

Total interest expense	$	37,932		$	54,120

Interest expense decreased due to an increase in capitalized interest of $19.5 million offset by the increase in interest expense before capitalization of $3.4 million. The increase in interest expense before capitalization was attributable to higher interest rates associated with the 7 ⁵ / ₈ % Senior Notes issued in May 2008 and the 10% Senior Notes issued in 2009. The increase in capitalized interest is attributable to higher unevaluated property balances associated with our Haynesville Shale properties and a higher average interest rate.

Debt extinguishment costs. In connection with reductions of the commitments on our senior revolving credit facility, we recorded $10.9 million and $10.3 million of debt extinguishment costs in the six months ended June 30, 2009 and 2008, respectively.

Loss on mark-to-market derivative contracts . We do not currently use hedge accounting for our derivative instruments. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized a $1.6 million loss related to mark-to-market derivative contracts in the six months ended June 30, 2009, which was primarily associated with a decrease in the fair value of our crude oil puts due to higher crude oil prices, partially offset by higher fair value on our natural gas collars as a result of decreased gas prices. In the six months ended June 30, 2008, we recognized a $60.9 million loss related to mark-to-market derivative contracts.

Income taxes. For the six months ended June 30, 2009, our income tax expense was approximately 13% of pre-tax income. This effective tax rate of 13% for the six months results primarily from the relationship of 2009 estimated pre-tax income relative to the estimated permanent differences together with specific items affecting income tax expense for the six months which included a significant reduction in our balance of unrecognized tax positions. For the six months ended June 30, 2008, income tax expense was approximately 38% of pre-tax income.

Liquidity and Capital Resources

Liquidity is important to our operations. Our liquidity may be affected by declines in oil and gas prices, an inability to access the capital and credit markets and the success of our commodity price risk management activities, which may subject us to the credit risk of the counterparties to such agreements. This situation may arise due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions that cause substantial or extended declines in oil and gas prices.

During the first half of 2009, the extreme volatility and disruption in the capital and credit markets continued to exist. The volatility and disruption have created conditions that may adversely affect the financial condition of lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, our insurers and our oil and natural gas purchasers. While these market conditions persist, our liquidity may be adversely affected by limitations on our ability to access the capital and credit markets.

Our primary sources of liquidity are cash generated from our operations, our cash balances, our borrowing capacity under our senior revolving credit facility and periodic public offerings of debt and equity. At June 30, 2009, we had approximately $1.34 billion available for future secured borrowings under our senior revolving credit facility and $455.8 million in cash and cash equivalents. Under the terms of the senior revolving credit facility, the borrowing base will be redetermined on an annual basis, with PXP and the lenders each having the right to one annual interim unscheduled redetermination. Declines in oil and gas prices from our March 2009 redetermination may adversely affect our liquidity by lowering the amount of the borrowing base that the lenders are willing to extend.

The commitments of each lender to make loans to us are several and not joint under our senior revolving credit facility. Accordingly, if any lender fails to make loans to us, our available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the credit facility. The commitments are from a diverse syndicate of 22 lenders with no single lender’s commitment representing more than 7% of the total commitments.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisitions and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil or gas prices above the maximum amount specified in the derivative agreements. Further, we become subject to the credit risk of the counterparties to such agreements when the price of oil and natural gas decreases below the floor specified in the derivative agreement. We consider the credit quality of our counterparties when we value our commodity derivatives (See Item 3 – Quantitative and Qualitative Disclosures About Market Risk). The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy.

In the first half of 2009, we continued to strengthen our liquidity by monetizing derivatives and issuing new senior notes and shares of our common stock (See Financing Activities).

In the first quarter of 2009, we monetized our 2009 and 2010 crude oil put option contracts on 40,000 BOPD with weighted average strike prices of $106.16 per barrel and $111.49 per barrel, respectively. As a result of this monetization, we received approximately $1.1 billion in net proceeds, which we used to reduce the outstanding balance on our senior revolving credit facility and for other general corporate purposes. In connection with this monetization, we also entered into crude oil put option contracts on 40,000 BOPD in 2010. These put options have a strike price of $55 per barrel. Additionally, in separate transactions, we acquired natural gas three-way collars on 85,000 MMBtu per day for 2010. The monetization and reset arrangements accelerated cash receipts, while maintaining a hedge position that helps protect against declines in oil and natural gas prices during 2009 and 2010 (See Item 3 – Quantitative and Qualitative Disclosures About Market Risk).

