Plains Exploration & Production 10-Q 2008 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, 2008

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.

Yes  x    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

107.6 million shares of Common Stock, $0.01 par value, issued and outstanding at October 31, 2008.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
ITEM 1. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets September 30, 2008 and December 31, 2007	1
Consolidated Statements of Income For the three months and nine months ended September 30, 2008 and 2007	2
Consolidated Statements of Cash Flows For the nine months ended September 30, 2008 and 2007	3
Consolidated Statement of Stockholders’ Equity For the nine months ended September 30, 2008	4
Notes to Consolidated Financial Statements	5
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk	44
ITEM 4. Controls and Procedures	47
PART II. OTHER INFORMATION	48

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

		September 30, 2008			December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents		$	2,427		$	25,446
Restricted cash			-			59,092
Accounts receivable	��		362,015			304,972
Commodity derivative contracts			79,236			2,186
Inventories			29,643			18,394
Deferred income taxes			19,474			229,893
Other current assets			12,240			34,937
			505,035			674,920
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization			7,328,579			7,340,238
Not subject to amortization			3,147,345			1,951,783
Other property and equipment			117,946			85,928
			10,593,870			9,377,949
Less allowance for depreciation, depletion and amortization			(1,404,010	)		(1,000,722	)
			9,189,860			8,377,227
Goodwill			535,280			536,822
Commodity Derivative Contracts			293,439			-
Other Assets			112,240			104,382
		$	10,635,854		$	9,693,351
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable		$	381,603		$	319,583
Commodity derivative contracts			30,262			79,938
Royalties and revenues payable			145,411			132,919
Stock appreciation rights			5,116			63,106
Interest payable			32,696			25,330
Income taxes payable			194,965			3,492
Accrued merger expenses			964			77,980
Other current liabilities			133,524			115,698
			924,541			818,046
Long-Term Debt
Senior revolving credit facility			2,034,131			2,205,000
Senior notes			1,500,000			1,100,000
			3,534,131			3,305,000
Other Long-Term Liabilities
Asset retirement obligation			183,197			184,080
Other			125,374			88,547
			308,571			272,627
Deferred Income Taxes			1,931,823			1,959,431
Commitments and Contingencies (Note 9)
Stockholders’ Equity
Common stock			1,128			1,128
Additional paid-in capital			2,729,070			2,711,617
Retained earnings			1,483,557			623,993
Accumulated other comprehensive income			1,496			1,566
Treasury stock			(278,463	)		(57	)
			3,936,788			3,338,247
		$	10,635,854		$	9,693,351

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,
	2008			2007			2008			2007
Revenues
Oil sales	$	528,787		$	276,096		$	1,531,138		$	713,197
Gas sales		181,971			22,696			528,374			63,441
Other operating revenues		8,779			177			15,805			2,571
		719,537			298,969			2,075,317			779,209
Costs and Expenses
Production costs
Lease operating expenses		76,943			52,696			236,699			147,471
Steam gas costs		37,418			22,349			110,175			76,630
Electricity		14,367			11,197			36,665			29,464
Production and ad valorem taxes		27,348			5,118			77,757			15,419
Gathering and transportation expenses		4,405			3,026			15,356			4,432
General and administrative		29,374			22,007			114,505			74,417
Depreciation, depletion and amortization		139,956			69,731			411,558			180,932
Accretion		3,258			2,297			9,868			6,832
		333,069			188,421			1,012,583			535,597
Income from Operations		386,468			110,548			1,062,734			243,612
Other Income (Expense)
Gain on sale of assets		-			-			34,658			-
Interest expense		(32,994	)		(18,165	)		(87,114	)		(35,223	)
Debt extinguishment costs		(3,138	)		-			(13,401	)		-
Gain (loss) on mark-to-market derivative contracts		451,083			(39,155	)		390,175			(75,582	)
Other income (expense)		(13,842	)		(372	)		(12,181	)		952
Income Before Income Taxes		787,577			52,856			1,374,871			133,759
Income tax (expense) benefit
Current		(210,023	)		2,183			(312,276	)		2,183
Deferred		(84,409	)		(22,179	)		(203,031	)		(57,194	)
Net Income	$	493,145		$	32,860		$	859,564		$	78,748
Earnings per Share
Basic	$	4.58		$	0.45		$	7.87		$	1.09
Diluted	$	4.50		$	0.45		$	7.72		$	1.07
Weighted Average Shares Outstanding
Basic		107,725			72,859			109,195			72,499
Diluted		109,617			73,811			111,297			73,526

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,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	859,564		$	78,748
Items not affecting cash flows from operating activities
Gain on sale of assets		(34,658	)		-
Depreciation, depletion, amortization and accretion		421,426			187,764
Deferred income taxes		203,031			57,194
Debt extinguishment costs		13,401			-
(Gain) loss on commodity derivative contracts		(390,175	)		75,582
Noncash compensation		38,931			26,741
Other noncash items		4,230			220
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(65,749	)		(31,770	)
Accounts payable and other liabilities		(50,317	)		(7,855	)
Stock appreciation rights		(59,056	)		(6,591	)
Income taxes receivable/payable		206,311			(94,272	)
Net cash provided by operating activities		1,146,939			285,761
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(688,205	)		(476,314	)
Acquisition of oil and gas properties		(2,012,969	)		(975,407	)
Acquisition of Pogo Producing Company		(76,645	)		-
Derivative settlements		(36,212	)		(74,759	)
Proceeds from property sales, net of costs and expenses		1,736,059			-
Decrease in restricted cash		59,092			-
Additions to other property and equipment		(34,448	)		(28,588	)
Other		(1,671	)		(10,869	)
Net cash used in investing activities		(1,054,999	)		(1,565,937	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		11,501,352			1,989,565
Repayments		(11,672,221	)		(1,745,065	)
Proceeds from issuance of long-term debt		400,000			1,100,000
Cost incurred in connection with financing arrangements		(25,448	)		(18,182	)
Derivative settlements		(24,097	)		-
Purchase of treasury stock		(304,192	)		(47,485	)
Other		9,647			5,041
Net cash (used in) provided by financing activities		(114,959	)		1,283,874
Net (decrease) increase in cash and cash equivalents		(23,019	)		3,698
Cash and cash equivalents, beginning of period		25,446			899
Cash and cash equivalents, end of period	$	2,427		$	4,597

See notes to consolidated financial statements.

3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

				Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Income								Total
	Common Stock											Treasury Stock
	Shares	Amount										Shares		Amount
Balance at December 31, 2007	112,841	$	1,128	$	2,711,617		$	623,993	$	1,566		(1	)	$	(57	)	$	3,338,247
Net income	-		-		-			859,564		-		-			-			859,564
Restricted stock awards	19		-		42,982			-		-		-			-			42,982
Treasury stock purchases	-		-		-			-		-		(5,771	)		(304,192	)		(304,192	)
Issuance of treasury stock for restricted stock awards	-		-		(25,786	)		-		-		475			25,786			-
Other comprehensive income	-		-		-			-		(70	)	-			-			(70	)
Exercise of stock options	13		-		257			-		-		-			-			257
Balance at September 30, 2008	112,873	$	1,128	$	2,729,070		$	1,483,557	$	1,496		(5,297	)	$	(278,463	)	$	3,936,788

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 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.

We are an independent energy company 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 exploration prospects offshore New Zealand and Vietnam.

These consolidated financial statements and related notes present our consolidated financial position as of September 30, 2008 and December 31, 2007, the results of our operations for the three months and nine months ended September 30, 2008 and 2007, our cash flows for the nine months ended September 30, 2008 and 2007 and the changes in stockholders’ equity for the nine months ended September 30, 2008. 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, 2008 are not necessarily indicative of the results of our operations to be expected for the full year.

These 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 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, 2007.

Asset Retirement Obligations. The following table reflects the changes in our asset retirement obligation during the nine months ended September 30, 2008 (in thousands):

Asset retirement obligation - December 31, 2007	$	195,408
Property dispositions		(14,287	)
Settlements		(2,080	)
Accretion expense		9,868
Acquisitions		1,697
Asset retirement additions		2,877
Asset retirement obligation - September 30, 2008 (1)	$	193,483
(1) $10.3 million included in other current liabilities.

Earnings Per Share. For the three months and nine months ended September 30, 2008 and 2007 the weighted average shares outstanding for computing basic and diluted earnings per share (“EPS”) were (in thousands):

	Three Months Ended September 30,		Nine Months Ended September 30,
	2008	2007	2008	2007
Weighted average common shares outstanding - basic	107,725	72,859	109,195	72,499
Unvested restricted stock, restricted stock units and stock options	1,892	952	2,102	1,027
Weighted average common shares outstanding - diluted	109,617	73,811	111,297	73,526

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. Materials and supplies inventories are stated at the lower of cost or market with cost determined on an average cost method. Our inventories consist of (in thousands):

	September 30, 2008		December 31, 2007
Oil	$	7,003	$	6,066
Materials and supplies		22,640		12,328
	$	29,643	$	18,394

Write-downs under full cost ceiling test rules. We follow the full cost method of accounting. Under the SEC’s full cost accounting rules we review the carrying value of our proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and gas properties (net of accumulated depreciation, depletion and amortization, and 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 and require a write-down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. 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 significantly in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. At September 30, 2008, the ceiling with respect to our oil and gas properties exceeded the net capitalized costs of those properties by approximately $3.0 billion.

Goodwill.We account for goodwill in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment is the condition that exists 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 a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of that 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 described above, we follow the full cost method of accounting, and all of our producing properties are located in the United States. We have determined that for purposes of performing an impairment test in accordance with SFAS 142, we have one reporting unit. SFAS 142 states that quoted market prices in active markets, if available, are the best evidence of fair value and should be used as the basis for the fair value measurement. Accordingly, we use the quoted market price of our common stock as a starting point in determining the fair value of our reporting unit.

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. Factors that could result in the impairment of our goodwill include significant declines in oil and gas prices and/or estimated reserve volumes, either of which could trigger a decline in the fair value of our reporting unit.

6

Due to the adverse market conditions that had a pervasive impact on the U.S. business climate near the end of the third quarter of 2008, we performed a goodwill impairment test as of September 30, 2008. 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 at September 30, 2008, and we concluded that our goodwill was not impaired as of September 30, 2008. We determined the control premium through reference to control premiums in recent acquisition transactions for our industry and other comparable industries. If market conditions continue to deteriorate and our common stock price continues to decline in the fourth quarter, we could have an impairment of our goodwill at December 31, 2008.

Stockholders’ Equity. Our Board of Directors has authorized the repurchase of up to $1.0 billion of our common stock. The shares will be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. During the nine months ended September 30, 2008 we repurchased approximately 5.8 million common shares at a cost of approximately $304.2 million. We may expend an additional $695.8 million under the program.

Comprehensive Income. Other comprehensive income consisted of (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007
Net Income	$	493,145		$	32,860	$	859,564		$	78,748
Other Comprehensive Income Pension liability adjustment, net of tax benefit		(23	)		-		(70	)		-
Comprehensive Income	$	493,122		$	32,860	$	859,494		$	78,748

Recent Accounting Pronouncements. In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R broadens the guidance of SFAS 141, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. It broadens the fair value measurement and recognition of assets acquired, liabilities assumed, and interests transferred as a result of business combinations and requires that acquisition-related costs incurred prior to the acquisition be expensed. SFAS 141R also expands the definition of what qualifies as a business, and this expanded definition could include prospective oil and gas property acquisitions. This could require us to expense transaction costs for future oil and natural gas property purchases that we have historically capitalized. Additionally, SFAS 141R expands the required disclosures to improve the financial statement users’ ability to evaluate the nature and financial effects of business combinations. SFAS 141R is effective for business combinations for which the acquisition date is on or after January 1, 2009, except for certain income tax effects related to prior business combinations for which FAS 141R is now effective.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We do not expect this pronouncement to have a significant impact on our consolidated financial position, results of operations or cash flows.

