Plains Exploration & Production 10-Q 2009 Q3 Quarterly report

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 September 30, 2009

OR

¨ 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.

Yesx    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).

Yesx    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  ¨ (Do not check if a smaller reporting company)	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

139.3 million shares of Common Stock, $0.01 par value, issued and outstanding at October 30, 2009.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
ITEM 1. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets September 30, 2009 and December 31, 2008	1
Consolidated Statements of Income For the three months ended and nine months ended September 30, 2009 and 2008	2
Consolidated Statements of Cash Flows For the nine months ended September 30, 2009 and 2008	3
Consolidated Statement of Stockholders’ Equity For the nine months ended September 30, 2009	4
Notes to Consolidated Financial Statements	5
ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
ITEM 3.Quantitative and Qualitative Disclosures About Market Risks	39
ITEM 4.Controls and Procedures	41
PART II. OTHER INFORMATION	42

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	September 30, 2009		December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	3,601	$	311,875
Accounts receivable		159,107		175,896
Commodity derivative contracts		63,913		945,838
Inventories		20,491		23,368
Prepaid expenses and other current assets		29,514		19,464
		276,626		1,476,441
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		8,661,710		7,106,785
Not subject to amortization		3,346,861		2,513,424
Other property and equipment		123,157		110,990
		12,131,728		9,731,199
Less allowance for depreciation, depletion, amortization and impairment		(5,491,734)		(5,217,803)
		6,639,994		4,513,396
Goodwill		535,265		535,265
Commodity Derivative Contracts		-		530,181
Other Assets		59,994		56,632
	$	7,511,879	$	7,111,915
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	361,041	$	363,713
Royalties and revenues payable		73,579		87,874
Interest payable		33,548		20,843
Income taxes payable		-		102,948
Deferred income taxes		131,716		285,426
Other current liabilities		126,426		132,841
		726,310		993,645
Long-Term Debt		2,493,583		2,805,000
Other Long-Term Liabilities
Asset retirement obligation		169,287		159,473
Other		34,746		32,061
		204,033		191,534
Deferred Income Taxes		926,124		744,456
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common stock, $0.01 par value, 250.0 million shares authorized, 143.9 million and 112.9 million shares issued at September 30, 2009 and December 31, 2008, respectively		1,439		1,129
Additional paid-in capital		3,400,559		2,739,625
Retained earnings (deficit)		3,072		(85,101)
Accumulated other comprehensive loss		-		(684)
Treasury stock, at cost, 4.7 million shares and 5.3 million shares at September 30, 2009 and December 31, 2008, respectively		(243,241)		(277,689)
		3,161,829		2,377,280
	$	7,511,879	$	7,111,915

See notes to consolidated financial statements.

1

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Revenues
Oil sales	$	249,619	$	528,787	$	625,822	$	1,531,138
Gas sales		62,428		181,971		192,233		528,374
Other operating revenues		141		8,779		1,326		15,805
		312,188		719,537		819,381		2,075,317
Costs and Expenses
Lease operating expenses		60,276		76,943		194,564		236,699
Steam gas costs		10,956		37,418		37,425		110,175
Electricity		10,585		14,367		33,895		36,665
Production and ad valorem taxes		7,917		27,348		29,995		77,757
Gathering and transportation expenses		10,349		4,405		25,667		15,356
General and administrative		36,419		29,374		111,066		114,505
Depreciation, depletion and amortization		101,755		139,956		280,691		411,558
Accretion		3,541		3,258		10,628		9,868
Legal recovery		-		-		(87,272)		-
Other operating (income) expense		(4,403)		-		1,553		-
		237,395		333,069		638,212		1,012,583
Income from Operations		74,793		386,468		181,169		1,062,734
Other Income (Expense)
Gain on sale of assets		-		-		-		34,658
Interest expense		(16,355)		(32,994)		(54,287)		(87,114)
Debt extinguishment costs		(1,183)		(3,138)		(12,093)		(13,401)
Gain on mark-to-market derivative contracts		14,795		451,083		13,217		390,175
Other income (expense)		569		(13,842)		761		(12,181)
Income Before Income Taxes		72,619		787,577		128,767		1,374,871
Income tax expense
Current		(21,696)		(210,023)		(33,757)		(312,276)
Deferred		(11,597)		(84,409)		(6,837)		(203,031)
Net Income	$	39,326	$	493,145	$	88,173	$	859,564
Earnings per Share
Basic	$	0.30	$	4.58	$	0.74	$	7.87
Diluted	$	0.30	$	4.50	$	0.73	$	7.72
Weighted Average Shares Outstanding
Basic		131,701		107,725		119,288		109,195
Diluted		132,725		109,617		120,003		111,297

See notes to consolidated financial statements.

2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Nine Months Ended September 30,
	2009		2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	88,173	$	859,564
Items not affecting cash flows from operating activities
Gain on sale of assets		-		(34,658)
Depreciation, depletion, and amortization		280,691		411,558
Accretion		10,628		9,868
Deferred income tax expense		6,837		203,031
Debt extinguishment costs		12,093		13,401
Gain on mark-to-market derivative contracts		(13,217)		(390,175)
Noncash compensation		47,816		38,931
Other noncash items		4,479		4,230
Change in assets and liabilities from operating activities
Accounts receivable and other assets		29,586		(65,749)
Accounts payable and other liabilities		(30,682)		(50,317)
Stock appreciation rights		(327)		(59,056)
Income taxes receivable/payable		(126,191)		206,311
Net cash provided by operating activities		309,886		1,146,939
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(1,242,698)		(688,205)
Acquisition of oil and gas properties		(1,137,142)		(2,012,969)
Payment of accrued merger costs		-		(76,645)
Proceeds from sales of oil and gas properties and related assets, net of costs and expenses		-		1,736,059
Derivative settlements		1,457,232		(36,212)
Decrease in restricted cash		-		59,092
Additions to other property and equipment		(12,167)		(34,448)
Other		162		(1,671)
Net cash used in investing activities		(934,613)		(1,054,999)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		2,315,090		11,501,352
Repayments of revolving credit facilities		(3,545,090)		(11,672,221)
Proceeds from issuance of Senior Notes		916,439		400,000
Cost incurred in connection with financing arrangements		(19,441)		(25,448)
Derivative settlements		1,392		(24,097)
Issuance of common stock		648,035		-
Purchase of treasury stock		-		(304,192)
Other		28		9,647
Net cash provided by (used in) financing activities		316,453		(114,959)
Net decrease in cash and cash equivalents		(308,274)		(23,019)
Cash and cash equivalents, beginning of period		311,875		25,446
Cash and cash equivalents, end of period	$	3,601	$	2,427

See notes to consolidated financial statements.

3

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									Shares		Amount
Balance at December 31, 2008	112,874	$	1,129	$	2,739,625	$	(85,101	)	$	(684)	(5,283	)	$	(277,689)	$	2,377,280
Net income	-		-		-		88,173			-	-			-		88,173
Issuance of common stock	31,050		310		647,725		-			-	-			-		648,035
Restricted stock awards	-		-		47,615		-			-	-			-		47,615
Issuance of treasury stock for restricted stock awards	-		-		(34,434)		-			-	624			34,448		14
Other comprehensive income	-		-		-		-			684	-			-		684
Exercise of stock options and other	-		-		28		-			-	-			-		28
Balance at September 30, 2009	143,924	$	1,439	$	3,400,559	$	3,072		$	-	(4,659)		$	(243,241)	$	3,161,829

See notes to consolidated financial statements.

4

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 nine months ended September 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 nine months ended September 30, 2009 (in thousands):

Asset retirement obligation - December 31, 2008	$	169,809
Settlements		(2,740)
Accretion expense		10,628
Additions		1,185
Asset retirement obligation - September 30, 2009(1)	$	178,882

⁽¹⁾ $9.6 million is included in other current liabilities.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008
Weighted average common shares outstanding - basic	131,701	107,725	119,288	109,195
Unvested restricted stock, restricted stock units and stock options	1,024	1,892	715	2,102
Weighted average common shares outstanding - diluted	132,725	109,617	120,003	111,297

In the three and nine months ended September 30, 2009, 2.6 million and 3.0 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.