In August 2009, we revised our 2009 capital budget to $1.4 billion from $1.05 billion. The increase reflects our participation in anticipated additional Haynesville Shale wells and additional acreage purchases offset by the elimination of the Haynesville Carry in the fourth quarter combined with a slower than anticipated reduction in rig rates and service costs as well as additional Gulf of Mexico exploratory drilling. Our 2009 capital budget is focused on our major development areas. Our resources will be primarily directed to the Haynesville Shale, the California long-life oil resource base, the Flatrock area development, delineation of the Friesian discovery, and high-impact Miocene and Paleogene exploration projects in the Gulf of Mexico shelf and deep water. To maximize economic returns, we are reducing operating expenses in all of our field locations and are reducing general and administrative costs throughout 2009. We continue to aggressively manage our inventory, our cost structure and our financial flexibility.

We believe that we have sufficient liquidity through our forecasted cash flow from operations, cash balances, projected settlements from our derivative contracts and borrowing capacity under our senior revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies and anticipated capital expenditures. Our senior revolving credit facility has no amounts outstanding, and the next maturity of our senior notes will occur on June 15, 2015.

Working Capital

At June 30, 2009, we had a working capital surplus of approximately $161.4 million, primarily as a result of monetizing derivatives and issuing new Senior Notes and shares of common stock (see Financing Activities). As a result of the current volatility and disruption in the capital and credit markets, we changed our cash management strategy to maintain larger cash and cash equivalents balances. Significant cash balances are invested in highly liquid money market mutual funds that consist of U.S. government securities. Our working capital is affected by fluctuations in the fair value of our commodity derivative instruments and stock appreciation rights.

Financing Activities

On March 13, 2009, we entered into an amendment to our senior revolving credit facility. The amendment reduced the borrowing base and commitments from $2.7 billion and $2.3 billion, respectively, to $1.5 billion. This reduction gives consideration to our derivative monetization (See Liquidity and Capital Resources). Our borrowing base and commitments were further reduced to $1.34 billion in recognition of the issuances of $565 million of 10% Senior Notes due 2016, which closed in March and April 2009 (“10% Senior Notes).

In addition, the amendment increased the cost of borrowings under the facility. Amounts borrowed under our senior revolving credit facility bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 2.00% to 2.75%; (ii) the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus ¹ / 2 of 1%, and (3) the adjusted LIBOR rate plus 1%; or (iii) the over-night federal funds rate plus an additional variable amount ranging from 2.00% to 2.75% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under our senior revolving credit facility to the conforming borrowing base and (2) our long-term debt ratings. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and our long-term debt rating and range from 2.0% to 2.75%. Commitment fees are 0.50% of the amount available for borrowing.

In March 2009, we issued $365 million of 10% Senior Notes due 2016, which were sold to the public at 92.373% of the face value to yield 11.625% to maturity. In April 2009, an additional $200 million of 10% Senior Notes due 2016 were sold to the public at 92.969% of the face value, plus interest accrued from March 6, 2009, to yield 11.5% to maturity. The 10% Senior Notes were issued under one indenture. We received approximately $330 million and $181 million of net proceeds respectively, after deducting the underwriting discount, original issue discount and offering expenses. The net proceeds were used to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes, including capital expenditures. We may redeem all or part of the 10% Senior Notes on or after March 1, 2013 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to March 1, 2012 we may, at our option, redeem up to 35% of the 10% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 10% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

Cash Flows


	Six Months
	Ended June 30,
	2009			2008
	(in millions)
Cash provided by (used in):
Operating activities	$	141.7		$	609.4
Investing activities		544.0			871.3
Financing activities		(541.7	)		(1,503.7	)

Net cash provided by operating activities was $141.7 million for the first half of 2009 compared to $609.4 million for the first half of 2008. The decrease primarily reflects lower operating income as a result of lower commodity prices and income tax payments in 2009 related to 2008 taxable income, partially offset by reduced production costs and the legal settlement recovery.