7

In September 2008, the FASB issued FASB Staff Position (“FSP”) FAS 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (“FSP FAS 133-1 and FIN 45-4”). This FSP amends FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”, to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument. This FSP also amends FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”, to require additional disclosure about the current status of the payment/performance risk of a guarantee. Further, this FSP clarifies the FASB’s intent about the effective date of SFAS 161. This FSP is effective for reporting periods (annual or interim) ending after November 15, 2008. We do not expect this FSP to have a significant impact on our consolidated financial position, results of operations or cash flows.

Note 2—Acquisitions

Pogo Producing Company

On November 6, 2007, we acquired Pogo Producing Company (“Pogo”) in a stock and cash transaction. We paid cash consideration of approximately $1.5 billion and issued approximately 40 million common shares valued at approximately $2.0 billion. In addition, we paid cash consideration of $35.4 million to redeem outstanding stock options. The total purchase price included $154.2 million of merger costs. We accounted for the Pogo acquisition as a purchase effective November 6, 2007, and the assets and liabilities were recorded at their fair value. We have finalized the purchase price allocation as of September 30, 2008, and during the first nine months of 2008, goodwill related to the acquisition was decreased by $1.5 million.

Unaudited Pro Forma Information

The following unaudited pro forma information shows the pro forma effect on our results for the three months and nine months ended September 30, 2007 of the Pogo acquisition and certain other material acquisition and financing transactions, including: (1) the acquisition of certain properties located in the Piceance Basin for $975 million in cash and one million shares of common stock in May 2007, (2) the issuance by PXP of $500 million of 7% Senior Notes due 2017 in March 2007, (3) the issuance by PXP of $600 million of 7³/₄% Senior Notes due 2015 in June 2007, (4) $2.0 billion of borrowings under the senior revolving credit facility, and (5) the retirement of Pogo’s $450 million 7.875% Senior Subordinated Notes due 2013, $300 million 6.625% Senior Subordinated Notes due 2015, and $500 million 6.875% Senior Subordinated Notes due 2017. We believe the assumptions used provide a reasonable basis for presenting the pro forma significant effects directly attributable to these transactions. This unaudited pro forma information assumes such transactions occurred on January 1, 2007. This pro forma financial information does not purport to represent what our results of operations would have been if such transactions had occurred on that date.

8

	Three Months Ended September 30, 2007		Nine Months Ended September 30, 2007
	(in thousands except per share data)
	(unaudited)
Revenues	$	500,041	$	1,444,320
Income from continuing operations		25,144		15,172
Net income		25,144		15,172
Basic and diluted earnings per share
Income from continuing operations	$	0.22	$	0.13
Net income	$	0.22	$	0.13
Weighted average shares outstanding
Basic		112,859		113,050
Diluted		113,811		114,077

South Texas Properties

On April 17, 2008, we completed the acquisition of oil and gas producing properties in South Texas from a private company. After the exercise of third party preferential rights, we paid approximately $282 million in cash. We funded the acquisition primarily with proceeds from recently completed divestments through the use of a tax deferred like-kind exchange (see Note 3—Divestitures). We estimate that proved reserves were approximately 93 billion cubic feet of natural gas equivalent as of December 31, 2007. The effective date of the transaction was January 1, 2008.

Piceance Basin Expansion

On June 27, 2008, PXP and a subsidiary of Occidental Petroleum Corporation (“Oxy”) acquired from a third party working interests in acreage immediately adjacent to our existing Piceance Basin assets. PXP and Oxy, a 50% owner in our Piceance Basin assets, agreed to pay an aggregate of $158.6 million for a 95% working interest comprising approximately 11,500 net acres. Under the terms of the acquisition agreement, we paid approximately $20.3 million on June 27, 2008, with the remaining balance payable in equal amounts of approximately $20.3 million on July 1, 2009 and July 1, 2010 and approximately $18.5 million on July 1, 2011. PXP’s total consideration of $79.3 million was allocated to oil and gas properties not subject to amortization. Of the $59.0 million of unpaid consideration, $20.2 million is included in Other Current Liabilities and $38.8 million is included in Other Long-Term Liabilities on our Consolidated Balance Sheet at September 30, 2008. On September 24, 2008 we agreed to sell our interest in these properties to Oxy (see Note 3—Divestitures). Oxy will assume our obligation for the unpaid consideration in connection with the sale, which is expected to close in December 2008.

Chesapeake Joint Venture

On July 7, 2008, we acquired from a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) a 20% interest in Chesapeake’s Haynesville Shale leasehold as of June 30, 2008 for approximately $1.65 billion in cash, subject to customary post-closing adjustments. 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. In addition, we will have the option to participate for 20% of any additional leasehold that Chesapeake, or its affiliates, acquires in the Haynesville Shale within a designated area of mutual interest. At the acquisition date, there were no material proved reserves associated with the 110,000 net acres we acquired. Amounts incurred in connection with this acquisition were allocated to oil and natural gas properties not subject to amortization.

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Note 3—Divestitures

On February 29, 2008, we closed the sale of certain oil and gas properties to a subsidiary of Oxy and certain other companies with contractual preferential rights to purchase, with an effective date of January 1, 2008, and received approximately $1.53 billion in cash proceeds. We sold 50% of our working interests in oil and gas properties located in the Permian Basin, West Texas and New Mexico. We retained 50% of our working interest in these properties. We acquired the above referenced properties in the Pogo acquisition on November 6, 2007, and the property revenues and expenses were included in our historical consolidated statement of income beginning on that date through the closing date of the sale. We also sold 50% of our working interests in oil and gas properties located in the Piceance Basin in Colorado, including a 50% interest in the entity that holds our interest in Collbran Valley Gas Gathering LLC (“CVGG”), and we retained 50% of our working interest in these oil and gas properties. We acquired these properties on May 31, 2007, and the property revenues and expenses were included in our historical consolidated statement of income beginning on that date through the closing date of the sale. We recorded a $34.7 million pretax gain on the sale of the 50% interest in the entity that holds our interest in CVGG.

On February 15, 2008, we closed the sale to XTO Energy Inc. (“XTO”) of our interests in certain oil and gas properties located in the San Juan Basin in New Mexico and in the Barnett Shale in Texas. This transaction had an effective date of January 1, 2008, and we received $199.0 million in cash proceeds. On February 29, 2008, we completed the acquisition of XTO’s 50% working interest in the Big Mac prospect located on the Texas Gulf Coast for approximately $20.2 million.

Our aggregate working interest in the properties sold in February 2008 generated total sales volumes of approximately 11 thousand barrels of oil equivalent per day (“MBOEPD”) during the first quarter of 2008 and had 105 million barrels of oil equivalent (“BOE”) of estimated proved reserves as of December 31, 2007.

We follow the full cost method of accounting under which proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless these sales involve a significant change in the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. No gain or loss was recognized on these sales of oil and gas properties, as the sales did not cause a significant change in the relationship between our capitalized costs and estimated proved reserves. The proceeds from these sales of oil and gas properties were recorded as reductions to our capitalized costs.

On September 24, 2008, we agreed to sell all of our remaining interests in the Permian Basin and the Piceance Basin, including the Piceance Basin Expansion properties (see Note 2—Acquisitions) to Oxy for $1.25 billion. Our aggregate working interest in these properties generated total sales volumes of approximately 13 MBOEPD during the third quarter of 2008 and had 92 MMBOE of estimated proved reserves as of December 31, 2007. This sale, which is subject to customary closing conditions, is expected to close in December 2008. We anticipate that proceeds from this sale will be recorded as a reduction to capitalized costs as we do not anticipate a significant change in the relationship between our capitalized costs and estimated proved reserves.

Note 4—Long-Term Debt

At September 30, 2008 and December 31, 2007, long-term debt consisted of (in thousands):

	September 30, 2008		December 31, 2007
Senior revolving credit facility	$	2,034,131	$	2,205,000
7 3/4% Senior Notes		600,000		600,000
7% Senior Notes		500,000		500,000
7 5/8% Senior Notes		400,000		-
	$	3,534,131	$	3,305,000

During 2008, the borrowing base and commitments under our senior revolving credit facility were adjusted as a result of oil and gas property acquisitions and divestitures and completion of the offering of $400 million of 7⁵/₈% senior notes due 2018 (the “7⁵/₈% Senior Notes”). Additionally, in February 2008, we entered into an amendment to our senior revolving credit facility, which allows us to repurchase up to $1.0 billion of our common stock, subject to certain conditions being met. During 2008, we recognized $13.4 million of debt extinguishment costs related to the changes in our commitments under our senior revolving credit facility.

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Our senior revolving credit facility, as amended, contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries to, among other things, 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, 2008, we had approximately $2.0 billion outstanding and $665 million available under our senior revolving credit facility, and our borrowing base and commitments were $3.1 billion and $2.7 billion, respectively. At September 30, 2008, we had $0.7 million in letters of credit outstanding under our senior revolving credit facility, and the effective interest rate on our borrowings under the facility was 4.14%.

We have an uncommitted short-term unsecured credit facility under the terms of which we may make borrowings from time to time until June 1, 2009, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than June 1, 2009. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and PXP.

In May 2008, we issued the 7⁵/₈% Senior Notes at par. We may redeem all or part of the 7⁵/₈% Senior Notes on or after June 1, 2013 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 1, 2011 we may, at our option, redeem up to 35% of the 7⁵/₈% 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 7⁵/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 7 ³/4% Senior Notes due 2015, the 7% Senior Notes due 2017 and the 7⁵/₈% Senior Notes (together, “the Senior Notes”) are our general unsecured, senior obligations. The Senior Notes are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. The 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 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.

The indenture governing the Senior Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional debt; make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock; sell assets, including capital stock of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; create liens that secure debt; enter into transactions with affiliates; and merge or consolidate with another company.

Subsequent Event.Effective upon the closing of the asset sale to Oxy, certain modifications to our senior revolving credit facility will occur. On October 22, 2008, we entered into a letter agreement, which will decrease the borrowing base from $3.1 billion to $2.7 billion. The borrowing base will remain subject to the redetermination provisions of the senior revolving credit facility. Upon the receipt of proceeds from the asset sale, we will voluntarily decrease the aggregate commitments of the lenders under our senior revolving credit facility from $2.7 billion to $2.3 billion. These modifications will be effective upon the closing of the asset sale to Oxy for $1.25 billion, which is expected to occur in December 2008 (see Note 3—Divestitures). The other terms and conditions of the senior revolving credit facility will remain the same.

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Note 5—Derivative Instruments

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.

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

During June 2008, we entered into crude oil put option contracts on 40,000 barrels of oil per day in 2009 and 2010. The 2009 put options have an average strike price of $106.16 per barrel and an average deferred premium plus interest of $6.19 per barrel, and the 2010 put options have an average strike price of $111.49 per barrel and an average deferred premium plus interest of $12.08 per barrel. The put options for 2009 and 2010 are settled annually based on a calendar year average price. We also acquired natural gas collars with an average floor price of $10.00 per million British thermal units (“MMBtu”) and an average ceiling price of $20.00 per MMBtu on 150,000 MMBtu per day for the months of July 2008 through December 2009. The average deferred premium plus interest is $0.346 per MMBtu and is settled monthly.

At September 30, 2008, we had the following open commodity derivative positions, none of which were designated as hedging instruments:

Period	Instrument Type	Daily Volumes	Average Price(1)	Index
Sales of Crude Oil Production
2008
Oct - Dec	Put options	42,000 Bbls	$55.00 Strike price	WTI
Oct - Dec	Collar	2,500 Bbls	$60.00 Floor - $80.13 Ceiling	WTI
2009
Jan - Dec	Put options	32,500 Bbls	$55.00 Strike price	WTI
Jan - Dec	Put options	40,000 Bbls	$106.16 Strike price	WTI
2010
Jan - Dec	Put options	40,000 Bbls	$111.49 Strike price	WTI
Sales of Natural Gas Production
2008
Oct - Dec	Collar	15,000 MMBtu	$8.00 Floor - $12.11 Ceiling	Henry Hub
Oct - Dec	Collar	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	Henry Hub
2009
Jan - Dec	Collar	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	Henry Hub

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

The only cash settlements we are required to make on the purchased put options are option premiums and interest. Commodity derivative liabilities at September 30, 2008 include deferred premium and associated accrued interest of (i) approximately $14.5 million for the last three months of 2008, which will be paid ratably each month, (ii) approximately $38.7 million which will be paid ratably each month in 2009, (iii) approximately $85.4 million which will be paid after the end of the 2009 annual period in January 2010 and (iv) approximately $161.3 million for 2010, which will be paid after the end of the 2010 annual period in January 2011.