5

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 September 30, 2009 and December 31, 2008, inventories consisted of (in thousands):

	September 30, 2009		December 31, 2008
Oil	$	5,813	$	6,689
Materials and supplies		14,678		16,679
	$	20,491	$	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 September 30, 2009, 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 22%, 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 September 30, 2009, goodwill totaled $535 million and represented approximately 7% of our total assets.

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.

6

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, we have one reporting unit. Quoted market prices in active markets are the best evidence of fair value. 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 goodwill 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 nine months ended September 30, 2009 and 2008 consisted of (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Stock-based compensation included in:
General and administrative expense	$	13,782	$	6,835	$	43,696	$	39,151
Lease operating expenses		1,468		(8,355)		4,120		(220)
Oil and natural gas properties		4,233		(2,774)		12,505		8,769
Total stock-based compensation	$	19,483	$	(4,294)	$	60,321	$	47,700

During the first nine months of 2009, we granted 1.3 million restricted stock units at an average fair value of $22.27 per share and 837 thousand stock appreciation rights with an average exercise price of $21.15 per share.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
Net income	$	39,326	$	493,145		$	88,173	$	859,564
Other comprehensive income (loss)
Pension liability adjustment, net of tax benefit		-		(23	)		684		(70	)
Comprehensive income	$	39,326	$	493,122		$	88,857	$	859,494

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 loss.

7

Recent Accounting Pronouncements.    In February 2008, the Financial Accounting Standards Board (“FASB”) issued a one-year deferral to comply with authoritative guidance that defines fair value and establishes a framework for measuring fair value of nonfinancial assets and liabilities measured on a nonrecurring basis. On January 1, 2009, we adopted this guidance for nonfinancial assets and liabilities and the adoption did not have a material impact on our consolidated financial position, results of operations or cash flows.

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. Currently, 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. We expect that the primary impact of adoption on our financial statements will be related to the use of the twelve-month average price rather than a single-day price in our reserve estimates. If the average price is higher or lower than the year-end price, we would expect our reserve estimates to be higher or lower which will have an impact on our reserve volumes and values, the full cost ceiling limitations and our oil and gas depreciation, depletion and amortization rate. We will adopt the guidance as of December 31, 2009 in our 2009 Annual Report on Form 10-K. In September 2009, the FASB issued its proposed standard on oil and gas reserve estimation and disclosure aligning its requirements with the SEC final rule.

In April 2009, the FASB issued authoritative guidance on 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. The guidance emphasizes that if there has been a significant decrease in the volume and level of activity for the asset or liability, 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. The guidance further requires disclosures, in summarized financial information, about the fair value of financial instruments for interim reporting periods of publicly traded companies. This guidance is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted. We early adopted the guidance effective January 1, 2009, and it did not have a material impact on our consolidated financial position, results of operations or cash flows.

In May 2009, the FASB issued authoritative guidance that 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. It also sets forth the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The guidance is effective for interim or annual periods ending after June 15, 2009 and our second quarter 2009 adoption did not impact our consolidated financial position, results of operations or cash flows. We have evaluated events or transactions through November 5, 2009, the date we issued our consolidated financial statements.

In June 2009, the FASB issued authoritative guidance for improving financial reporting by enterprises involved with variable-interest entities. This guidance (1) eliminates the exemption for qualifying special purpose entities, (2) includes a new approach for determining who should consolidate a variable-interest entity, and (3) presents changes as to when it is necessary to reassess who should consolidate a variable-interest entity. The guidance 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 this guidance.

In August 2009, the FASB issued authoritative guidance on fair value measurements and disclosures, specifically regarding the measurement of liabilities at fair value. This guidance provides clarification for required valuation techniques in circumstances in which a quoted price in an active market for the identical liability is not available. The guidance also states that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. Further clarification was also provided that both a quoted price for the identical liability at the measurement date and the quoted price for the identical liability when traded as an asset in an active market, in situations where no adjustments to the quoted price of the asset are required, are Level 1 fair value measurements. The guidance is effective for the first reporting period after the period of issuance. We early adopted the guidance effective third quarter 2009, and the adoption did not have a material impact on our consolidated financial position, results of operations or cash flows.

8

Note 2—Long-Term Debt

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

	September 30, 2009		December 31, 2008
Senior revolving credit facility	$	75,000	$	1,305,000
7 3/4% Senior Notes due 2015		600,000		600,000
10% Senior Notes due 2016 (less unamortized discount of $39.8 million)		525,221		-
7% Senior Notes due 2017		500,000		500,000
7 5/8% Senior Notes due 2018		400,000		400,000
8 5/8% Senior Notes due 2019 (less unamortized discount of $6.6 million)		393,362		-
	$	2,493,583	$	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 then reduced to $1.34 billion in recognition of our issuances of $565 million of 10% Senior Notes due 2016, in March and April 2009 (“10% Senior Notes”), and further reduced to $1.22 billion in recognition of our issuance of $400 million of 8 ⁵/8% Senior Notes due 2019, in September 2009 (“8 ⁵/8% Senior Notes”). During 2009, we have recognized $12.1 million of debt extinguishment costs in connection with the reductions in our borrowing base and commitments.

In addition, the amendment increased the cost of borrowings under our senior revolving credit 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 the shares of stock in 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 September 30, 2009, we had $1.3 million in letters of credit outstanding and approximately $1.14 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 discounts, original issue discount and offering expenses. We used the net proceeds 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.

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In September 2009, we issued $400 million of 8 ⁵/8% Senior Notes due 2019. The notes were sold to the public at 98.335% of the face value to yield 8.875% to maturity. We received approximately $386 million of net proceeds after deducting the underwriting discount, original issue discount and offering expenses. We used the net proceeds for general corporate purposes, including to fund a portion of the remaining drilling carry under our agreement with Chesapeake Energy Corporation (See Note 6 – Commitments and Contingencies). We may redeem all or part of the 8 ⁵/8% Senior Notes on or after October 15, 2014 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to October 15, 2012 we may, at our option, redeem up to 35% of the 8 ⁵/8% 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 8 ⁵/8% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 10% Senior Notes and 8 ⁵/8% Senior Notes are general unsecured senior obligations. They 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. These 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 and 8 ⁵/8% 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, such as swaps, collars, puts, calls and various combinations of these instruments, may be utilized to manage our exposure to the volatility of oil and gas commodity prices. Currently, we do not use derivatives to manage our interest rate or foreign currency risk. The interest rate on our senior revolving credit facility is variable, while our senior notes are fixed interest rates, thereby mitigating our interest rate risk exposure. 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.

Cash settlements with respect to derivatives, which contain a significant financing element, are 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. We may pay a premium to the counterparty in exchange for a certain floor or ceiling. Any premium reduces amounts we would receive under the floor or increases amounts we would pay above the ceiling. If the floating price exceeds the floor price or is less than the ceiling price, then no payment, other than the premium, is required. If we have less production than the volumes 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.

10

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.

See Note 4 – Fair Value Measurements of Assets and Liabilities, for additional discussion on the fair value measurement of our derivative contracts.

As of September 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
Oct - 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
Oct - 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 $8.00 Ceiling	$0.034 per MMBtu	Henry Hub

⁽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 September 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	September 30, 2009		December 31, 2008
Derivative assets (liabilities) not designated as hedging instruments
Crude oil puts	Commodity derivative contracts - current assets	$	34,132	$	882,179
Crude oil swaps	Commodity derivative contracts - current assets		-		5,124
Natural gas collars	Commodity derivative contracts - current assets		80,145		215,391
Crude oil puts	Commodity derivative contracts - non-current assets		15,542		693,148
Natural gas collars	Commodity derivative contracts - non-current liability		(1,159)		-
Total derivative instruments		$	128,660	$	1,795,842

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The following table provides supplemental information to reconcile the fair value of our derivative assets to our consolidated balance sheets at September 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 amounts disclosed in the table above (in thousands):

	September 30, 2009			December 31, 2008
Net fair value asset	$	128,660		$	1,795,842
Deferred premium and accrued interest on puts and collars		(87,717	)		(333,156	)
Settlement (payable) receivable		(3,294	)		13,333
Net commodity derivative asset	$	37,649		$	1,476,019
Commodity derivative contracts - current asset	$	63,913		$	945,838
Commodity derivative contracts - non-current asset		-			530,181
Commodity derivative contracts - current liability		(22,331	)(1)		-
Commodity derivative contracts - non-current liability		(3,933	)(2)		-
	$	37,649		$	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 derivative contracts on a net basis where the right of offset is provided for in our counterparty agreements.