Net cash provided by investing activities of $544.0 million in the first half of 2009 primarily reflects derivative settlements received of $1.4 billion, partially offset by additions to oil and gas properties of $827.0 million. During the first six months of 2009, our capital expenditures were approximately $802.4 million, including capitalized interest and capitalized G&A. Additions to oil and gas properties reported in our consolidated statement of cash flows of $827.0 million differ from our capital expenditures due to the timing of payments. Net cash provided by investing activities was $871.3 million for the first six months of 2008, primarily reflecting net proceeds from property sales of $1.7 billion and a reduction in restricted cash of $59.1 million, offset by additions to oil and gas properties of $847.3 million, derivative settlements of $29.6 million, and additions to other property and equipment of $27.4 million.

Net cash used in financing activities of $541.7 million in 2009 primarily reflects the $1.3 billion net reduction in borrowings under our senior revolving credit facility; offset by net proceeds of $511.0 million from the offering of 10% Senior Notes and the $250.9 million of proceeds from our common stock offering. Net cash used in financing activities of $1.5 billion in 2008 primarily reflects the $1.6 billion net reduction in borrowings under our senior revolving credit facility and $304.2 million for treasury stock purchases, partially offset by $400 million from the issuance of the 7 ⁵ / ₈ % Senior Notes.

Critical Accounting Policies and Factors that May Affect Future Results

On January 1, 2009, we adopted the provisions of SFAS 157 for nonfinancial assets and liabilities such as asset retirement obligations, goodwill and other property and equipment, which we disclose at fair value in the financial statements on a nonrecurring basis.

For assets and liabilities that are measured at fair value on a nonrecurring basis in periods subsequent to initial recognition (for example, impaired assets), SFAS 157 requires us to disclose information that enables users of our financial statements to assess the inputs used to develop those measurements. As none of our assets and liabilities within the scope of this statement are impaired at the end of the second quarter and no other fair value measurements were required to be recognized on a nonrecurring basis, no additional disclosures are provided at June 30, 2009.

•

the present value discounted at 10% of estimated future net cash flows from proved oil and gas reserves, net of estimated future income taxes; plus

•

the lower of cost or fair value of unproved properties not included in the costs being amortized (net of related tax effects).

We account for goodwill in accordance with SFAS No. 142. Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. A two-step impairment test is used to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized, if any. The first step of the goodwill impairment test compares the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired, thus the second step of the impairment test is unnecessary.

In determining the fair value of our reporting unit in the first step of the goodwill impairment test, we applied a control premium to the quoted market price of our common stock, and we concluded that our goodwill was not impaired as of that date. We determined the control premium through reference to control premiums in merger and acquisition transactions for our industry and other comparable industries. If the price of our common stock declines, we could have an impairment of our goodwill in future periods.

An impairment of goodwill could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders’ equity.

Based on the accounting policies that we have in place, certain factors may impact our future financial results. Critical accounting policies related to oil and gas reserves, future development and abandonment costs, DD&A, commodity pricing and risk management activities, fair value and stock-based compensation are discussed in our Annual Report on Form 10-K for the year ended December 31, 2008.

Recent Accounting Pronouncements

In December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which is effective January 1, 2010 for reporting 2009 oil and gas reserve information. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure also requires companies to include nontraditional resources such as oil sands, shale, coalbeds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently the SEC requires that reserve volumes are determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the prior twelve-month period rather than year-end prices. The twelve-month average price will also be used for purposes of calculating future net cash flows from proved oil and gas reserves for the SEC full cost ceiling limitations, and the results will not be subject to a single day pricing mechanism. Although the FASB currently requires the price on the last day of the reporting period to be used for accounting purposes, the FASB has added it to their agenda to conform with the SEC. The new requirements also will allow companies to disclose their probable and possible reserves to investors and will require companies to report the independence and qualifications of their reserve preparer or auditor. We will adopt the provisions of the release as of December 31, 2009 for our 2009 Annual Report on Form 10-K. We are currently evaluating the impact of the release.