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For a collar contract, (i) we are required to pay cash settlements to the counterparty if the settlement price for any settlement period is above the ceiling price, (ii) the counterparty is required to pay cash settlements to us if the settlement price for any settlement period is below the floor price and (iii) neither party is required to pay cash settlements to the other party if the settlement price for any settlement period is equal to or between the floor and ceiling price. We are required to pay premiums and interest for the natural gas collars with daily volumes of 150,000 MMBtu per day. Commodity derivative liabilities at September 30, 2008 include deferred premium and associated accrued interest of approximately $4.7 million for the last three months of 2008 and approximately $18.6 million for 2009. These payments will be made on the monthly settlement dates.

At September 30, 2008 and December 31, 2007, commodity derivative assets and liabilities consisted of the following (in thousands):

	September 30, 2008			December 31, 2007
Commodity derivative assets
Crude oil puts	$	529,534		$	3,786
Natural gas collars		143,079			4,378
Commodity derivative liabilities
Crude oil collars		(5,077	)		-
Natural gas collars		-			(13,314	)
Net derivative fair value asset (liability)		667,536			(5,150	)
Deferred premium and accrued interest on puts and collars		(323,294	)		(93,902	)
Settlement payable		(6,544	)		(12,521	)
Net commodity derivative asset (liability)	$	337,698		$	(111,573	)
Short-term commodity derivative asset	$	79,236		$	2,186
Long-term commodity derivative asset		293,439			-
Short-term commodity derivative liability		(30,262	)		(79,938	)
Long-term commodity derivative liability(1)		(4,715	)		(33,821	)
	$	337,698		$	(111,573	)

⁽¹⁾ Included in other long-term liabilities

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

Note 6—Stock Based Compensation

We account for stock based compensation in accordance with the provisions of SFAS No.123R, “Share-Based Payment” (“SFAS 123R”) that requires us to recognize compensation cost relating to share-based payment transactions in our financial statements.

Stock based compensation for the three and nine months ended September 30, 2008 and 2007 was (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Stock-based compensation included in:
General and administrative expense	$	6,835		$	5,252		$	39,151		$	25,226
Lease operating expenses		(8,355	)		(130	)		(220	)		1,517
Oil and natural gas properties		(2,774	)		1,541			8,769			6,121
Total stock-based compensation	$	(4,294	)	$	6,663		$	47,700		$	32,864

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Negative amounts in the above table are a result of decreases in the fair value of stock appreciation rights (“SARs”) as a result of decreases in our common stock price.

Stock Appreciation Rights

The following table summarizes the status of our SARs at September 30, 2008 and the changes during the nine months then ended:

	Outstanding (thousands)		Weighted Average Exercise Price		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractual Life (Years)
Outstanding at January 1, 2008	2,767		$	28.90
Granted	769			51.32
Exercised	(1,373	)		13.75
Forfeited or expired	(150	)		48.78
Outstanding at September 30, 2008	2,013			46.30	$	1,270	3.4
Exercisable at September 30, 2008	564			38.09	$	1,270	2.0

We paid $59.1 million for SARs exercised during the nine months ended September 30, 2008 and our liability associated with SARs decreased from $68.4 million at December 31, 2007 to $6.4 million at September 30, 2008.

Restricted Stock and Restricted Stock Units (“RSUs”)

The following table summarizes the status of our restricted stock and RSUs at September 30, 2008 and the changes during the nine months then ended:

	Equity Instruments (thousands)		Weighted Average Grant Date Fair Value		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractual Life (Years)
Nonvested at January 1, 2008	4,843		$	44.73
Granted	2,176	(1)		52.28
Vested	(784	)		42.60
Forfeited	(28	)		46.94
Nonvested at September 30, 2008	6,207			47.64	$	218,238	5.1
(1)      The amount granted includes five annual grants of 200,000 RSUs commencing on September 30, 2015. The first three annual grants will each vest in full in 2020, and the fourth and fifth annual grants will each vest ratably over a three-year period from the date of grant. Under the provisions of SFAS 123R, the grant date for accounting purposes for all 1.0 million RSUs to be granted in the future is March 12, 2008.

As of September 30, 2008, there was $225.5 million of total unrecognized compensation cost related to unvested RSUs that is expected to be recognized over a period of 5.1 years.

In addition, under the terms of our Long-Term Retention and Deferred Compensation Plan, annual grants may be increased if certain common stock price performance targets are achieved. We estimated the value and number of RSUs expected to be granted in the future by using a Monte-Carlo simulation model. The model involves forecasting potential future stock price paths based on the expected return on the common stock and its volatility, then calculating the number of RSUs expected to be granted based on the results of the simulations. Pursuant to this simulation model, we estimated that 0.4 million RSUs are expected to be granted. Such units had a weighted average grant date fair value of $46.62 per unit, an aggregate fair value of $18.7 million and a weighted average remaining contractual life of 5.6 years.

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Note 7—Fair Value Measurements of Assets and Liabilities

Effective January 1, 2008, we adopted SFAS No. 157 “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. SFAS 157 does not require any new fair value measurements but may require some entities to change their measurement practices. Pursuant to SFAS 157, we have revised our fair value calculations to consider our credit quality and the credit quality of our counterparties. The credit quality of our counterparties had a significant effect on the fair value of our commodity derivative contracts in our consolidated financial position and results of operations in the third quarter of 2008. These fair value adjustments had no impact on our consolidated cash flows.

As defined in SFAS 157, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (“exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of fair value under SFAS 157 are as follows:

• Level 1 – Quoted, unadjusted prices for assets or liabilities in active markets for identical assets or liabilities as of the reporting date.

• Level 2 – Market-based inputs that are directly or indirectly observable but not considered Level 1 quoted prices, including quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; or valuation techniques whose inputs are observable. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

• Level 3 – Valuation techniques whose significant inputs are unobservable.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement.

We estimate the fair values of our derivative instruments, including crude oil put options, crude oil collars and natural gas collars using an option-pricing model. The option-pricing model 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. We use the credit default swap value for counterparties, when available or the spread between the risk-free interest rates and the yield on the counterparty’s publicly-traded debt for similar maturities. We consider the impact of master netting agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability.

We classify our derivatives as Level 2 if the inputs used in the valuation model are directly or indirectly observable as described above; however, if the significant inputs are not observable, we classify those derivatives as Level 3. For our derivatives classified as Level 3, certain inputs that were significant to the overall fair value measurement were not observable for substantially the full term of the instrument. For these inputs, we utilize pricing and volatility information from other instruments with similar characteristics. Our crude oil put options that are settled annually and our natural gas collars with an average floor price of $10.00 and average ceiling price of $20.00 are classified as Level 3 instruments.

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The following table presents, for each fair value hierarchy level, our commodity derivative assets and liabilities related to continuing operations which are measured at fair value on a recurring basis as of September 30, 2008 (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)
Commodity derivative assets	$	672,613	$	-	$	11,703	$	660,910
Commodity derivative liabilities		5,077		-		5,077		-

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

The following table presents a reconciliation of changes in fair value of financial assets and liabilities classified as Level 3 (in thousands):

	Commodity Derivative Contracts(1)
Fair value at January 1, 2008	$	-
Realized and unrealized gains included in earnings		401,142
Purchases and settlements		259,768
Transfers		-
Fair value at September 30, 2008	$	660,910
Realized and unrealized gains included in earnings related to financial assets and liabilities on the Consolidated Balance Sheet as of September 30, 2008(2)	$	401,142
Change in unrealized gains and losses relating to assets and liabilities still held as of September 30, 2008(2)	$	389,759
(1)      Option premium and 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 (loss) on mark-to-market derivative contracts in our Consolidated Statements of Income.

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We consider the credit quality of our counterparties when we value our commodity derivatives. At September 30, 2008, we had the following commodity derivative net asset (liability) balances with counterparties rated by Standard & Poor’s (“S&P”) (in thousands):

S&P Rating	Fair Value		Deferred Premium Liability		Net Asset (Liability)
AA+ / Stable	$	220,753	$	109,045	$	111,708
AA- / Stable		243		-		243
AA / Watch Negative		39,006		5,479		33,527
AA / Negative		32		1,753		(1,721	)
AA- / Negative		181,234		105,315		75,919
A+ / Stable		57,985		11,521		46,464
A+ / Negative		168,283		90,181		78,102
	$	667,536	$	323,294	$	344,242

We present the fair value of our derivatives for which a master netting agreement exists on a net basis in accordance with FIN 39.

In November 2007, the FASB agreed to a one-year deferral of SFAS 157 fair value measurement requirements for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. In February 2008, the FASB issued FSP SFAS 157-2 “Effective date of SFAS 157.” This FSP defers the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 and interim periods within those fiscal years for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We have elected to utilize this deferral and have only partially applied SFAS 157 (to financial assets and liabilities measured at fair value on a recurring basis, as described above). Accordingly, we will apply SFAS 157 to our nonfinancial assets and liabilities, which we disclose or recognize at fair value on a nonrecurring basis, such as asset retirement obligations,goodwill impairment and other assets and liabilities, in the first quarter of 2009. We do not expect that the application of SFAS 157 to our nonfinancial assets and liabilities, which we disclose or recognize at fair value on a nonrecurring basis will have a significant impact on our consolidated financial position, results of operations or cash flows.

In October 2008, the FASB issued FSP SFAS 157-3. This FSP clarifies the application of SFAS 157 in a market that is not active and provides for an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. We determined whether the market for our derivative instruments is active or inactive based on transaction volume for such instruments and classified those instruments that we determined were not actively traded as Level 3 instruments. We value these Level 3 instruments using similar instruments and extrapolating data between data points for thinly traded instruments. This FSP was effective upon issuance, including prior periods for which financial statements have not been issued. The adoption of FSP SFAS 157-3 did not have a significant impact on our consolidated financial position, results of operations or cash flows.

We adopted SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of SFAS No. 115” (“SFAS 159”) on January 1, 2008. SFAS 159 permits companies to choose to measure financial instruments and certain other items at fair value that were not previously required to be measured at fair value. We have elected not to present assets and liabilities at fair value that were not required to be measured at fair value prior to the adoption of SFAS 159.

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Note 8—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 and nine months ended September 30, 2008, income tax expense was approximately 37% of pretax income. Variances in our estimated annual effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes and estimated permanent differences, which include (1) the special deduction for domestic production and (2) expenses that are not deductible because of Internal Revenue Service limitations. Specific items that affected income tax expense for the nine months ended September 30, 2008 included state tax rate changes due to asset acquisitions and divestitures and changes to our balance of unrecognized tax positions.

We file income tax returns in the United States and various state and foreign jurisdictions. With respect to the previously filed PXP, Nuevo Energy Company and 3TEC Energy Corporation tax returns, we are no longer subject to U.S. federal and state income tax examinations by authorities for years before 1996. For the previously filed Pogo tax returns, we are no longer subject to U.S. federal and state income tax examinations for years prior to 2005. During the third quarter of 2008, the IRS began an examination of Pogo’s federal tax return for 2006.

The IRS is currently examining the PXP and Nuevo federal income tax returns for 2003 and 2004, the fieldwork for which is anticipated to be completed in the fourth quarter of 2008. As this IRS audit remains ongoing, it is possible that changes will occur to the balance of our unrecognized tax benefits during the next 12 months as the IRS finalizes its examination. The financial impact of these future changes cannot be determined at this time.

At September 30, 2008, we had approximately $44.8 million of gross unrecognized tax benefits. If all unrecognized tax benefits were recognized, approximately $37.9 million would impact our effective tax rate in future periods (including all indirect tax effects in other jurisdictions). Both of these amounts have increased over the corresponding amounts that existed at December 31, 2007 as a result of our ongoing assessment of developments related to the IRS examinations.

Note 9—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.