Income Statement

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Gain on mark-to-market derivative contracts	$	14,795	$	451,083	$	13,217	$	390,175

Cash Payments and Receipts

During the nine months ended September 30, 2009 and 2008, cash receipts (payments) for derivative contracts were as follows (in thousands):

	Nine Months Ended September 30,
	2009		2008
Mark-to-market derivative contracts
Oil sales
Settlements	$	150,394	$	(67,061)
Monetization of crude oil puts and swaps		1,074,361		-
Natural gas sales		233,869		6,752
	$	1,458,624	$	(60,309)

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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 derivative 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 have incurred if all the counterparties to our derivative contracts failed to perform according to the terms of the derivative contracts at September 30, 2009 was $37.8 million.

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 September 30, 2009, we were in a net liability position with three of the counterparties to our derivative instruments, totaling $24.4 million.

Note 4—Fair Value Measurements of Assets and Liabilities

Our financial assets and liabilities are measured at fair value on a recurring basis. We disclose or recognize our nonfinancial assets and liabilities, such as asset retirement obligations, goodwill and other property and equipment, at fair value on a nonrecurring basis. For nonfinancial assets and liabilities, we are required to disclose information that enables users of our financial statements to assess the inputs used to develop those measurements. As none of our nonfinancial assets and liabilities were impaired at the end of the third quarter and no other fair value measurements were required to be recognized on a nonrecurring basis, no additional disclosures were provided at September 30, 2009.

Fair Value of Derivative Instruments

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. We follow 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 measured at fair value on a recurring basis as of September 30, 2009 (in thousands):

	Fair Value (1)		Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2009
Commodity derivative assets	$	128,660	$	-	$	49,674	$	78,986

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

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The fair value amounts of our derivative instruments are estimated 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 nine months ended September 30, 2009 (in thousands):

	Nine Months Ended September 30, 2009 (1)
Fair value at beginning of period	$	1,790,718
Realized and unrealized gains included in earnings(2)		211,918
Purchases and settlements		(1,798,960)
Transfers		(124,690)
Fair value at end of period	$	78,986
Change in unrealized gains and losses relating to assets and liabilities held as of the end of the period(2)	$	29,494

⁽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 gain on mark-to-market derivative contracts in our consolidated statement of income.

Fair Value of Financial Instruments other than Derivative Contracts

The estimated fair value amounts of financial instruments 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.

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

	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Current Liability
Deferred premium on derivative contracts	$	69,401	$	69,401	$	170,189	$	170,189
Non-Current Liability
Deferred premium on derivative contracts		18,316		18,316		162,967		162,967
Long-Term Debt
Senior revolving credit facility		75,000		75,000		1,305,000		1,125,945
73/4% Senior Notes		600,000		595,500		600,000		453,000
10% Senior Notes		565,000		608,788		-		-
7% Senior Notes		500,000		476,250		500,000		342,500
75/8% Senior Notes		400,000		392,000		400,000		274,000
85/8% Senior Notes		400,000		405,000		-		-

The carrying value of our senior revolving credit facility as of September 30, 2009 approximates fair value, as interest rates are variable, based on prevailing market rates. Additionally, our credit spread is reflective of the market due to the recent amendment in the first quarter of 2009, which adjusted our spread to reflect prevailing market rates. As of December 31, 2008, the fair value of our senior revolving credit facility was 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 September 30, 2009, our income tax expense was approximately 46% of pre-tax income, and for the nine months ended September 30, 2009, income tax expense was approximately 32% 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 related to domestic production, and (3) state income taxes. Specific items affecting our income tax expense for the nine months ended September 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 amounts.

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 September 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.

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.

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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, $43 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 $67 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At September 30, 2009, the escrow account had a balance of $12 million. The fair value of our guarantee at September 30, 2009 was $0.9 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. While there are signs that the economy may be improving, business conditions may remain challenging. Volatility and disruption in the financial and credit markets 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 a 20% interest in Chesapeake’s Haynesville Shale leasehold effective 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, which we refer to as the Haynesville Carry.

In August 2009, we amended the joint venture agreement with Chesapeake to accelerate the payment of the remaining Haynesville Carry. We agreed to pay $1.1 billion for the remaining Haynesville Carry balance due Chesapeake as of September 30, 2009, which we estimated to be $1.25 billion, an approximate 12% reduction. On September 29, 2009, we paid $1.1 billion to Chesapeake and we recorded the payment as an addition to oil and natural gas properties. Additionally, Chesapeake committed to drill at least 150 wells per year under the participation agreement for the three-year period starting October 1, 2009. Further, we agreed to terminate our one-time option exercisable in June 2010 which would have relieved us of our obligation to pay the last $800 million of the Haynesville Carry in exchange for an assignment to Chesapeake of 50% of our interest in our Haynesville acreage.

16

We have completed our commitments under our production sharing contract with PetroVietnam, the state oil company of Vietnam, which included the acquisition and interpretation of approximately 850 square kilometers of 3-D seismic data and the drilling of two exploratory wells, which were plugged and abandoned after encountering a minor structurally controlled hydrocarbon accumulation in one well. Our interest in Block 124 covers approximately 1,480,000 gross acres offshore central Vietnam. In September 2009 we obtained 520 kilometers of 2-D seismic data and filed a formal request with the Vietnam government for a one-year extension of the first phase of our production sharing contract which expires on December 31, 2009. We continue to evaluate our plans utilizing the 3-D seismic data, the data from the two exploratory wells and the 2-D seismic data. In the event we discontinue operations, we will record a pre-tax write-down of approximately $55 million, consisting of the accumulated costs in our Vietnam cost center, and would expect to record a corresponding tax deduction for any write-down.

In the second quarter of 2009, we received a net recovery of $87.3 million as our share of the award for damages in the breach of contract lawsuit Amber Resources Company et al. v. United States.

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 of 2009, we sold 13.8 million shares of our common stock at a price of $18.70 per share to the public and received $250.9 million of net proceeds after deducting the underwriting discounts and offering expenses. We used the net proceeds for general corporate purposes, including capital expenditures.

In August 2009, we sold 17.25 million shares of our common stock at a price of $24.00 per share to the public and received $397.1 million of net proceeds after deducting the underwriting discounts and offering expenses. We used the net proceeds for general corporate purposes, including to fund a portion of the $1.1 billion payment for the Haynesville Carry.

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, $400 million of 7 ⁵/8% Senior Notes and $400 million of 8 ⁵/8% Senior Notes as of September 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.