In April 2009, the FASB issued FSP FAS 157-4 Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly and FSP FAS 107-1 and APB 28-1 Interim Disclosures about Fair Value of Financial Instruments . These FSPs are effective for interim reporting periods ending after June 15, 2009, with early adoption permitted; however, early adoption requires that the FSPs are adopted concurrently.

We early adopted these FSPs effective January 1, 2009, and the FSPs did not have a material impact on our consolidated financial position, results of operations or cash flows:

•

FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157, Fair Value Measurements , when the volume and level of activity for the asset or liability have significantly decreased as well as guidance for identifying circumstances that indicate a transaction is not orderly. This FSP emphasizes that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date under current market conditions.

•

In May 2009, the FASB issued SFAS No. 165, Subsequent Events, which establishes principles and requirements for subsequent events. This statement defines the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, and the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements. SFAS 165 also sets forth the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 is effective for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 did not have an impact on our consolidated financial position, results of operations or cash flows.

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R). The amendments include: (1) the elimination of the exemption for qualifying special purpose entities, (2) a new approach for determining who should consolidate a variable-interest entity, and (3) changes to when it is necessary to reassess who should consolidate a variable-interest entity. This statement is effective for fiscal years beginning after November 15, 2009, and for interim periods within that first annual reporting period. We are currently evaluating the impact of the standard.

Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking information regarding Plains Exploration & Production Company that is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as “will”, “would”, “should”, “plans”, “likely”, “expects”, “anticipates”, “intends”, “believes”, “estimates”, “thinks”, “may”, and similar expressions, are forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, there are risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements. These factors include, among other things:

•

uncertainties inherent in the development and production of oil and gas and in estimating reserves;

•

unexpected difficulties in integrating our operations as a result of any significant acquisitions;

•

unexpected future capital expenditures (including the amount and nature thereof);

•

impact of oil and gas price fluctuations, including the impact on our reserve volumes and values and on our earnings;

•

the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences;

•

the success of our derivative activities;

•

the success of our risk management activities;

•

the effects of competition;

•

the availability (or lack thereof) of acquisition, disposition or combination opportunities;

•

the availability (or lack thereof) of capital to fund our business strategy and/or operations;

•

the impact of current and future laws and governmental regulations;

•

environmental liabilities that are not covered by an effective indemnity or insurance;

•

the ability and willingness of our current or potential counterparties to fulfill their obligations to us or to enter into transactions with us in the future; and

•

general economic, market, industry or business conditions.

All forward-looking statements in this report are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report and our other filings with the SEC. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except for any obligation to disclose material information under the federal securities laws, we do not intend to update these forward-looking statements and information. See Item 1A – Risk Factors and Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Factors That May Affect Future Results in our Annual Report on Form 10-K for the year ended December 31, 2008 for additional discussions of risks and uncertainties.

Item 3 – Quantitative and Qualitative Disclosures About Market Risks

Commodity Price Risk

Our primary market risk is oil and gas commodity prices. Historically the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized currently in our income statement as a gain or loss on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. We do not currently use hedge accounting for our derivative instruments.

See Note 3 – Derivative Instruments and Note 4 – Fair Value Measurement of Assets and Liabilities to the consolidated financial statements for a discussion of our derivative activities and fair value measurements.

As of June 30, 2009, we had the following outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedging instruments:


	Instrument	Daily	Average	Average Deferred
Period	Type	Volumes	Price ⁽¹⁾	Premium	Index
Sales of Crude Oil Production
2009
July-Dec	Put options	32,500 Bbls	$55.00 Strike price	$3.38 per Bbl	WTI

2010
Jan-Dec	Put options	40,000 Bbls	$55.00 Strike price	$5.00 per Bbl ⁽²⁾	WTI

Sales of Natural Gas Production
2009
July-Dec	Collars	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	$0.346 per MMBtu	Henry Hub
2010
Jan-Dec	Three-way collars ⁽³⁾	85,000 MMBtu	$6.12 Floor with a $4.64 Limit	$0.034 per MMBtu	Henry Hub
			$8.00 Ceiling

⁽¹⁾	The average strike prices do not reflect the cost to purchase the put options or collars.

⁽²⁾	In addition to the deferred premium, a premium averaging $3.86 per barrel was paid from the proceeds of our first quarter 2009 derivative monetization upon entering into these derivative contracts.