On April 10, 2008, a coalition of California environmental organizations announced the signing of an agreement with us and the coalition’s support of our Tranquillon Ridge Project offshore California. We believe the organizations’ support will improve our chance of receiving a new state oil and gas lease and attendant operating permits. In return for the coalition’s support and upon completion of certain permitting and operational objectives, the agreement provides certain benefits to the communities in Santa Barbara County and to the state of California, including a firm end date prohibiting the extension of our existing oil and gas operations, our donation of 3,900 acres of lands and full mitigation of greenhouse gases from the project if Tranquillon Ridge is permitted and proves to be a commercial success. We also agreed to donate $1.5 million to further reduce greenhouse gas emissions in the county and withdraw permits for the approximately 800 acre Purisima Hills residential project if permitting, which is subject to approval by certain California agencies, is successful. In October 2008, we received final approval for this project from Santa Barbara County. We anticipate the remaining state and federal permitting reviews to take place over the next several months.

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 assure you that we will be able to collect on these indemnities.

18

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, $44 million ($81 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 $46 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At September 30, 2008, the escrow account had a balance of $9.6 million. The fair value of our guarantee at September 30, 2008 was $0.3 million and is included in Other Long-Term Liabilities in the 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 susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. We maintain coverage for earthquake damages in California, but this coverage may not provide for the full effect of damages that could occur, and we may be subject to additional liabilities. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.

In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. During the third and fourth quarters of 2008, the volatility and disruption in the financial and credit markets reached unprecedented levels, which may adversely affect the credit quality of our insurers and impact their ability to pay our 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 November 15, 2005, the United States Court of Federal Claims issued a ruling granting the plaintiffs’ motion for summary judgment as to liability and partial summary judgment as to damages in the breach of contract lawsuit Amber Resources Company et al. v. United States, Case No. 02-30c. The court’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold 36 federal leases offshore California. The court further ruled that the Government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On October 31, 2006, the court issued an unfavorable decision on the plaintiff’s motion for partial summary judgment concerning plaintiffs’ additional claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas in the disputed lease area, and other matters. Plaintiffs filed a motion for final judgment on November 29, 2006 and the court granted such motion on January 11, 2007. Judgment on $1 billion on 35 leases was filed January 12, 2007. The United States has filed an appeal and Plaintiffs filed a cross-appeal concerning the Court’s October 31, 2006 decision. The United States Court of Appeals for the Federal Circuit affirmed on August 25, 2008 the trial court’s judgment in all respects concluding that the lessees may recover $1 billion in lease bonuses paid. The United States filed combined petitions for rehearing and rehearing en banc in October 2008. No payments will be made until all appeals have either been waived or exhausted. We are among the current lessees of the 35 leases. Our share of the $1.0 billion award is in excess of $80 million.

19

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.

On July 7, 2008, we acquired from a subsidiary of Chesapeake a 20% interest in Chesapeake’s Haynesville Shale leasehold as of June 30, 2008 for approximately $1.65 billion in cash, subject to customary post-closing adjustments. 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.

Note 10—Consolidating Financial Statements

We are the issuer of $600 million of 7³/₄% Senior Notes, $500 million of 7% Senior Notes and $400 million of 7⁵/₈% Senior Notes, 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.

20

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

SEPTEMBER 30, 2008

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	95		$	32		$	2,300		$	-		$	2,427
Accounts receivable and other current assets		193,159			307,840			1,609			-			502,608
		193,254			307,872			3,909			-			505,035
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,803,558			4,525,021			-			-			7,328,579
Not subject to amortization		352,790			2,775,188			19,367			-			3,147,345
Other property and equipment		45,188			47,440			25,318			-			117,946
		3,201,536			7,347,649			44,685			-			10,593,870
Less allowance for depreciation, depletion and amortization		(676,247	)		(1,369,893	)		(27	)		642,157			(1,404,010	)
		2,525,289			5,977,756			44,658			642,157			9,189,860
Investment in and Advances to Subsidiaries		5,807,357			(1,020,503	)		(39,986	)		(4,746,868	)		-
Other Assets		322,725			569,447			48,787			-			940,959
	$	8,848,625		$	5,834,572		$	57,368		$	(4,104,711	)	$	10,635,854
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	528,355		$	394,947		$	1,239		$	-		$	924,541
Long-Term Debt		3,534,131			-			-			-			3,534,131
Other Long-Term Liabilities		156,165			152,406			-			-			308,571
Deferred Income Taxes		693,186			1,032,391			2,282			203,964			1,931,823
Stockholders’ Equity		3,936,788			4,254,828			53,847			(4,308,675	)		3,936,788
	$	8,848,625		$	5,834,572		$	57,368		$	(4,104,711	)	$	10,635,854

21

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2007

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	15,897		$	2,261		$	7,288		$	-		$	25,446
Accounts receivable and other current assets		255,049			385,720			8,705			-			649,474
		270,946			387,981			15,993			-			674,920
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,632,802			4,707,436			-			-			7,340,238
Not subject to amortization		174,837			1,761,489			15,457			-			1,951,783
Other property and equipment		57,384			11,903			16,641			-			85,928
		2,865,023			6,480,828			32,098			-			9,377,949
Less allowance for depreciation, depletion and amortization		(529,426	)		(788,164	)		(21	)		316,889			(1,000,722	)
		2,335,597			5,692,664			32,077			316,889			8,377,227
Investment in and Advances to Subsidiaries		5,120,045			(682,139	)		(26,292	)		(4,411,614	)		-
Other Assets		24,504			613,264			3,436			-			641,204
	$	7,751,092		$	6,011,770		$	25,214		$	(4,094,725	)	$	9,693,351
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	391,018		$	415,771		$	11,257		$	-		$	818,046
Long-Term Debt		3,305,000			-			-			-			3,305,000
Other Long-Term Liabilities		170,401			102,226			-			-			272,627
Deferred Income Taxes		546,426			1,286,567			2,262			124,176			1,959,431
Stockholders’ Equity		3,338,247			4,207,206			11,695			(4,218,901	)		3,338,247
	$	7,751,092		$	6,011,770		$	25,214		$	(4,094,725	)	$	9,693,351

22

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED SEPTEMBER 30, 2008

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	388,327		$	140,460		$	-		$	-		$	528,787
Gas sales		37,538			144,433			-			-			181,971
Other operating revenues		476			8,303			-			-			8,779
		426,341			293,196			-			-			719,537
Costs and Expenses
Production costs		92,439			68,042			-			-			160,481
General and administrative		20,049			9,194			131			-			29,374
Depreciation, depletion, amortization and accretion		59,712			83,334			11			157			143,214
Full cost ceiling test write-down		-			320,513			-			(320,513	)		-
		172,200			481,083			142			(320,356	)		333,069
Income from Operations		254,141			(187,887	)		(142	)		320,356			386,468
Other Income (Expense)
Equity in earnings of subsidiaries		88,368			756			-			(89,124	)		-
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
Interest and other income (expense)		3,622			(14,613	)		870			(3,721	)		(13,842	)
Income (Loss) Before Income Taxes		751,215			(195,598	)		728			231,232			787,577
Income tax benefit (expense)		(258,070	)		78,043			28			(114,433	)		(294,432	)
Net Income (Loss)	$	493,145		$	(117,555	)	$	756		$	116,799		$	493,145

23

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED SEPTEMBER 30, 2007

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	239,707		$	36,389		$	-	$	-		$	276,096
Gas sales		4,985			17,711			-		-			22,696
Other operating revenues		81			96			-		-			177
		244,773			54,196			-		-			298,969
Costs and Expenses
Production costs		75,660			18,726			-		-			94,386
General and administrative		17,793			4,214			-		-			22,007
Depreciation, depletion, amortization and accretion		38,035			33,993			-		-			72,028
Full cost ceiling test write-down		-			261,000			-		(261,000	)		-
		131,488			317,933			-		(261,000	)		188,421
Income from Operations		113,285			(263,737	)		-		261,000			110,548
Other Income (Expense)
Equity in earnings of subsidiaries		(10,039	)		-			-		10,039			-
Interest expense		(13,884	)		(21,433	)		-		17,152			(18,165	)
Loss on mark-to-market derivative contracts		(39,155	)		-			-		-			(39,155	)
Interest and other income (expense)		17,147			(367	)		-		(17,152	)		(372	)
Income (Loss) Before Income Taxes		67,354			(285,537	)		-		271,039			52,856
Income tax benefit (expense)		(34,494	)		116,309			-		(101,811	)		(19,996	)
Net Income (Loss)	$	32,860		$	(169,228	)	$	-	$	169,228		$	32,860

24

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2008

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	1,084,119		$	447,019		$	-		$	-		$	1,531,138
Gas sales		57,527			470,847			-			-			528,374
Other operating revenues		1,415			14,390			-			-			15,805
		1,143,061			932,256			-			-			2,075,317
Costs and Expenses
Production costs		280,994			195,658			-			-			476,652
General and administrative		71,647			42,727			131			-			114,505
Depreciation, depletion, amortization and accretion		161,192			264,979			11			(4,756	)		421,426
Full cost ceiling test write-down		-			320,513			-			(320,513	)		-
		513,833			823,877			142			(325,269	)		1,012,583
Income from Operations		629,228			108,379			(142	)		325,269			1,062,734
Other Income (Expense)
Equity in earnings of subsidiaries		267,267			1,411			-			(268,678	)		-
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
Interest and other income (expense)		19,184			20,566			1,528			(18,801	)		22,477
Income (Loss) Before Income Taxes		1,259,996			56,898			1,386			56,591			1,374,871
Income tax benefit (expense)		(400,432	)		(486	)		25			(114,414	)		(515,307	)
Net Income (Loss)	$	859,564		$	56,412		$	1,411		$	(57,823	)	$	859,564

25

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2007

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	620,092		$	93,105		$	-		$	-		$	713,197
Gas sales		19,191			44,250			-			-			63,441
Other operating revenues		2,226			345			-			-			2,571
		641,509			137,700			-			-			779,209
									��
Costs and Expenses
Production costs		224,133			49,283			-			-			273,416
General and administrative		63,995			10,422			-			-			74,417
Depreciation, depletion, amortization and accretion		100,141			87,623			-			-			187,764
Full cost ceiling test write-down		-			316,889			-			(316,889	)		-
		388,269			464,217			-			(316,889	)		535,597
Income (Loss) from Operations		253,240			(326,517	)		-			316,889			243,612
Other Income (Expense)
Equity in earnings of subsidiaries		(26,602	)		-			-			26,602			-
Interest expense		(21,737	)		(36,138	)		-			22,652			(35,223	)
Loss on mark-to-market derivative contracts		(75,582	)		-			-			-			(75,582	)
Interest and other income (expense)		23,926			(322	)		-			(22,652	)		952
Income (Loss) Before Income Taxes		153,245			(362,977	)		-			343,491			133,759
Income tax benefit (expense)		(74,497	)		144,737			-			(125,251	)		(55,011	)
Net Income (Loss)	$	78,748		$	(218,240	)	$	-		$	218,240		$	78,748

26

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2008

(in thousands)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	859,564		$	56,412		$	1,411		$	(57,823	)	$	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		161,192			585,492			11			(325,269	)		421,426
Equity in earnings of subsidiaries		(267,267	)		(1,411	)		-			268,678			-
Deferred income taxes		286,927			(163,704	)		20			79,788			203,031
Debt extinguishment costs		13,401			-			-			-			13,401
(Gain) loss on commodity derivative contracts		(408,348	)		18,173			-			-			(390,175	)
Noncash compensation		33,419			5,548			(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		(4,278	)		(64,963	)		3,492			-			(65,749	)
Accounts payable and other liabilities		(13,910	)		(35,798	)		(609	)		-			(50,317	)
Stock appreciation rights		(59,056	)		-			-			-			(59,056	)
Income taxes receivable/payable		206,311			-			-			-			206,311
Net cash provided by (used in) operating activities		810,458			366,358			4,749			(34,626	)		1,146,939
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(308,114	)		(373,842	)		(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	)
Derivative settlements		(36,212	)		-			-			-			(36,212	)
Proceeds from property sales, net of costs and expenses		1,736,059			-			-			-			1,736,059
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		1,367,684			(2,406,086	)		(16,597	)		-			(1,054,999	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		11,501,352			-			-			-			11,501,352
Repayments		(11,672,221	)		-			-			-			(11,672,221	)
Proceeds from issuance of long-term debt		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		(2,079,480	)		2,037,994			6,860			34,626			-
Other		10,142			(495	)		-			-			9,647
Net cash provided by (used in) financing activities		(2,193,944	)		2,037,499			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