17

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

SEPTEMBER 30, 2009

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	2,847		$	11		$	743		$	-		$	3,601
Accounts receivable and other current assets		203,469			86,831			1,966			(19,241	)		273,025
		206,316			86,842			2,709			(19,241	)		276,626
Property and Equipment, at cost
Oil and natural gas properties - full cost method		3,959,553			7,994,267			54,751			-			12,008,571
Other property and equipment		48,703			35,647			38,807			-			123,157
		4,008,256			8,029,914			93,558			-			12,131,728
Less allowance for depreciation, depletion, amortization and impairment		(2,157,133	)		(5,097,316	)		(39	)		1,762,754			(5,491,734	)
		1,851,123			2,932,598			93,519			1,762,754			6,639,994
Investment in and Advances to Affiliates		4,777,849			(1,831,156	)		(56,129	)		(2,890,564	)		-
Other Assets		20,140			575,119			-			-			595,259
	$	6,855,428		$	1,763,403		$	40,099		$	(1,147,051	)	$	7,511,879
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	440,654		$	294,717		$	10,180		$	(19,241	)	$	726,310
Long-Term Debt		2,493,583			-			-			-			2,493,583
Other Long-Term Liabilities		143,341			60,692			-			-			204,033
Deferred Income Taxes		616,021			(392,444	)		1,750			700,797			926,124
Stockholders’ Equity		3,161,829			1,800,438			28,169			(1,828,607	)		3,161,829
	$	6,855,428		$	1,763,403		$	40,099		$	(1,147,051	)	$	7,511,879

18

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

19

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED SEPTEMBER 30, 2009

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	210,577		$	39,042		$	-		$	-		$	249,619
Gas sales		20,315			42,113			-			-			62,428
Other operating revenues		68			73			-			-			141
		230,960			81,228			-			-			312,188
Costs and Expenses
Production costs		71,935			28,148			-			-			100,083
General and administrative		25,953			10,226			240			-			36,419
Depreciation, depletion, amortization and accretion		54,519			36,384			5			14,388			105,296
Impairment of oil and gas properties		-			631,067			-			(631,067	)		-
Other operating expense (income)		1,229			(5,632	)		-			-			(4,403	)
		153,636			700,193			245			(616,679	)		237,395
Income (Loss) from Operations		77,324			(618,965	)		(245	)		616,679			74,793
Other Income (Expense)
Equity in earnings of subsidiaries		(3,744	)		(61	)		-			3,805			-
Interest expense		(22	)		(15,493	)		(840	)		-			(16,355	)
Debt extinguishment costs		(1,183	)		-			-			-			(1,183	)
Gain on mark-to-market derivative contracts		14,795			-			-			-			14,795
Other income (expense)		540			1			28			-			569
Income (Loss) Before Income Taxes		87,710			(634,518	)		(1,057	)		620,484			72,619
Income tax (expense) benefit		(48,384	)		233,762			314			(218,985	)		(33,293	)
Net Income (Loss)	$	39,326		$	(400,756	)	$	(743	)	$	401,499		$	39,326

20

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED SEPTEMBER 30, 2008

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	395,777	$	133,010	$	-	$	-		$	528,787
Gas sales		38,264		143,707		-		-			181,971
Other operating revenues		476		8,303		-		-			8,779
									��
		434,517		285,020		-		-			719,537
Costs and Expenses
Production costs		94,237		66,244		-		-			160,481
General and administrative		20,225		9,018		131		-			29,374
Depreciation, depletion, amortization and accretion		60,813		77,624		11		4,766			143,214
Impairment of oil and gas properties		-		160,257		-		(160,257)			-
		175,275		313,143		142		(155,491)			333,069
Income (Loss) from Operations		259,242		(28,123)		(142)		155,491			386,468
Other Income (Expense)
Equity in earnings of subsidiaries		85,186		756		-		(85,942)			-
Interest expense		(23,683)		(13,032)		-		3,721			(32,994)
Debt extinguishment costs		(3,138)		-		-		-			(3,138)
Gain on mark-to-market derivative contracts		431,905		19,178		-		-			451,083
Other income (expense)		3,622		(14,613)		870		(3,721)			(13,842)
Income (Loss) Before Income Taxes		753,134		(35,834)		728		69,549			787,577
Income tax (expense) benefit		(259,989)		17,954		28		(52,425)			(294,432)
Net Income (Loss)	$	493,145	$	(17,880)	$	756	$	17,124		$	493,145

21

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2009

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	523,027	$	102,795	$	-	$	-	$	625,822
Gas sales		51,053		141,180		-		-		192,233
Other operating revenues		628		698		-		-		1,326
		574,708		244,673		-		-		819,381
Costs and Expenses
Production costs		218,220		103,326		-		-		321,546
General and administrative		76,818		33,659		589		-		111,066
Depreciation, depletion, amortization and accretion		158,716		121,266		15		11,322		291,319
Impairment of oil and gas properties		-		1,498,923		-		(1,498,923)		-
Legal recovery		(81,790)		(5,482)		-		-		(87,272)
Other operating expense (income)		6,283		(4,730)		-		-		1,553
		378,247		1,746,962		604		(1,487,601)		638,212
Income (Loss) from Operations		196,461		(1,502,289)		(604)		1,487,601		181,169
Other Income (Expense)
Equity in earnings of subsidiaries		3,724		(453)		-		(3,271)		-
Interest expense		(18,325)		(33,579)		(2,383)		-		(54,287)
Debt extinguishment costs		(12,093)		-		-		-		(12,093)
Gain on mark-to-market derivative contracts		13,217		-		-		-		13,217
Other income (expense)		1,446		(680)		(5)		-		761
Income (Loss) Before Income Taxes		184,430		(1,537,001)		(2,992)		1,484,330		128,767
Income tax (expense) benefit		(96,257)		574,768		893		(519,998)		(40,594)
Net Income (Loss)	$	88,173	$	(962,233)	$	(2,099)	$	964,332	$	88,173

22

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2008

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	1,104,853	$	426,285	$	-	$	-	$	1,531,138
Gas sales		59,425		468,949		-		-		528,374
Other operating revenues		1,415		14,390		-		-		15,805
		1,165,693		909,624		-		-		2,075,317
Costs and Expenses
Production costs		285,544		191,108		-		-		476,652
General and administrative		72,288		42,086		131		-		114,505
Depreciation, depletion, amortization and accretion		164,296		248,061		11		9,058		421,426
Impairment of oil and gas properties		-		160,257		-		(160,257)		-
										��
		522,128		641,512		142		(151,199)		1,012,583
Income (Loss) from Operations		643,565		268,112		(142)		151,199		1,062,734
Other Income (Expense)
Equity in earnings of subsidiaries		258,263		1,411		-		(259,674)		-
Interest expense		(50,630)		(55,285)		-		18,801		(87,114)
Debt extinguishment costs		(13,401)		-		-		-		(13,401)
Gain (loss) on mark-to-market derivative contracts		408,348		(18,173)		-		-		390,175
Other income (expense)		19,184		20,566		1,528		(18,801)		22,477
Income Before Income Taxes		1,265,329		216,631		1,386		(108,475)		1,374,871
Income tax (expense) benefit		(405,765)		(60,517)		25		(49,050)		(515,307)
Net Income	$	859,564	$	156,114	$	1,411	$	(157,525)	$	859,564

23

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2009

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	88,173	$	(962,233)	$	(2,099)	$	964,332	$	88,173
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		158,716		1,620,189		15		(1,487,601)		291,319
Equity in earnings of subsidiaries		(3,724)		453		-		3,271		-
Deferred income tax benefit (expense)		(45,296)		(544,995)		(893)		598,021		6,837
Debt extinguishment costs		12,093		-		-		-		12,093
Gain on mark-to-market derivative contracts		(13,217)		-		-		-		(13,217)
Noncash compensation		39,283		8,533		-		-		47,816
Other noncash items		4,203		204		72		-		4,479
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(12,326)		42,266		(354)		-		29,586
Accounts payable and other liabilities		(1,750)		(28,950)		18		-		(30,682)
Stock appreciation rights		(327)		-		-		-		(327)
Income taxes receivable/payable and prepaid		(126,191)		-		-		-		(126,191)
Net cash provided (used in) by operating activities		99,637		135,467		(3,241)		78,023		309,886
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(543,504)		(668,719)		(30,475)		-		(1,242,698)
Acquisition of oil and gas properties		-		(1,137,142)		-		-		(1,137,142)
Derivative settlements		1,457,232		-		-		-		1,457,232
Additions to other property and equipment		(3,014)		(599)		(8,554)		-		(12,167)
Other, net		50		112		-		-		162
Net cash provided by (used in) investing activities		910,764		(1,806,348)		(39,029)		-		(934,613)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		2,315,090		-		-		-		2,315,090
Repayments of revolving credit facilities		(3,545,090)		-		-		-		(3,545,090)
Proceeds from issuance of Senior Notes		916,439		-		-		-		916,439
Cost incurred in connection with financing arrangements		(19,441)		-		-		-		(19,441)
Derivative settlements		1,392		-		-		-		1,392
Issuance of common stock		648,035		-		-		-		648,035
Investment in and advances to affiliates		(1,633,369)		1,670,607		40,785		(78,023)		-
Other		28		-		-		-		28
Net cash (used in) provided by financing activities		(1,316,916)		1,670,607		40,785		(78,023)		316,453
Net (decrease) increase in cash and cash equivalents		(306,515)		(274)		(1,485)		-		(308,274)
Cash and cash equivalents, beginning of period		309,362		285		2,228		-		311,875
Cash and cash equivalents, end of period	$	2,847	$	11	$	743	$	-	$	3,601