⁽³⁾	If NYMEX is less than the $6.12 per MMBtu floor, we receive the difference between NYMEX and the $6.12 per MMBtu floor up to a maximum of $1.48 per MMBtu. We pay the difference between NYMEX and $8.00 per MMBtu if NYMEX is greater than the $8.00 ceiling.

The fair value of outstanding crude oil and natural gas commodity derivative instruments at June 30, 2009 and the change in fair value that would be expected from a 10% price increase/decrease is shown below (in millions):


	Fair Value Asset		Effect of 10%
	Fair Value Asset		Price Increase			Price Decrease
Crude oil put options	$	42	$	(16	)	$	25
Natural gas collars		163		(23	)		20

	$	205	$	(39	)	$	45

We estimate the fair value of our derivatives using an option-pricing model, which uses various factors, including NYMEX price quotations, volatilities, interest rates and contract terms. We adjust the valuations from the model for credit quality, using the counterparty’s credit quality for asset balances and our credit quality for liability balances. For asset balances, we use the credit default swap value for counterparties, when available or the spread between the risk-free interest rate and the yield on the counterparty’s publicly-traded debt for similar maturities. We consider the impact of netting and offset provisions in the agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability. We determine whether the market for our derivative instruments is active or inactive based on transaction volume for such instruments. We value the instruments using similar instruments and by extrapolating data between data points for the thinly traded instruments.

None of our offsetting physical positions are included in the above table. Price risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price.

Our management intends to continue to maintain derivative arrangements for a portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Our derivative arrangements provide us protection on the volumes if prices decline below the prices at which these derivatives are set, but ceiling prices in our derivatives may cause us to receive less revenue on the volumes than we would receive in the absence of derivatives.

ITEM 4 – Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rules 13a-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer believe that the disclosure controls and procedures as of June 30, 2009 were effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, our internal control over financial reporting can provide only reasonable assurance with respect to our financial reporting and financial statement preparation.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1A – Risk Factors

There has been no material change to our risk factors set forth in Part I, Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008 except as set forth below.

Proposed federal legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Legislation has been proposed in the U.S. Congress to amend the Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formation to stimulate natural gas production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of natural gas and oil from many reservoirs, especially shale formations such as the Haynesville Shale. If adopted, this legislation could establish an additional level of regulation and permitting at the federal level. This additional regulation and permitting could result in additional burdens such as operational delays or increased operating costs and make it more difficult to perform hydraulic fracturing.

ITEM 4 – Submission of Matters to a Vote of Security Holders

The following items were presented for approval to stockholders of record on March 23, 2009 at the Company’s 2009 annual meeting of stockholders, held on May 7, 2009 in Houston, Texas:


		For	Against	Abstained or Withheld
(i)	Election of Directors

	James C. Flores	94,334,708	—	3,017,111
	Isaac Arnold, Jr.	96,512,666	—	839,153
	Alan R. Buckwalter, III	96,578,940	—	772,879
	Jerry L. Dees	67,287,743	—	30,064,076
	Tom H. Delimitros	71,739,795	—	25,612,024
	Thomas A. Fry, III	96,589,456	—	762,363
	Robert L. Gerry, III	95,915,589	—	1,436,230
	Charles G. Groat	96,583,395	—	768,424
	John H. Lollar	68,550,118	—	28,801,701

(ii)	Ratification of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company’s financial statements for the fiscal year ending December 31, 2009	97,154,501	117,563	79,754

Of the 107,590,547 shares of common stock issued and outstanding on March 23, 2009, the record date for the Company’s 2009 annual meeting of stockholders, 97,351,819 were present, either in person or by proxy.

ITEM 6 – Exhibits


Exhibit No.		Description

31.1*		Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Chief Executive Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Chief Financial Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema Document

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB**		XBRL Taxonomy Extension Label Linkbase Document

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document

*	Filed herewith

**	To be furnished by amendment to this report.

Items 1, 2, 3, and 5 are not applicable and have been omitted.

SIGNATURES

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.

EXHIBIT INDEX


Exhibit No.		Description

31.1*		Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Chief Executive Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Chief Financial Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema Document

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB**		XBRL Taxonomy Extension Label Linkbase Document

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document