27

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2007

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	78,748		$	(218,240	)	$	-		$	218,240		$	78,748
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		100,141			404,512			-			(316,889	)		187,764
Equity in earnings of subsidiaries		26,602			-			-			(26,602	)		-
Deferred income taxes		84,799			(152,856	)		-			125,251			57,194
Loss on commodity derivative contracts		75,582			-			-			-			75,582
Noncash compensation		24,604			2,137			-			-			26,741
Other noncash items		21			199			-			-			220
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(23,747	)		(8,023	)		-			-			(31,770	)
Accounts payable and other liabilities		(6,769	)		(1,086	)		-			-			(7,855	)
Stock appreciation rights		(6,591	)		-			-			-			(6,591	)
Income taxes receivable/payable		(94,272	)		-			-			-			(94,272	)
Net cash provided by operating activities		259,118			26,643			-			-			285,761
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(374,242	)		(102,072	)		-			-			(476,314	)
Acquisition of oil and gas properties		(975,407	)		-									(975,407	)
Derivative settlements		(74,759	)		-			-			-			(74,759	)
Other		(31,669	)		(2,721	)		(5,067	)		-			(39,457	)
Net cash used in investing activities		(1,456,077	)		(104,793	)		(5,067	)		-			(1,565,937	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		1,989,565			-			-			-			1,989,565
Repayments		(1,745,065	)		-			-			-			(1,745,065	)
Proceeds from issuance of long-term debt		1,100,000			-			-			-			1,100,000
Cost incurred in connection with financing arrangements		(18,182	)		-			-			-			(18,182	)
Investment in and advances to affiliates		(83,220	)		78,153			5,067			-			-
Purchase of treasury stock		(47,485	)		-			-			-			(47,485	)
Other		5,041			-			-			-			5,041
Net cash provided by financing activities		1,200,654			78,153			5,067			-			1,283,874
Net increase in cash and cash equivalents		3,695			3			-			-			3,698
Cash and cash equivalents, beginning of period		896			3			-			-			899
Cash and cash equivalents, end of period	$	4,591		$	6		$	-		$	-		$	4,597

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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, 2007.

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:

• the Los Angeles and San Joaquin Basins onshore California;

• the Santa Maria Basin offshore California;

• the Wind River Basin in the Rocky Mountains;

• the Haynesville Shale in North Louisiana and East Texas;

• the Anadarko Basin in the Texas Panhandle; and

• the South Texas and Gulf Coast regions, including the Gulf of Mexico.

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 fixed amount specified in the derivative agreement 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. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk.

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. See Liquidity and Capital Resources.

Recent Events

Capital and Credit Markets

During 2008, there has been extreme volatility and disruption in the capital and credit markets. During the third and fourth quarters of 2008, the volatility and disruption have created conditions that may adversely affect the financial condition of the lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, our insurers and our oil and natural gas purchasers. See Liquidity and Capital Resources.

Chesapeake Joint Venture

On July 7, 2008, we acquired from a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) a 20% interest in Chesapeake’s Haynesville Shale leasehold as of June 30, 2008 for approximately $1.65 billion in cash, subject to customary post-closing adjustments. 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. In addition, we will have the option to participate for 20% of any additional leasehold that Chesapeake, or its affiliates, acquires in the Haynesville Shale within a designated area of mutual interest. At the acquisition date, there were no material proved reserves associated with the 110,000 net acres we acquired. Amounts incurred in connection with this acquisition were allocated to oil and natural gas properties not subject to amortization.

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Other Acquisitions

On April 17, 2008, we completed the acquisition of oil and gas producing properties in South Texas from a private company. After the exercise of third party preferential rights, we paid approximately $282 million in cash. We funded the acquisition primarily with proceeds from recently completed divestments through the use of a tax deferred like-kind exchange. We estimate that proved reserves were approximately 93 billion cubic feet of natural gas equivalent as of December 31, 2007. The effective date of the transaction was January 1, 2008.

On June 27, 2008, PXP and a subsidiary of Occidental Petroleum Corporation (“Oxy”) acquired from a third party working interests in acreage immediately adjacent to our existing Piceance Basin assets. PXP and Oxy, a 50% owner in our Piceance Basin assets, agreed to pay an aggregate of $158.6 million for a 95% working interest comprising approximately 11,500 net acres. Under the terms of the acquisition agreement, we paid approximately $20.3 million on June 27, 2008, with the remaining balance payable in equal amounts of approximately $20.3 million on July 1, 2009 and July 1, 2010 and approximately $18.5 million on July 1, 2011. PXP’s total consideration of $79.3 million was allocated to oil and gas properties not subject to amortization. Of the $59.0 million of unpaid consideration, $20.2 million is included in Other Current Liabilities and $38.8 million is included in Other Long-Term Liabilities on our Consolidated Balance Sheet at September 30, 2008. On September 24, 2008, we agreed to sell our interest in these properties to Oxy. Oxy will assume our obligation for the unpaid consideration in connection with the sale, which is expected to close in December 2008.

Divestments

On February 29, 2008, we closed the sale of certain oil and gas properties to a subsidiary of Oxy and certain other companies with contractual preferential rights to purchase, with an effective date of January 1, 2008, and received approximately $1.53 billion in cash proceeds. We sold 50% of our working interests in oil and gas properties located in the Permian Basin, West Texas and New Mexico. We retained 50% of our working interest in these properties. We acquired the above referenced properties in the Pogo acquisition on November 6, 2007, and the property revenues and expenses were included in our historical consolidated statement of income beginning on that date through the closing date of the sale. We also sold 50% of our working interests in oil and gas properties located in the Piceance Basin in Colorado, including a 50% interest in the entity that holds our interest in Collbran Valley Gas Gathering LLC (“CVGG”), and we retained 50% of our working interest in these oil and gas properties. We acquired these properties on May 31, 2007, and the property revenues and expenses were included in our historical consolidated statement of income beginning on that date through the closing date of the sale. We recorded a $34.7 million pretax gain on the sale of the 50% interest in the entity that holds our interest in CVGG.

On February 15, 2008, we closed the sale to XTO Energy Inc. (“XTO”) of our interests in certain oil and gas properties located in the San Juan Basin in New Mexico and in the Barnett Shale in Texas. This transaction had an effective date of January 1, 2008, and we received $199.0 million in cash proceeds. On February 29, 2008 we completed the acquisition of XTO’s 50% working interest in the Big Mac prospect located on the Texas Gulf Coast for approximately $20.2 million.

Our aggregate working interest in the properties sold in February 2008 generated total sales volumes of approximately 11 thousand barrels of oil equivalent per day (“MBOEPD”) during the first quarter of 2008 and had 105 million barrels of oil equivalent (“BOE”) of estimated proved reserves as of December 31, 2007.

On September 24, 2008, we agreed to sell all of our remaining interests in the Permian Basin and the Piceance Basin (including the Piceance Basin properties acquired with Oxy in June 2008) to Oxy for $1.25 billion. Our aggregate working interest in these properties generated total sales volumes of approximately 13 MBOEPD during the third quarter of 2008 and had 92 MMBOE of estimated proved reserves as of December 31, 2007. This sale, which is subject to customary closing conditions, is expected to close in December 2008.

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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 a write-down if our capitalized costs exceed the allowed “ceiling.” 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 fluctuate in the near term. If oil and gas prices continue to decline significantly in the future, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our estimated proved reserves, our reserve volumes and our revenues, profitability and cash flow. See Critical Accounting Policies and Factors that May Affect Future Results.

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

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

Results Overview

In the first nine months of 2008, we reported net income of $859.6 million, or $7.72 per diluted share compared to net income of $78.7 million, or $1.07 per diluted share in the nine months of 2007. The increase reflects higher sales volumes resulting from our November 2007 acquisition of Pogo Producing Company, (“Pogo”), and higher commodity prices. Net income for the nine months ended September 30, 2008 also includes a $390.2 million pre-tax gain on mark-to-market derivative contracts.

On May 31, 2007, we acquired interests in oil and gas producing properties in the Piceance Basin in Colorado, plus associated midstream assets, and on November 6, 2007, we acquired Pogo, which was engaged in oil and gas exploration, development, acquisition and production activities primarily located in the onshore United States.

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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,
	2008		2007		2008		2007
Sales Volumes
Oil and liquids sales (MBbls)		5,134		4,369		15,399		12,895
Gas (MMcf)
Production		20,722		5,867		60,320		13,134
Used as fuel		524		561		1,659		1,724
Sales		20,198		5,306		58,661		11,410
MBOE
Production		8,588		5,347		25,452		15,084
Sales		8,500		5,252		25,175		14,796
Daily Average Volumes
Oil and liquids sales (Bbls)		55,803		47,482		56,199		47,233
Gas (Mcf)
Production		225,232		63,768		220,145		48,108
Used as fuel		5,691		6,096		6,053		6,313
Sales		219,541		57,672		214,092		41,795
BOE
Production		93,342		58,110		92,890		55,251
Sales		92,393		57,094		91,881		54,199
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	118.22	$	75.15	$	113.52	$	66.19
Gas		10.28		6.18		9.76		6.84
Average Realized Sales Price Before
Derivative Transactions
Oil (per Bbl)	$	103.00	$	63.19	$	99.43	$	55.31
Gas (per Mcf)		9.01		4.28		9.00		5.56
Per BOE		83.62		56.89		81.81		52.49
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	9.06	$	10.04	$	9.40	$	9.96
Steam gas costs		4.40		4.26		4.38		5.18
Electricity		1.69		2.13		1.46		1.99
Production and ad valorem taxes		3.22		0.97		3.09		1.04
Gathering and transportation		0.52		0.58		0.61		0.30
Depreciation, depletion and amortization of oil and gas properties (“DD&A”)		15.71		12.64		15.72		11.59

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Mark-to-market contracts
Crude oil put options and collars	$	(23,953	)	$	(25,615	)	$	(67,061	)	$	(74,759	)
Natural gas collars		6,325			-			6,752			-

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Comparison of Three Months Ended September 30, 2008 to Three Months Ended September 30, 2007

Oil and gas revenues. Oil and gas revenues increased $412.0 million, to $710.8 million for 2008 from $298.8 million for 2007 due to a 62% increase in sales volumes and a $26.73 per barrel of oil equivalent (“BOE”) increase in realized prices.

Oil revenues increased $252.7 million to $528.8 million for 2008 from $276.1 million for 2007 reflecting higher realized prices ($173.9 million) and higher sales volumes ($78.8 million). Our average realized price for oil increased $39.81 to $103.00 per barrel (“Bbl”) for 2008 from $63.19 per Bbl for 2007. The increase in revenue attributable to prices is due to an improvement in the NYMEX oil price, which averaged $118.22 per Bbl in 2008 versus $75.15 per Bbl in 2007, partially offset by an increase in the differential to NYMEX. Oil sales volumes increased 8.3 MBbls per day to 55.8 MBbls per day in 2008 from 47.5 MBbls per day in 2007, primarily reflecting production from the properties acquired in the Pogo acquisition, which had sales of 9.6 MBbls per day in the third quarter of 2008.

Gas revenues increased $159.3 million to $182.0 million in 2008 from $22.7 million in 2007 due to increased sales volumes ($134.2 million) and an increase in realized prices ($25.1 million). Our average realized price for gas was $9.01 per Mcf in 2008 compared to $4.28 per Mcf in 2007. Approximately 87% of the gas revenue increase attributable to prices is due to an improvement in the NYMEX gas price, which averaged $10.28 per Mcf in 2008 versus $6.18 per Mcf in 2007, and the remainder is due to an improvement in our average differential to NYMEX, which averaged $1.27 per Mcf in the third quarter of 2008 versus $1.90 in the third quarter of 2007. Gas sales volumes increased from 57.7 MMcf per day in 2007 to 219.5 MMcf per day in 2008, primarily reflecting production from the properties acquired in the Pogo acquisition in November 2007 (151.6 MMcf per day) and production from the Flatrock project in the Gulf of Mexico (27.3 MMcf per day) in the third quarter of 2008, partially offset by a decrease in production as a result of the hurricanes during the third quarter of 2008 (9.7 MMcf per day). All production impacted by the hurricanes has been restored.