24

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2008

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	859,564	$	156,114	$	1,411	$	(157,525)	$	859,564
Items not affecting cash flows from operating activities
Gain on sale of assets		-		(34,658)		-		-		(34,658)
Depreciation, depletion, amortization, accretion and impairment		164,296		408,318		11		(151,199)		421,426
Equity in earnings of subsidiaries		(258,263)		(1,411)		-		259,674		-
Deferred income taxes		289,166		(100,579)		20		14,424		203,031
Debt extinguishment costs		13,401		-		-		-		13,401
(Gain) loss on mark-to-market derivative contracts		(408,348)		18,173		-		-		(390,175)
Noncash compensation		33,509		5,458		(36)		-		38,931
Other noncash items		2,503		1,267		460		-		4,230
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(5,095)		(64,146)		3,492		-		(65,749)
Accounts payable and other liabilities		(13,608)		(36,100)		(609)		-		(50,317)
Stock appreciation rights		(59,056)		-		-		-		(59,056)
Income taxes receivable/payable		206,311		-		-		-		206,311
Net cash provided by operating activities		824,380		352,436		4,749		(34,626)		1,146,939
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(314,379)		(367,577)		(6,249)		-		(688,205)
Acquisition of oil and gas properties		-		(2,012,969)		-		-		(2,012,969)
Acquisition of Pogo Producing Company		-		(76,645)		-		-		(76,645)
Proceeds from sales of oil and gas properties and related assets, net of costs and expenses		1,736,059		-		-		-		1,736,059
Derivative settlements		(36,212)		-		-		-		(36,212)
Decrease in restricted cash		-		59,092		-		-		59,092
Other		(24,049)		(1,722)		(10,348)		-		(36,119)
Net cash provided by (used in) investing activities		1,361,419		(2,399,821)		(16,597)		-		(1,054,999)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		11,501,352		-		-		-		11,501,352
Repayments of revolving credit facilities		(11,672,221)		-		-		-		(11,672,221)
Proceeds from issuance of Senior Notes		400,000		-		-		-		400,000
Cost incurred in connection with financing arrangements		(25,448)		-		-		-		(25,448)
Derivative settlements		(24,097)		-		-		-		(24,097)
Purchase of treasury stock		(304,192)		-		-		-		(304,192)
Investment in and advances to affiliates		(2,087,137)		2,045,651		6,860		34,626		-
Other		10,142		(495)		-		-		9,647
Net cash (used in) provided by financing activities		(2,201,601)		2,045,156		6,860		34,626		(114,959)
Net decrease in cash and cash equivalents		(15,802)		(2,229)		(4,988)		-		(23,019)
Cash and cash equivalents, beginning of period		15,897		2,261		7,288		-		25,446
Cash and cash equivalents, end of period	$	95	$	32	$	2,300	$	-	$	2,427

25

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 senior revolving credit facility and periodic public offerings of debt and equity. At September 30, 2009, we had approximately $1.14 billion available for future secured borrowings under our senior revolving credit facility. We believe that we have sufficient liquidity through our forecasted cash flow from operations, 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

While there are signs that the economy may be improving, the potential remains for further volatility and disruption in the capital and credit markets. The recent 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. These market conditions may adversely affect our liquidity by limiting our ability to access the capital and credit markets (See Liquidity and Capital Resources).

26

Recent Developments

Haynesville Shale Joint Venture

In August 2009, we amended the joint venture agreement with Chesapeake to accelerate the payment of the remaining Haynesville Carry. We agreed to pay $1.1 billion for the remaining Haynesville Carry balance due Chesapeake as of September 30, 2009, which we estimated to be $1.25 billion, an approximate 12% reduction. On September 29, 2009, we paid $1.1 billion to Chesapeake and we recorded the payment as an addition to oil and natural gas properties. Additionally, Chesapeake committed to drill at least 150 wells per year under the participation agreement for the three-year period starting October 1, 2009. Further, we agreed to terminate our one-time option exercisable in June 2010 which would have relieved us of our obligation to pay the last $800 million of the Haynesville Carry in exchange for an assignment to Chesapeake of 50% of our interest in our Haynesville acreage.

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.

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, 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

For the nine months ended September 30, 2009, we reported net income of $88.2 million, or $0.73 per diluted share, compared to net income of $859.6 million, or $7.72 per diluted share, for the nine months ended September 30, 2008. The decrease primarily reflects lower commodity prices in 2009 and a reduction in the pre-tax gain on mark-to-market derivative contracts.

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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 September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Sales Volumes
Oil and liquids sales (MBbls)		4,360		5,134		13,246		15,399
Gas (MMcf)
Production		20,250		20,722		55,857		60,320
Used as fuel		593		524		1,823		1,659
Sales		19,657		20,198		54,034		58,661
MBOE
Production		7,736		8,588		22,556		25,452
Sales		7,637		8,500		22,252		25,175
Daily Average Volumes
Oil and liquids sales (Bbls)		47,399		55,803		48,521		56,199
Gas (Mcf)
Production		220,103		225,232		204,605		220,145
Used as fuel		6,443		5,691		6,678		6,053
Sales		213,660		219,541		197,927		214,092
BOE
Production		84,083		93,342		82,622		92,890
Sales		83,009		92,393		81,509		91,881
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	68.24	$	118.22	$	57.32	$	113.52
Gas		3.40		10.28		3.91		9.76
Average Realized Sales Price Before
Derivative Transactions
Oil (per Bbl)	$	57.26	$	103.00	$	47.24	$	99.43
Gas (per Mcf)		3.18		9.01		3.56		9.00
Per BOE		40.86		83.62		36.76		81.81
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	7.89	$	9.06	$	8.75	$	9.40
Steam gas costs		1.43		4.40		1.68		4.38
Electricity		1.39		1.69		1.52		1.46
Production and ad valorem taxes		1.04		3.22		1.35		3.09
Gathering and transportation		1.36		0.52		1.15		0.61
Depreciation, depletion and amortization of oil and gas properties (“DD&A”)	$	12.66	$	15.71	$	11.89	$	15.72

Comparisons between the periods are affected by the February 2008 divestiture of 50% of our working interest in the Piceance and Permian Basins, all of the San Juan Basin and Barnett Shale, the April 2008 acquisition of South Texas properties, the 20% interest in Chesapeake's Haynesville Shale leasehold acquired July 7, 2008 and the divestiture of the remainder of our interest in the Piceance and Permian Basins effective December 1, 2008.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Mark-to-market derivative contracts
Oil sales
Settlements	$	(9,198)	$	(23,953)	$	150,394	$	(67,061)
Monetization of crude oil puts and swaps		-		-		1,074,361		-
Natural gas sales		86,108		6,325		233,869		6,752
	$	76,910	$	(17,628)	$	1,458,624	$	(60,309)

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

Oil and gas revenues.    Oil and gas revenues decreased $398.8 million, to $312.0 million for 2009 from $710.8 million for 2008 primarily due to a decrease in realized prices of $42.76 per BOE and a 10% decrease in sales volumes primarily associated with the 2008 property divestments. Excluding the impact of our divestments, increased production from the Haynesville Shale and Flatrock properties is responsible for a 4% increase in sales volumes for the three months ended September 30, 2009 compared to the same period a year ago.

Oil revenues decreased $279.2 million to $249.6 million for 2009 from $528.8 million for 2008 reflecting lower average realized prices ($234.9 million) and lower sales volumes ($44.3 million). Our average realized price for oil decreased $45.74 to $57.26 per Bbl for 2009 from $103.00 per Bbl for 2008. Oil sales volumes decreased 8.4 MBbls per day to 47.4 MBbls per day in 2009 from 55.8 MBbls per day in 2008, primarily reflecting the impact of our divestments in 2008 (5.5 MBbls per day).