Lease operating expenses. Lease operating expenses increased $24.3 million, to $77.0 million in 2008 from $52.7 million in 2007. Lease operating expenses for 2008 include $31.1 million attributable to the Pogo and Piceance Basin properties acquired in November and May of 2007, respectively. Lease operating expense for the third quarter of 2007 includes $2.3 million of Piceance Basin costs. Excluding these incremental costs, lease operating expenses decreased $4.5 million due primarily to decreased charges for stock appreciation rights ($8.3 million) as a result of a decrease in the price of our common stock, partially offset by an increase in workover expense ($2.3 million). On a per unit basis, lease operating expenses decreased to $9.06 per BOE in 2008 versus $10.04 per BOE in 2007 due to increased sales volumes.

Steam gas costs. Steam gas costs increased $15.1 million, to $37.4 million in 2008 from $22.3 million in 2007, primarily reflecting the higher cost of gas used in steam generation. In 2008, we burned approximately 4.2 billion cubic feet (“Bcf”) of natural gas at a cost of approximately $8.99 per Mcf compared to 4.0 Bcf at a cost of approximately $5.52 per Mcf in 2007.

Electricity. Electricity increased $3.2 million, to $14.4 million in 2008 from $11.2 million in 2007, primarily reflecting rate increases from providers. On a per unit basis, electricity decreased to $1.69 per BOE in 2008 versus $2.13 per BOE in 2007 due to increased sales volume.

Production and ad valorem taxes. Production and ad valorem taxes increased $22.2 million, to $27.3 million in 2008 from $5.1 million in 2007, primarily reflecting increased volumes from the Pogo acquisition ($19.0 million).

Gathering and transportation expenses. Gathering and transportation expenses increased $1.4 million, to $4.4 million in 2008 from $3.0 million in 2007, primarily reflecting increased volumes from the Pogo acquisition.

General and administrative expense. G&A expense increased $7.4 million, to $29.4 million in 2008 compared to $22.0 million in 2007. The increase, net of capitalization, is due to increased personnel and other costs primarily as a result of the Pogo and Piceance Basin acquisitions (approximately $11.6 million), partially offset by a decrease in stock compensation cost of $2.7 million and an increase in capitalized G&A costs related to our acquisition, exploration and development activities. We capitalized $10.6 million and $9.0 million of G&A costs in 2008 and 2007, respectively.

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Depreciation, depletion and amortization. DD&A expense increased $70.3 million, to $140.0 million in 2008 from $69.7 million in 2007. The increase was attributable to our oil and gas DD&A, primarily due to increased production ($51.0 million) and a higher per unit rate ($16.4 million). Our oil and gas unit of production rate increased to $15.71 per BOE in 2008 compared to $12.64 per BOE in 2007. The increase primarily reflects the acquisition of the Pogo properties.

Accretion expense. Accretion expense increased $1.0 million, to $3.3 million in 2008 from $2.3 million in 2007. The increase in accretion expense for 2008 is attributable to an increase in our asset retirement obligation associated with the Pogo properties acquired in November 2007 ($0.9 million).

Interest expense. Interest expense increased $14.8 million, to $33.0 million in 2008 from $18.2 million in 2007 due to higher outstanding debt associated with the Pogo and Haynesville Shale acquisitions. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization and other assets being prepared for use. We capitalized $19.2 million and $11.1 million of interest in 2008 and 2007, respectively. The increase in capitalized interest is due to a higher unevaluated property balance associated with the Pogo and Haynesville Shale acquisitions.

Debt extinguishment costs. We recorded $3.1 million of debt extinguishment costs as a result of the third quarter modifications to our senior revolving credit facility.

Gain on mark-to-market derivative contracts. We do not currently use hedge accounting for our derivative instruments. Consequently, our 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 us making a payment to or receiving a payment from the counterparty.

For the three months ended September 30, 2008, we recognized a $451.1 million gain related to mark-to-market derivative contracts and net cash payments related to contracts that settled totaled $17.6 million. For the three months ended September 30, 2007, we recognized a $39.2 million loss related to mark-to-market derivative contracts and cash payments related to contracts that settled totaled $25.6 million. The gain related to mark-to-market derivative contracts is primarily due to (i) additional contracts entered into during the second quarter of 2008 (See Item 3 – Quantitative and Qualitative Disclosures About Market Risk) and (ii) price decreases in oil and natural gas since June 30, 2008.

Income taxes. During interim periods income tax expense is generally based on the estimated effective income tax rate that is expected for the entire year plus any significant, unusual or infrequently occurring items that are 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. Variances in our estimated annual effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes and estimated permanent differences, which include (1) the special deduction for domestic production and (2) expenses that are not deductible because of Internal Revenue Service limitations.

For the third quarter of 2008, income tax expense was approximately 37% of pretax income. Our current tax expense as a percentage of total tax expense increased as result of the anticipated sale of our remaining interest in Permian and Piceance Basin properties to Oxy, which is expected to close in December 2008. Specific items affecting income tax expense for the third quarter included state tax rate changes due to asset acquisitions and divestitures and changes to our balance of unrecognized tax positions. For the third quarter 2007, income tax expense was approximately 38% of pretax income.

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Comparison of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2007

Oil and gas revenues. Oil and gas revenues increased $1.3 billion, to $2.1 billion for 2008 from $776.6 million for 2007, primarily due to a 70% increase in sales volumes and a $29.32 per BOE increase in realized prices.

Oil revenues increased $818.0 million to $1.5 billion for 2008 from $713.2 million for 2007 reflecting higher realized prices ($569.0 million) and higher sales volumes ($249.0 million). Our average realized price for oil increased $44.12 to $99.43 per Bbl for 2008 from $55.31 per Bbl for 2007. The revenue increase attributable to price is due to an improvement in the NYMEX oil price, which averaged $113.52 per Bbl in 2008 versus $66.19 per Bbl in 2007, partially offset by an increase in the differential to NYMEX. Oil sales volumes increased 9.0 MBbls per day to 56.2 MBbls per day in 2008 from 47.2 MBbls per day in 2007, primarily reflecting production from the properties acquired in the Pogo acquisition, which had sales of 10.7 MBbls per day in 2008.

Gas revenues increased $465.0 million to $528.4 million in 2008 from $63.4 million in 2007 due to increased sales volumes ($425.6 million) and an increase in realized prices ($39.4 million). Our average realized price for gas was $9.00 per Mcf in 2008 compared to $5.56 per Mcf in 2007. Gas sales volumes increased from 41.8 MMcf per day in 2007 to 214.1 MMcf per day in 2008 primarily reflecting production from the properties acquired in the Pogo acquisition, which had sales of 159.5 MMcf per day in 2008, and increased production from the Piceance Basin properties. Production from the Piceance Basin properties, net to our interest, increased 120%to 31.9 MMcf per day for the first nine months of 2008 compared to 14.5 MMcf per day in the same period of 2007.

Lease operating expenses. Lease operating expenses increased $89.2 million to $236.7 million in 2008 from $147.5 million in 2007. Lease operating expenses for 2008 includes $82.1 million attributable to the Pogo and Piceance Basin properties acquired in November and May of 2007, respectively. Lease operating expense for 2007 includes $2.9 million of Piceance Basin costs. Excluding these incremental costs, lease operating expenses increased $10.0 million due primarily to increased repairs and maintenance and workover expense ($9.8 million). On a per unit basis, lease operating expenses decreased to $9.40 per BOE in 2008 versus $9.96 per BOE in 2007 due to increased sales volumes.

Steam gas costs. Steam gas costs increased $33.6 million to $110.2 million in 2008 from $76.6 million in 2007, primarily reflecting the higher cost of gas used in steam generation. In 2008, we burned approximately 12.5 Bcf of natural gas at a cost of approximately $8.80 per Mcf compared to 12.5 Bcf at a cost of $6.14 per Mcf in 2007.

Electricity. Electricity increased $7.2 million to $36.7 million in 2008 from $29.5 million in 2007, primarily reflecting the Pogo acquisition ($2.8 million) and increased rates. On a per unit basis, electricity decreased to $1.46 per BOE in 2008 versus $1.99 per BOE in 2007 due to increased sales volumes.

Production and ad valorem taxes. Production and ad valorem taxes increased $62.4 million to $77.8 million in 2008 from $15.4 million in 2007, primarily reflecting increased volumes from the Pogo and Piceance Basin acquisitions ($61.2 million).

Gathering and transportation expenses. Gathering and transportation expenses increased $11.0 million to $15.4 million in 2008 from $4.4 million in 2007, primarily reflecting increased volumes from the Pogo and Piceance Basin acquisitions ($10.4 million).

General and administrative expense. G&A expense increased $40.1 million to $114.5 million in 2008 compared to $74.4 million in 2007. The increase, net of capitalization, is due to increased personnel and other costs primarily as a result of the Pogo and Piceance Basin acquisitions (approximately $35.3 million), stock based compensation (approximately $16.6 million) and transition and other expenses related to the Pogo acquisition (approximately $5.3 million). These expenses were partially offset by an increase in capitalized G&A related to our acquisition, exploration and development activities. We capitalized $44.7 million and $27.5 million of G&A costs in 2008 and 2007, respectively. The increase in capitalized G&A is attributable to increased acquisition, exploration and development activities.

Depreciation, depletion and amortization. DD&A expense increased $230.7 million, to $411.6 million in 2008 from $180.9 million in 2007. The increase was attributable to our oil and gas DD&A, primarily due to increased production ($163.1 million) and a higher per unit rate ($62.3 million). Our oil and gas unit of production rate increased to $15.72 per BOE in 2008 compared to $11.59 per BOE in 2007. The increase primarily reflects the acquisition of the Pogo and Piceance Basin properties.

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Accretion expense. Accretion expense increased $3.1 million, to $9.9 million in 2008 from $6.8 million in 2007. Accretion expense for 2008 included $2.9 million attributable to an increase in our asset retirement obligation associated with the Pogo and Piceance Basin properties acquired in November and May of 2007, respectively.

Gain on sale of assets. In February 2008, we completed the sale to Oxy of 50% of the entity which holds our investment in CVGG and recorded a gain on the sale of $34.7 million.

Interest expense. Interest expense increased $51.9 million, to $87.1 million in 2008 from $35.2 million in 2007 due to higher outstanding debt associated with the Pogo, Piceance Basin and Haynesville Shale acquisitions. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization and other assets being prepared for use. We capitalized $48.9 million and $18.2 million of interest in 2008 and 2007, respectively. The increase in capitalized interest is due to a higher unevaluated property balance associated with the Pogo, Piceance Basin and Haynesville Shale acquisitions.

Debt extinguishment costs.In connection with a reduction of the commitments under our senior revolving credit facility in February 2008, we recorded $10.3 million of debt extinguishment costs. We recorded an additional $3.1 million of debt extinguishment costs in the third quarter on our senior revolving credit facility.

Gain on mark-to-market derivative contracts. We do not currently use hedge accounting for our derivative instruments. Consequently, our 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 us making a payment to or receiving a payment from the counterparty.

For the nine months ended September 30, 2008, we recognized a $390.2 million gain related to mark-to-market derivative contracts and net cash payments related to contracts that settled totaled $60.3 million. For the nine months ended September 30, 2007, we recognized a $75.6 million loss related to mark-to-market derivative contracts and cash payments related to contracts that settled totaled $74.8 million. The gain related to mark-to-market derivative contracts is primarily due to (i) additional contracts entered into during the second quarter of 2008 (see Item 3 – Quantitative and Qualitative Disclosures About Market Risk) and (ii) price decreases in oil and natural gas since we acquired these additional derivative contracts.

Income taxes. During interim periods, income tax expense is generally based on the estimated effective income tax rate that is expected for the entire year plus any significant, unusual or infrequently occurring items that are 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. Variances in our estimated annual effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes and estimated permanent differences, which include (1) the special deduction for domestic production and (2) expenses that are not deductible because of Internal Revenue Service limitations.

For the nine months ended September 30, 2008, income tax expense was approximately 37% of pretax income. Our current tax expense for the nine months ended September 30, 2008 has increased over the same percentage for the six months ended June 30, 2008 as result of the anticipated sale of our remaining interest in Permian and Piceance Basin properties to Oxy, which is expected to close in December 2008. Specific items affecting income tax expense for the nine months ended September 30, 2008 included state tax rate changes due to asset acquisitions and divestitures and changes to our balance of unrecognized tax positions. For the nine months ended September 30, 2007, income tax expense was approximately 41% of pretax income.

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Liquidity and Capital Resources

Liquidity is important to our operations. Our liquidity may be affected by an inability to access the capital and credit markets and the success of our commodity price risk management activities, which may subject us to the credit risk of the counterparties to such agreements. This situation may arise due to circumstances beyond our control, such as a general disruption of the financial markets.

During 2008, there has been extreme volatility and disruption in the capital and credit markets. During the third and fourth quarters of 2008, the volatility and disruption have reached unprecedented levels that may adversely affect the financial condition of lenders in our senior revolving credit facility and the counterparties to our commodity price risk management agreements, as well as our insurers and our oil and natural gas purchasers. While these market conditions persist, our liquidity may be adversely affected by limitations on our ability to access the capital and credit markets.

Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility, and periodic public offerings of debt. At September 30, 2008, we had approximately $665 million available under our senior revolving credit facility, which had aggregate commitments of $2.7 billion. Under the terms of our senior revolving credit facility, the commitments of each lender to make loans to us are several and not joint. 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 23 lenders with no single lender’s commitment representing more than nine percent of the total commitments.

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 or natural gas prices above the maximum fixed amount specified in the derivative agreement. Further, we become subject to the credit risk of the counterparties to such agreements when the price of oil or 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 response to market conditions and as part of our regular contingency planning and portfolio optimization, we are taking a number of actions to improve our liquidity position. On September 24, 2008, we entered into a definitive agreement to sell certain properties to Oxy for $1.25 billion. The sale, which is subject to customary closing conditions, is expected to close in December 2008. As a result of the sale, our senior revolving credit facility commitments will be voluntarily reduced from $2.7 billion to $2.3 billion upon closing of the sale. Pro forma for the asset sale, our available funds under our senior revolving credit facility as of September 30, 2008 would be approximately $1.3 billion, an increase from approximately $665 million currently available. We are also changing our cash management activities to maintain larger cash and cash equivalents balances.

Our Board of Directors approved a $1.15 billion 2009 capital budget. Approximately 50% of the capital investment is allocated to production and development activities, 40% to the Haynesville Shale project and 10% for exploration projects. We intend to fund our 2009 capital budget from internally generated funds, and we have flexibility to adjust our discretionary capital expenditures if our cash flows decline from expected levels.

We believe that we have sufficient liquidity through our cash from operations 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, commitments and contingencies and anticipated capital expenditures. We have no near-term debt maturities. Our senior revolving credit facility matures on November 6, 2012 and the next maturity of our senior unsecured notes will occur on June 15, 2015.

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Working Capital

At September 30, 2008, we had a working capital deficit of approximately $419.5 million. Our working capital deficit is affected by fluctuations in the fair value of our commodity derivative instruments and SARs. Additionally, at September 30, 2008, our current income tax payable increased in anticipation of the sale of certain oil and gas properties to Oxy; however, the sale is not expected to close until December 2008. At September 30, 2008, we had a net short-term asset of $27.1 million for derivatives and net short-term liabilities of $155.5 million for income taxes and $3.2 million for SARs. Excluding these items, our working capital deficit was approximately $287.9 million. We generally have a working capital deficit or a minimal working capital balance because we use excess cash to pay down borrowings under our senior revolving credit facility; however, as a result of the current volatility and disruption we expect to change our cash management activities to maintain larger cash and cash equivalent balances. We expect to invest any significant cash balances in U.S. government securities and other highly liquid investments.

Financing Activities

7⁵/₈% Senior Notes. In May 2008, we issued $400 million of 7⁵/₈% Senior Notes due 2018 (the “7⁵/₈% Senior Notes”) at par. The net proceeds were used to repay borrowings under our senior revolving credit facility. We may redeem all or part of the 7⁵/₈% Senior Notes on or after June 1, 2013 at specified redemption prices and prior to that date at a “make-whole” redemption price. In addition, prior to June 1, 2011 we may, at our option, redeem up to 35% of the 7⁵/₈% 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 7⁵/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 7 ³/4% Senior Notes due 2015, the 7% Senior Notes due 2017 and the 7⁵/₈% Senior Notes (together, “the Senior Notes”) are our general unsecured, senior obligations. The Senior Notes are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. The 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 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.

The indenture governing the Senior Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional debt; make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock; sell assets, including capital stock of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; create liens that secure debt; enter into transactions with affiliates; and merge or consolidate with another company.

Amended Credit Agreement.During 2008, the borrowing base and commitments under our senior revolving credit facility were adjusted as a result of oil and gas property acquisitions and divestitures and completion of the offering of the 7⁵/₈% Senior Notes. Additionally, in February 2008, we entered into an amendment to our senior revolving credit facility, which allows us to repurchase up to $1.0 billion of our common stock subject to certain conditions being met. During 2008, we recognized $13.4 million of debt extinguishment costs related to the changes in our commitments under our senior revolving credit facility.

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.

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As of September 30, 2008, we had $0.7 million in letters of credit outstanding under our senior revolving credit facility, and the effective interest rate on our borrowings under the facility was 4.14%.

Effective upon the closing of the asset sale to Oxy, certain modifications to our senior revolving credit facility will occur. On October 22, 2008, we entered into a letter agreement, which will decrease the borrowing base from $3.1 billion to $2.7 billion. The borrowing base will remain subject to the redetermination provisions of our senior revolving credit facility. Upon the receipt of proceeds from the asset sale, we will voluntarily decrease the aggregate commitments of the lenders under our senior revolving credit facility from $2.7 billion to $2.3 billion. These modifications will be effective upon the closing of the asset sale to Oxy for $1.25 billion, which is expected to occur in December 2008. The other terms and conditions of the senior revolving credit facility will remain the same.

Short-term Credit Facility. We have an uncommitted short-term unsecured credit facility under the terms of which we may make borrowings from time to time until June 1, 2009, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than June 1, 2009. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and PXP.

Cash Flows

	Nine Months Ended September 30,
	2008			2007
	(in millions)
Cash provided by (used in):
Operating activities	$	1,146.9		$	285.8
Investing activities		(1,055.0	)		(1,565.9	)
Financing activities		(115.0	)		1,283.8

Net cash provided by operating activities was $1.1 billion in 2008 compared to $285.8 million in 2007. The increase in net cash provided by operating activities in 2008 reflects higher operating income primarily related to the Pogo acquisition and higher commodity prices.

Net cash used in investing activities of $1.1 billion in 2008 primarily reflects 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. Net cash used in investing activities of $1.6 billion in 2007 primarily reflects the purchase of the Piceance Basin properties of $975.4 million, additions to oil and gas properties of $476.3 million and derivative settlements of $74.8 million. Derivative settlements related to derivatives that have not been qualified for hedge accounting and do not contain a significant financing element are reflected as investing activities.

Net cash used in financing activities of $115.0 million in 2008 primarily reflects a $170.9 million net decrease in borrowings under our senior revolving credit facility, $304.2 million used for treasury stock purchases and derivative settlements of $24.1 million, partially offset by $400 million from the issuance of the 7⁵/₈% Senior Notes. Net cash provided by financing activities in 2007 of $1.3 billion primarily reflects $1.3 billion in net borrowings, including $1.1 billion from the issuance of the 7% and 7³/₄% Senior Notes, partially offset by $47.5 million for treasury stock purchases. In 2008, certain of our derivatives are deemed to contain a significant financing element, and cash settlements with respect to such derivatives are required to be reflected as financing activities.

Stock Repurchase Program

Our Board of Directors has authorized the repurchase of up to $1.0 billion of our common stock. The shares will be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. During the nine months ended September 30, 2008, we repurchased approximately 5.8 million common shares at a cost of approximately $304.2 million. We may expend an additional $695.8 million under the program.

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Commitments and Contingencies

On July 7, 2008, we acquired from a subsidiary of Chesapeake a 20% interest in Chesapeake’s Haynesville Shale leasehold as of June 30, 2008 for approximately $1.65 billion in cash, subject to customary post-closing adjustments. 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.

On June 27, 2008, PXP and a subsidiary of Oxy acquired from a third party working interests in acreage immediately adjacent to our existing Piceance Basin assets. PXP and Oxy, a 50% owner in our Piceance Basin assets, agreed to pay an aggregate of $158.6 million for a 95% working interest comprising approximately 11,500 net acres. Under the terms of the acquisition agreement, we paid approximately $20.3 million on June 27, 2008, with the remaining balance payable in equal amounts of approximately $20.3 million on July 1, 2009 and July 1, 2010 and approximately $18.5 million on July 1, 2011. Of the $59.0 million of unpaid consideration, $20.2 million is included in Other Current Liabilities and $38.8 million is included in Other Long-Term Liabilities on our Consolidated Balance Sheet at September 30, 2008. On September 24, 2008, we agreed to sell our interest in these properties to Oxy. Oxy will assume our obligation for the unpaid consideration in connection with the sale, which is expected to close in December 2008.

Critical Accounting Policies and Factors that May Affect Future Results

Fair Value.We adopted Statement of Financial Account Standard (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS 157”) and SFAS No.159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (“SFAS 159”) effective January 1, 2008, each of which address the fair value measurement of assets and liabilities. We have elected to partially adopt SFAS 157 as provided by FSP SFAS 157-2, which deferred the effective date of SFAS 157 for nonfinancial assets and liabilities that are recognized and disclosed at fair value in the financial statements on a nonrecurring basis. SFAS 159 permits the measurement of financial instruments and certain other items at fair value that were not previously required to be measured at fair value. We have elected not to present assets and liabilities at fair value that were not required to be measured at fair value prior to the adoption of SFAS 159.

As defined in SFAS 157, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (“exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of fair value under SFAS 157 are as follows:

• Level 1 – Valuations utilizing quoted, unadjusted prices for assets or liabilities in active markets for identical assets or liabilities as of the reporting date. This is the most reliable evidence of fair value and does not require a significant amount of judgment.

• Level 2 – Valuations utilizing market-based inputs that are directly or indirectly observable but not considered Level 1 quoted prices, including quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; or valuation techniques whose inputs are observable. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability.

• Level 3 – Valuations utilizing techniques whose significant inputs are unobservable. This provides the least objective evidence of fair value and requires a significant degree of judgment.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement.

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We estimate the fair values of our derivative instruments, including crude oil put options, crude oil collars and natural gas collars using an option-pricing model. The option-pricing model 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. We use the credit default swap value for counterparties, when available, or the spread between the risk-free interest rates and the yield on the counterparty’s publicly-traded debt for similar maturities. We consider the impact of master netting agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability.

In October 2008, the Financial Accounting Standards Board (“FASB”) issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active” (FSP SFAS 157-3”). This FSP clarifies the application of SFAS No. 157 in a market that is not active and provides for an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. We determined whether the market for our derivative instruments is active or inactive based on transaction volume for such instruments and classified those instruments as Level 3 instruments. We value these Level 3 instruments using similar instruments and extrapolating data between data points for the thinly traded instruments.

Write-downs under full cost ceiling test rules. We follow the full cost method of accounting. Under the SEC’s full cost accounting rules we review the carrying value of our proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and gas properties (net of accumulated depreciation, depletion and amortization, and 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 and require a write-down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. 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 significantly in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. At September 30, 2008, the ceiling with respect to our oil and gas properties exceeded the net capitalized costs of those properties by approximately $3.0 billion.

Goodwill.We account for goodwill in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). Goodwill is not amortized, instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment is the condition that exists 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 a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of that 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 described above, we follow the full cost method of accounting, and all of our producing properties are located in the United States. We have determined that for purposes of performing an impairment test in accordance with SFAS 142, we have one reporting unit. SFAS 142 states that quoted market prices in active markets, if available, are the best evidence of fair value and should be used as the basis for the fair value measurement. Accordingly, we use the quoted market price of our common stock a starting point in determining the fair value of our reporting unit.