Gas revenues decreased $119.6 million to $62.4 million in 2009 from $182.0 million in 2008 due to a decrease in realized prices ($117.8 million) and decreased sales volumes ($1.8 million). Our average realized price for gas was $3.18 per Mcf in 2009 compared to $9.01 per Mcf in 2008. Gas sales volumes decreased from 219.5 MMcf per day in 2008 to 213.7 MMcf per day in 2009, primarily reflecting the impact of our divestments in 2008 (43.1 MMcf per day). Excluding the impact of our divestments, increased production from the Haynesville Shale and Flatrock properties is responsible for a 21% increase in sales volumes for the three months ended September 30, 2009 compared to the same period a year ago.

Lease operating expenses.    Lease operating expenses decreased $16.7 million, to $60.3 million in 2009 from $77.0 million in 2008. Excluding costs associated with the properties sold in 2008, lease operating expenses decreased by $4.9 million, primarily reflecting the implementation of our program to reduce expenses. On a per unit basis, lease operating expenses decreased to $7.89 per BOE in 2009 versus $9.06 per BOE in 2008 due primarily to the implementation of our cost reduction program.

Steam gas costs.    Steam gas costs decreased $26.4 million, to $11.0 million in 2009 from $37.4 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 $2.95 per MMBtu compared to 4.2 Bcf at a cost of approximately $8.99 per MMBtu in 2008.

Electricity.    Electricity decreased $3.8 million, to $10.6 million in 2009 from $14.4 million in 2008, reflecting a decrease in rates, primarily in California. On a per unit basis, electricity was $1.39 per BOE in 2009 compared to $1.69 per BOE in 2008.

Production and ad valorem taxes.    Production and ad valorem taxes decreased $19.4 million, to $7.9 million in 2009 from $27.3 million in 2008, primarily reflecting lower commodity prices and the divestments in 2008.

Gathering and transportation expense.    Gathering and transportation expenses increased $5.9 million, to $10.3 million in 2009 from $4.4 million in 2008, primarily reflecting an increase in production from our Flatrock and Haynesville Shale properties.

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General and administrative expense.    G&A expense increased $7.0 million, to $36.4 million in 2009 from $29.4 million in 2008. The increase is primarily due to an increase in stock-based compensation expense ($6.9 million), which offset a decrease in cash costs between the two periods due to our cost reduction program. In 2009, our increased stock price resulted in a larger compensation expense compared to 2008 where we recognized a negative expense from declining stock prices during the second half of 2008.

Depreciation, depletion and amortization, or DD&A.    DD&A expense decreased $38.2 million, to $101.8 million in 2009 from $140.0 million in 2008. The decrease is attributable to our oil and gas depletion, primarily due to a lower per unit rate ($26.2 million) and decreased production ($10.8 million). Our oil and gas unit of production rate decreased to $12.66 per BOE in 2009 compared to $15.71 per BOE in 2008. The decrease primarily reflects the 2008 year-end impairment of our oil and gas properties, which reduced our DD&A rate in subsequent periods.

Other operating (income) expense.    Other operating income in 2009 consists primarily of a reduction in preacquisition operating expense accruals related to our acquisition of Pogo Producing Company in 2007, partially offset by idle drilling equipment costs resulting from unused contract commitments.

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

	Three Months Ended September 30,
	2009		2008
Interest expense before capitalization	$	47,805	$	52,225
Capitalized interest		(31,450)		(19,231)
Total interest expense	$	16,355	$	32,994

Net interest expense decreased due to an increase in capitalized interest of $12.2 million and a decrease in interest expense before capitalization of $4.4 million. The increase in capitalized interest is attributable to a higher average interest rate during 2009. The decrease in interest before capitalization is attributable to lower outstanding debt in 2009, which more than offset the effect of higher interest rates.

Gain 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 a $14.8 million mark-to-market derivative gain in the third quarter of 2009, which was primarily associated with an increase in the fair value of our 2010 crude oil puts and 2009 natural gas collars due to lower crude oil and natural gas prices. In the third quarter of 2008, we recognized a $451.1 million mark-to-market derivative gain primarily associated with the crude oil puts which we monetized in the first quarter of 2009 (See Recent Developments – Derivatives).

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 related to domestic production, and (3) state income taxes.

For the third quarter of 2009, our income tax expense was approximately 46% of pre-tax income. The effective tax rate of 46% for the quarter results primarily from changes in the relationship of 2009 estimated pre-tax income relative to estimated permanent differences. For the third quarter of 2008, income tax expense was approximately 37% of pre-tax income.

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Comparison of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2008

Oil and gas revenues.    Oil and gas revenues decreased $1.3 billion, to $818.1 million for 2009 from $2.1 billion for 2008 primarily due to a decrease in realized prices of $45.05 per BOE and a 12% decrease in sales volumes primarily associated with our 2008 property divestments. Excluding the impact of our divestments, increased production from the Haynesville Shale and Flatrock properties is responsible for an 8% increase in sales volumes in the first nine months of 2009 compared to the same period a year ago.

Oil revenues decreased $905.3 million to $625.8 million for 2009 from $1.5 billion for 2008 reflecting lower average realized prices ($803.6 million) and lower sales volumes ($101.7 million). Our average realized price for oil decreased $52.19 to $47.24 per Bbl for 2009 from $99.43 per Bbl for 2008. Oil sales volumes decreased 7.7 MBbls per day to 48.5 MBbls per day in 2009 from 56.2 MBbls per day in 2008, primarily reflecting the impact of our divestments in 2008 (7.1 MBbls per day).

Gas revenues decreased $336.2 million to $192.2 million in 2009 from $528.4 million in 2008 due to a decrease in realized prices ($319.7 million) and decreased sales volumes ($16.5 million). Our average realized price for gas was $3.56 per Mcf in 2009 compared to $9.00 per Mcf in 2008. Gas sales volumes decreased from 214.1 MMcf per day in 2008 to 197.9 MMcf per day in 2009, primarily reflecting the impact of our divestments in 2008 (57.5 MMcf per day). Excluding the impact of our divestments, increased production from the Haynesville Shale and Flatrock properties is responsible for a 26% increase in sales volumes in the first nine months of 2009 compared to the same period a year ago.

Lease operating expenses.    Lease operating expenses decreased $42.1 million, to $194.6 million in 2009 from $236.7 million in 2008. Excluding costs associated with the properties sold in 2008, lease operating expenses decreased by $11.9 million, primarily reflecting the implementation of our program to reduce expenses. On a per unit basis, lease operating expenses decreased to $8.75 per BOE in 2009 versus $9.40 per BOE in 2008 due primarily to the implementation of our cost reduction program in 2009.

Steam gas costs.    Steam gas costs decreased $72.8 million, to $37.4 million in 2009 from $110.2 million in 2008, primarily reflecting lower cost of gas used in steam generation. In 2009, we burned approximately 11.3 Bcf of natural gas at a cost of approximately $3.31 per MMBtu compared to 12.5 Bcf at a cost of approximately $8.80 per MMBtu in 2008.

Electricity.    Electricity decreased $2.8 million, to $33.9 million in 2009 from $36.7 million in 2008, primarily reflecting a decrease in rates, primarily in California. On a per unit basis, electricity was $1.52 per BOE in 2009 compared to $1.46 per BOE in 2008.

Production and ad valorem taxes.    Production and ad valorem taxes decreased $47.8 million, to $30.0 million in 2009 from $77.8 million in 2008, primarily reflecting lower commodity prices and the divestments in 2008.

Gathering and transportation expense.    Gathering and transportation expenses increased $10.3 million, to $25.7 million in 2009 from $15.4 million in 2008, primarily reflecting an increase in production from our Haynesville Shale and Flatrock properties.

General and administrative expense.    G&A expense decreased $3.4 million, to $111.1 million in 2009 from $114.5 million in 2008. The decrease is primarily due to cost reductions in 2009, partially offset by higher stock based compensation expense. In 2009, our increased stock price resulted in a larger compensation expense compared to 2008 where we recognized a negative expense from declining stock prices during the second half of 2008.