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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. Factors that could result in the impairment of our goodwill include significant declines in oil and gas prices and/or estimated reserve volumes, either of which could trigger a decline in the fair value of our reporting unit.

Due to the adverse market conditions that had a pervasive impact on the U.S. business climate near the end of the third quarter of 2008, we performed a goodwill impairment test as of September 30, 2008. 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 at September 30, 2008, and we concluded that our goodwill was not impaired at September 30, 2008. We determined the control premium through reference to control premiums in recent acquisition transactions for our industry and other comparable industries. If market conditions continue to deteriorate and our common stock price continues to decline in the fourth quarter, we could have an impairment of our goodwill at December 31, 2008.

Based on the accounting policies that we have in place, certain factors may impact our future financial results. Critical accounting policies related to commodity pricing and risk management activities, oil and gas reserves, future development and abandonment costs, DD&A and stock based compensation are discussed in our Annual Report on Form 10-K for the year ended December 31, 2007.

Recent Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R broadens the guidance of SFAS 141, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. It broadens the fair value measurement and recognition of assets acquired, liabilities assumed, and interests transferred as a result of business combinations and requires that acquisition-related costs incurred prior to the acquisition be expensed. SFAS 141R also expands the definition of what qualifies as a business, and this expanded definition could include prospective oil and gas property acquisitions. This could require us to expense transaction costs for future oil and natural gas property purchases that we have historically capitalized. Additionally, SFAS 141R expands the required disclosures to improve the financial statement users’ ability to evaluate the nature and financial effects of business combinations. SFAS 141R is effective for business combinations for which the acquisition date is on or after January 1, 2009, except for certain income tax effects related to prior business combination for which FAS 141R is now effective.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We do not expect this pronouncement to have a significant impact on our consolidated financial position, results of operations or cash flows.

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In September 2008, the FASB issued FASB Staff Position (“FSP”) FAS 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (“FSP FAS 133-1 and FIN 45-4”). This FSP amends FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”, to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument. This FSP also amends FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”, to require additional disclosure about the current status of the payment/performance risk of a guarantee. Further, this FSP clarifies the FASB’s intent about the effective date of SFAS 161. This FSP is effective for reporting periods (annual or interim) ending after November 15, 2008. We do not expect this FSP to have a significant 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:

• completion of the proposed Permian and Piceance asset sale;

• 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 our earnings as a result of our derivative positions;

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

• the success of our derivative activities;

• the success of our risk management activities;

• the effects of competition;

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

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

• the impact of current and future laws and governmental regulations;

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

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

• general economic, market, industry or business conditions.

All forward-looking statements in this report are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report and our other filings with the SEC. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except for any obligation to disclose material information under the Federal securities laws, we do not intend to update these forward-looking statements and information. See Item 1A – Risk Factors and Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Factors That May Affect Future Results in our Annual Report on Form 10-K for the year ended December 31, 2007 for additional discussions of risks and uncertainties.

Item 3 – Quantitative and Qualitative Disclosures About Market Risk

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 5 to the Consolidated Financial Statements – Derivative Instruments for a discussion of our derivative activities.

During June 2008, we entered into crude oil put option contracts on 40,000 barrels of oil per day in 2009 and 2010. The 2009 put options have an average strike price of $106.16 per barrel and an average deferred premium plus interest of $6.19 per barrel and the 2010 put options have an average strike price of $111.49 per barrel and an average deferred premium plus interest of $12.08 per barrel. The put options for 2009 and 2010 are settled annually on a calendar year average price. We also acquired natural gas collars with an average floor price of $10.00 per million British thermal units (“MMBtu”) and an average ceiling price of $20.00 per MMBtu on 150,000 MMBtu per day for the months of July 2008 through December 2009. The average deferred premium plus interest is $0.346 per MMBtu and is settled monthly. The deferred premium plus interest is recorded as an offset to commodity derivative assets or as a commodity derivative liability in our Consolidated Balance Sheet when a master netting agreement exists.

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At September 30, 2008, we had the following open commodity derivative positions, none of which were designated as hedging instruments:

Period	Instrument Type	Daily Volumes	Average Price	Index
Sales of Crude Oil Production
2008
Oct - Dec	Put options	42,000 Bbls	$55.00 Strike price	WTI
Oct - Dec	Collar	2,500 Bbls	$60.00 Floor - $80.13 Ceiling	WTI
2009
Jan - Dec	Put options	32,500 Bbls	$55.00 Strike price	WTI
Jan - Dec	Put options	40,000 Bbls	$106.16 Strike price	WTI
2010
Jan - Dec	Put options	40,000 Bbls	$111.49 Strike price	WTI
Sales of Natural Gas Production
2008
Oct - Dec	Collar	15,000 MMBtu	$8.00 Floor - $12.11 Ceiling	Henry Hub
Oct - Dec	Collar	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	Henry Hub
2009
Jan - Dec	Collar	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	Henry Hub

The only cash settlements we are required to make on the purchased put options are option premiums and interest. Commodity derivative liabilities at September 30, 2008 include deferred premiums and associated accrued interest of (i) approximately $14.5 million for the last three months of 2008, which will be paid ratably each month, (ii) approximately $38.7 million which will be paid ratably each month in 2009, (iii) approximately $85.4 million which will be paid after the end of the 2009 annual period in January 2010 and (iv) approximately $161.3 million for 2010, which will be paid after the end of the 2010 annual period in January 2011.

For a collar contract, (i) we are required to pay cash settlements to the counterparty if the settlement price for any settlement period is above the ceiling price, (ii) the counterparty is required to pay cash settlements to us if the settlement price for any settlement period is below the floor price and (iii) neither party is required to pay cash settlements to the other party if the settlement price for any settlement period is equal to or between the floor and ceiling price. We are required to pay premiums and interest for the natural gas collars with daily volumes of 150,000 MMBtu per day. Commodity derivative liabilities at September 30, 2008 include deferred premiums and associated accrued interest of approximately $4.7 million for the last three months of 2008 and approximately $18.6 million for 2009. These payments will be made on the monthly settlement dates.

The fair value of outstanding crude oil and natural gas commodity derivative instruments at September 30, 2008 and the change in fair value that would be expected from a 10% price increase or decrease is shown below (in millions). The fair value does not include the deferred premiums on the purchased put options and natural gas collars.

				Effect of 10%
	Fair Value Asset (Liability)			Price Increase			Price Decrease
Put options	$	529.5		$	(100.9	)	$	152.3
Crude oil collars		(5.1	)		(2.1	)		1.9
Natural gas collars		143.1			(31.3	)		35.8
	$	667.5		$	(134.3	)	$	190.0

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We estimate the fair values of our derivatives using an option-pricing model. The option-pricing model 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. We use the credit default swap value for counterparties, when available, or the spread between the risk-free interest rates and the yield on the counterparty’s publicly-traded debt for similar maturities. We consider the impact of master netting agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability. We determined 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.

All positions offset physical positions exposed to the cash market. None of these 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.

Of the ten financial institutions that are contract counterparties for our commodity derivative contracts, all but one of the financial institutions are participating lenders in our senior revolving credit facility.

We consider the credit quality of our counterparties when we value our commodity derivatives. At September 30, 2008, we had the following commodity derivative net asset (liability) balances with counterparties rated by Standard & Poor’s (“S&P”) (in thousands):

S&P Rating	Fair Value		Deferred Premium Liability		Net Asset (Liability)
AA+ / Stable	$	220,753	$	109,045	$	111,708
AA- / Stable		243		-		243
AA / Watch Negative		39,006		5,479		33,527
AA / Negative		32		1,753		(1,721	)
AA- / Negative		181,234		105,315		75,919
A+ / Stable		57,985		11,521		46,464
A+ / Negative		168,283		90,181		78,102
	$	667,536	$	323,294	$	344,242

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.

Credit Exposure

In addition to derivatives, financial instruments which potentially subject us to concentrations of credit risk consist primarily of accounts receivable with respect to our oil and gas operations. During the three months and nine months ended September 30, 2008 sales to ConocoPhillips accounted for 38% and 37%, respectively, of our total sales and sales to Plains Marketing, L.P., which is a subsidiary of Plains All American Pipeline, L.P. accounted for 23% and 23%, respectively, of our total sales. Their role as purchaser of a significant portion of our oil production has the potential to impact our overall exposure to credit risk, either positively or negatively, in that these purchasers may be affected by changes in economic, industry or other conditions. The S&P rating as of September 30, 2008 for ConocoPhillips was A/Stable and Plains Marketing, L.P. was BBB-/Stable.

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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, 2008 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, 2008 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

The following risk factors update the Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2007. Except as set forth below, there have been no material changes to the risks described in Part I Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2007.

Adverse capital and credit market conditions may significantly affect our ability to meet liquidity needs, access to capital and cost of capital.

The capital and credit markets have been experiencing extreme volatility and disruption over the last year. In the third and fourth quarters of 2008, the volatility and disruption reached unprecedented levels. In some cases, the markets produced downward pressure on stock prices and credit capacity for certain issuers without regard to those issuers’ underlying financial strength. If these levels of market disruption and volatility continue, worsen or abate and then arise at a later date, our business, financial condition and results of operations as well as our ability to access capital may all be negatively impacted.

The impairment of financial institutions could adversely affect us.

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including, commercial banks, investment banks, insurance companies, other investment funds and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Continued deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions in the form of derivative transactions in connection with our hedges. We also maintain insurance policies with insurance companies to protect us against certain risks inherent in our business. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.

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ITEM 6 – Exhibits

2.1	Purchase and Sale Agreement between Plains Exploration & Production Company, PXP Louisiana L.L.C., PXP Louisiana Operations LLC and Chesapeake Louisiana, L.P., dated July 1, 2008 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed July 8, 2008).
2.2	Participation Agreement between Plains Exploration & Production Company, PXP Louisiana L.L.C., PXP Louisiana Operations LLC and Chesapeake Louisiana, L.P., dated July 7, 2008 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed July 8, 2008).
2.3	Purchase and Sale Agreement dated September 24, 2008, by and among Plains Exploration & Production Company, Plains Resources Inc., PXP Hell’s Gulch LLC, PXP East Plateau LLC, PXP Brush Creek LLC, PXP Piceance LLC, Pogo Producing Company LLC, Pogo Panhandle 2004 LP and Latigo Petroleum Texas, LP and OXY USA Inc (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed September 25, 2008).
4.1	Amendment No. 3 to Amended and Restated Credit Agreement, dated as of July 23, 2008 among Plains Exploration & Production Company, as borrower, each of the lenders that is a signatory thereto, and JPMorgan Chase Bank N.A., as administrative agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 23, 2008).
4.2*	Eighth Supplemental Indenture, dated July 10, 2008, to Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, PXP Louisiana Operations LLC, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee.
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.
*  Filed herewith

Items 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 6, 2008
	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
2.1	Purchase and Sale Agreement between Plains Exploration & Production Company, PXP Louisiana L.L.C., PXP Louisiana Operations LLC and Chesapeake Louisiana, L.P., dated July 1, 2008 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed July 8, 2008).
2.2	Participation Agreement between Plains Exploration & Production Company, PXP Louisiana L.L.C., PXP Louisiana Operations LLC and Chesapeake Louisiana, L.P., dated July 7, 2008 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed July 8, 2008).
2.3	Purchase and Sale Agreement dated September 24, 2008, by and among Plains Exploration & Production Company, Plains Resources Inc., PXP Hell’s Gulch LLC, PXP East Plateau LLC, PXP Brush Creek LLC, PXP Piceance LLC, Pogo Producing Company LLC, Pogo Panhandle 2004 LP and Latigo Petroleum Texas, LP and OXY USA Inc (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed September 25, 2008).
4.1	Amendment No. 3 to Amended and Restated Credit Agreement, dated as of July 23, 2008 among Plains Exploration & Production Company, as borrower, each of the lenders that is a signatory thereto, and JPMorgan Chase Bank N.A., as administrative agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 23, 2008).
4.2*	Eighth Supplemental Indenture, dated July 10, 2008, to Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, PXP Louisiana Operations LLC, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee.
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.

        * Filed herewith

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