Depreciation, depletion and amortization, or DD&A.    DD&A expense decreased $130.9 million, to $280.7 million in 2009 from $411.6 million in 2008. The decrease is attributable to our oil and gas DD&A, primarily due to a lower per unit rate ($97.5 million) and decreased production ($34.4 million). Our oil and gas unit of production rate decreased to $11.89 per BOE in 2009 compared to $15.72 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.

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Legal 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.

Other operating (income) expense.    Other operating income/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 partially offset by a reduction in preacquisition operating expense accruals related to our acquisition of Pogo Producing Company in 2007.

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 nine months ended September 30, 2009 and 2008 (in thousands):

	Nine Months Ended September 30,
	2009		2008
Interest expense before capitalization	$	134,969	$	136,044
Capitalized interest		(80,682)		(48,930)
Total interest expense	$	54,287	$	87,114

Net interest expense decreased primarily due to an increase in capitalized interest of $31.8 million. The increase in capitalized interest is attributable to a higher average interest rate and higher unevaluated property balances associated with our Haynesville Shale properties.

Debt extinguishment costs.    In connection with reductions of the commitments on our senior revolving credit facility, we recorded $12.1 million and $13.4 million of debt extinguishment costs in the nine months ended September 30, 2009 and 2008, respectively.

Gain 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 $13.2 million gain related to mark-to-market derivative contracts in the nine months ended September 30, 2009, which was primarily associated with an increase in the fair value of our 2009 natural gas collars due to lower natural gas prices. In the nine months ended September 30, 2008, we recognized a $390.2 million gain related to mark-to-market derivative contracts primarily associated with the crude oil puts, which we monetized in the first quarter of 2009.

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, and (2) state income taxes.

For the nine months ended September 30, 2009, our income tax expense was approximately 32% of pre-tax income. This effective tax rate of 32% for the nine months results primarily from the relationship of 2009 estimated pre-tax income relative to our estimated permanent differences, together with specific items affecting income tax expense for the nine months which included a significant reduction in our balance of unrecognized tax positions. For the nine months ended September 30, 2008, income tax expense was approximately 37% of pre-tax income.

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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 these 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.

While there are signs that the economy may be improving, the potential remains for further volatility and disruption in the capital and credit markets. The recent 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. These market conditions may adversely affect our liquidity by limiting our ability to access the capital and credit markets.

Our primary sources of liquidity are cash generated from our operations, our borrowing capacity under our senior revolving credit facility and periodic public offerings of debt and equity. At September 30, 2009, we had approximately $1.14 billion available for future secured borrowings under our senior revolving credit facility. 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 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 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 addition to monetizing our derivatives, we have continued to strengthen our liquidity during 2009 by issuing new senior notes and shares of our common stock (See Financing Activities). On September 29, 2009, we used our cash on hand and $75 million of borrowings under our senior revolving credit facility to pay $1.1 billion to Chesapeake for the remaining Haynesville Carry balance. The $1.1 billion payment represented an approximate 12% reduction from the estimated $1.25 billion remaining commitment as of September 30, 2009. The payment allowed us to refinance a shorter-term commitment on a long-tem basis. It also increases the discretionary portion of our capital budget going forward so that we could curtail our discretionary capital expenditures if cash flows decline from expected levels.

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Our 2009 capital budget is expected to be $1.55 billion, including capitalized interest and general and administrative expenses. The capital budget reflects our participation in additional Gulf of Mexico exploratory drilling, additional Haynesville Shale wells, a slower than anticipated reduction in rig rates and service costs and increased capitalized interest and general and administrative expense partially offset by the elimination of the Haynesville Carry. Our 2009 capital budget continues to be 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 and high-impact Miocene and Paleogene exploration projects in the Gulf of Mexico shelf and deep water. We are targeting a $900 million to $1.1 billion 2010 capital budget including capitalized interest and general and administrative expenses. We intend to fund our 2010 capital budget from internally generated funds and borrowings under our senior revolving credit facility and have the flexibility to adjust spending as market conditions warrant.

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. As of September 30, we had approximately $1.14 billion available under our senior revolving credit facility and the next maturity of our senior notes will occur on June 15, 2015.

Working Capital

At September 30, 2009, we had a working capital deficit of approximately $449.7 million. We generally have a working capital deficit because we use excess cash to pay down borrowings under our senior revolving credit facility. 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. Our borrowing base and commitments were then reduced to $1.34 billion in recognition of our issuances of the 10% Senior Notes and further reduced to $1.22 billion in recognition of our issuance of the 8⁵/₈% Senior Notes. During 2009, we have recognized $12.1 million of debt extinguishment costs in connection with the reductions in our borrowing base and commitments. As of September 30, 2009, we had $75 million in outstanding borrowings under our senior revolving credit facility.

In addition, the amendment increased the cost of borrowings under our senior revolving credit 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 the shares of stock in 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 September 30, 2009, we had $1.3 million in letters of credit outstanding and approximately $1.14 billion available for future secured borrowings under our senior revolving credit facility.

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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 discounts, original issue discount and offering expenses. We used the net proceeds 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.

In September 2009, we issued $400 million of 8⁵/₈% Senior Notes due 2019. The notes were sold to the public at 98.335% of the face value to yield 8.875% to maturity. We received approximately $386 million of net proceeds after deducting the underwriting discount, original issue discount and offering expenses. We used the net proceeds for general corporate purposes, including to fund a portion of the remaining Haynesville Carry balance. We may redeem all or part of the 8⁵/₈% Senior Notes on or after October 15, 2014 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to October 15, 2012 we may, at our option, redeem up to 35% of the 8⁵/₈% 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 8⁵/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

During the second quarter of 2009, we sold 13.8 million shares of our common stock at a price of $18.70 per share to the public and received $250.9 million of net proceeds after deducting the underwriting discounts and offering expenses. We used the net proceeds for general corporate purposes, including capital expenditures.

In August 2009, we sold 17.25 million shares of our common stock at a price of $24.00 per share to the public and received $397.1 million of net proceeds after deducting the underwriting discounts and offering expenses. We used the net proceeds for general corporate purposes, including to fund a portion of the $1.1 billion payment for the Haynesville Carry.

Cash Flows

	Nine Months Ended September 30,
	2009		2008
	(in millions)
Cash provided by (used in):
Operating activities	$	309.9	$	1,146.9
Investing activities		(934.6)		(1,055.0)
Financing activities		316.5		(115.0)

Net cash provided by operating activities was $309.9 million for the nine months ended September 30, 2009 compared to $1.1 billion for of the same period in 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 Amber legal recovery.

Net cash used in investing activities of $934.6 million for the nine months ended September 30, 2009 includes additions to oil and gas properties of $1.2 billion and acquisitions of oil and gas properties of $1.1 billion, reflecting the payment of the Haynesville Carry, offset by derivative settlements received of $1.5 billion. Net cash used in investing activities was $1.1 billion for the nine months ended September 30, 2008, primarily reflecting the purchase of our Haynesville Shale leasehold for $1.65 billion, the purchase of our South Texas properties for approximately $282 million and additions to oil and gas properties of $688.2 million, partially offset by the net proceeds from property sales of $ 1.7 billion.

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Net cash provided by financing activities of $316.5 million in 2009 primarily reflects the net proceeds of $916.4 million from the issuance of the 10% and the 8⁵/₈% Senior Notes and the $648.0 million of proceeds from our common stock offerings offset by the $1.2 billion net reduction in borrowings under our senior revolving credit facility. Net cash used in financing activities of $115.0 million in 2008 primarily reflects the $170.9 million net reduction in borrowings under our senior revolving credit facility and $304.2 million of stock repurchases, partially offset by $400 million from the issuance of our 7⁵/₈% Senior Notes.

Critical Accounting Policies and Factors that May Affect Future Results

Our financial assets and liabilities are measured at fair value on a recurring basis. We disclose or recognize our nonfinancial assets and liabilities, such as asset retirement obligations, goodwill and other property and equipment, at fair value on a nonrecurring basis. For nonfinancial assets and liabilities, we are required to disclose information that enables users of our financial statements to assess the inputs used to develop those measurements. As none of our nonfinancial assets and liabilities were impaired at the end of the third quarter and no other fair value measurements were required to be recognized on a nonrecurring basis, no additional disclosures were provided at September 30, 2009.

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 September 30, 2009, 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 22%, 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.

We have completed our commitments under our production sharing contract with PetroVietnam, the state oil company of Vietnam, which included the acquisition and interpretation of approximately 850 square kilometers of 3-D seismic data and the drilling of two exploratory wells, which were plugged and abandoned after encountering a minor structurally controlled hydrocarbon accumulation in one well. Our interest in Block 124 covers approximately 1,480,000 gross acres offshore central Vietnam. In September 2009 we obtained 520 kilometers of 2-D seismic data and filed a formal request with the Vietnam government for a one-year extension of the first phase of our production sharing contract which expires on December 31, 2009. We continue to evaluate our plans utilizing the 3-D seismic data, the data from the two exploratory wells and the 2-D seismic data. In the event we discontinue operations, we will record a pre-tax write-down of approximately $55 million, consisting of the accumulated costs in our Vietnam cost center, and would expect to record a corresponding tax deduction for any such write-down.

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 September 30, 2009, goodwill totaled $535 million and represented approximately 7% of our total assets.

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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, we have one reporting unit. Quoted market prices in active markets are the best evidence of fair value. 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 goodwill 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.

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 February 2008, the Financial Accounting Standards Board (“FASB”) issued a one-year deferral to comply with authoritative guidance that defines fair value and establishes a framework for measuring fair value of nonfinancial assets and liabilities measured on a nonrecurring basis. On January 1, 2009, we adopted this guidance for nonfinancial assets and liabilities and the adoption did not have a material impact on our consolidated financial position, results of operations or cash flows.

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. Currently, 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. We expect that the primary impact of adoption on our financial statements will be related to the use of the twelve-month average price rather than a single-day price in our reserve estimates. If the average price is higher or lower than the year-end price, we would expect our reserve estimates to be higher or lower which will have an impact on our reserve volumes and values, the full cost ceiling limitations and our oil and gas depreciation, depletion and amortization rate. We will adopt the guidance as of December 31, 2009 in our 2009 Annual Report on Form 10-K. In September 2009, the FASB issued its proposed standard on oil and gas reserve estimation and disclosure aligning its requirements with the SEC final rule.

In April 2009, the FASB issued authoritative guidance on 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. The guidance emphasizes that if there has been a significant decrease in the volume and level of activity for the asset or liability, 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. The guidance further requires disclosures, in summarized financial information, about the fair value of financial instruments for interim reporting periods of publicly traded companies. This guidance is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted. We early adopted the guidance effective January 1, 2009, and it did not have a material impact on our consolidated financial position, results of operations or cash flows.

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In May 2009, the FASB issued authoritative guidance that 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. It also sets forth the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The guidance is effective for interim or annual periods ending after June 15, 2009 and our second quarter 2009 adoption did not impact our consolidated financial position, results of operations or cash flows. We have evaluated events or transactions through November 5, 2009, the date we issued our consolidated financial statements.

In June 2009, the FASB issued authoritative guidance for improving financial reporting by enterprises involved with variable-interest entities. This guidance (1) eliminates the exemption for qualifying special purpose entities, (2) includes a new approach for determining who should consolidate a variable-interest entity, and (3) presents changes as to when it is necessary to reassess who should consolidate a variable-interest entity. The guidance 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 this guidance.

In August 2009, the FASB issued authoritative guidance on fair value measurements and disclosures, specifically regarding the measurement of liabilities at fair value. This guidance provides clarification for required valuation techniques in circumstances in which a quoted price in an active market for the identical liability is not available. The guidance also states that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. Further clarification was also provided that both a quoted price for the identical liability at the measurement date and the quoted price for the identical liability when traded as an asset in an active market, in situations where no adjustments to the quoted price of the asset are required, are Level 1 fair value measurements. The guidance is effective for the first reporting period after the period of issuance. We early adopted the guidance effective third quarter 2009, and the adoption did not have a material impact on our consolidated financial position, results of operations or cash flows.

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;

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• 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 our filings with the SEC, including 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 and Item 1A – Risk Factors in our Quarterly Reports in our Form 10-Q 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, in the notes to the consolidated financial statements, for a discussion of our derivative activities and fair value measurements.

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As of September 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
Oct - 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
Oct - 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 $8.00 Ceiling	$0.034 per MMBtu	Henry Hub

⁽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 September 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%
			Price Increase		Price Decrease
Crude oil put options	$	50	$	(16)	$	24
Natural gas collars		79		(16)		15
	$	129	$	(32)	$	39

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.

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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 September 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 September 30, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1A – Risk Factors

There has been no material change to our risk factors set forth in Part 1, Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008 or Part II, Item 1A, “Risk Factors” in our Form 10-Q for the quarter ended June 30, 2009, except as set forth below.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

Among the changes contained in President Obama’s budget proposal, released by the White House on February 26, 2009, is the elimination or deferral of certain key U.S. federal income tax deductions currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Additionally, the Senate bill version of the Oil Industry Tax Break Repeal Act of 2009, introduced on April 23, 2009, and the Senate bill version of the Energy Fairness for America Act, introduced on May 20, 2009, include many of the proposals outlined in President Obama’s budget proposal. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of the budget proposal, either Senate bill or any other similar change in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial results.

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ITEM 6 – Exhibits

Exhibit No.	Description
1.1	Underwriting Agreement, dated August 6, 2009, by and among Plains Exploration & Production Company, Goldman, Sachs & Co., Barclays Capital Inc., J.P. Morgan Securities Inc. and UBS Securities LLC (incorporated by reference to Exhibit 1.1 of the Company’s Form 8-K filed August 7, 2009, File No. 1-31470 (the “August 7, 2009 Form 8-K”)).
1.2	Underwriting Agreement, dated September 8, 2009, by and among Plains Exploration & Production Company, the guarantors parties thereto, and the underwriters parties thereto (incorporated by reference to Exhibit 1.1 of the Company’s Form 8-K filed September 11, 2009, File No. 1-31470 (the “September 11, 2009 Form 8-K”)).
4.1	Tenth Supplemental Indenture, dated as of September 11, 2009, to Indenture dated March 13, 2007, among Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.1 to the September 11, 2009 Form 8-K).
10.1	Second Amendment to the Participation Agreement among Plains Exploration & Production Company, PXP Louisiana L.L.C., PXP Louisiana Operations LLC and Chesapeake Louisiana, L.P., dated August 5, 2009 (incorporated by reference to Exhibit 10.1 of the August 7, 2009 Form 8-K).
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

Items 1, 2, 3, 4 and 5 are not applicable and have been omitted.

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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.

	PLAINS EXPLORATION & PRODUCTION COMPANY
Date: November 5, 2009	By:	/s/ Winston M. Talbert
		Winston M. Talbert
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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EXHIBIT INDEX

Exhibit No.	Description
1.1	Underwriting Agreement, dated August 6, 2009, by and among Plains Exploration & Production Company, Goldman, Sachs & Co., Barclays Capital Inc., J.P. Morgan Securities Inc. and UBS Securities LLC (incorporated by reference to Exhibit 1.1 of the Company’s Form 8-K filed August 7, 2009, File No. 1-31470 (the “August 7, 2009 Form 8-K”)).
1.2	Underwriting Agreement, dated September 8, 2009, by and among Plains Exploration & Production Company, the guarantors parties thereto, and the underwriters parties thereto (incorporated by reference to Exhibit 1.1 of the Company’s Form 8-K filed September 11, 2009, File No. 1-31470 (the “September 11, 2009 Form 8-K”)).
4.1	Tenth Supplemental Indenture, dated as of September 11, 2009, to Indenture dated March 13, 2007, among Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.1 to the September 11, 2009 Form 8-K).
10.1	Second Amendment to the Participation Agreement among Plains Exploration & Production Company, PXP Louisiana L.L.C., PXP Louisiana Operations LLC and Chesapeake Louisiana, L.P., dated August 5, 2009 (incorporated by reference to Exhibit 10.1 of the August 7, 2009 Form 8-K).
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

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