Plains Exploration & Production 10-Q 2010 Q2 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 June 30, 2010

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes  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 filerx	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

140.1 million shares of Common Stock, $0.01 par value, issued and outstanding at July 30, 2010.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
ITEM 1. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets June 30, 2010 and December 31, 2009	1
Consolidated Statements of Income For the three months ended and six months ended June 30, 2010 and 2009	2
Consolidated Statements of Cash Flows For the six months ended June 30, 2010 and 2009	3
Consolidated Statement of Stockholders’ Equity For the six months ended June 30, 2010	4
Notes to Consolidated Financial Statements	5
ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
ITEM 3.Quantitative and Qualitative Disclosures About Market Risk	37
ITEM 4.Controls and Procedures	38
PART II.OTHER INFORMATION	39

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	June 30,      2010		December 31, 2009
ASSETS
Current Assets
Cash and cash equivalents	$	12,579	$	1,859
Accounts receivable		168,409		258,585
Commodity derivative contracts		23,623		11,952
Inventories		18,824		19,934
Prepaid expenses and other current assets		19,493		14,305
		242,928		306,635
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		9,787,554		9,044,146
Not subject to amortization		3,045,819		3,279,537
Other property and equipment		130,061		125,667
		12,963,434		12,449,350
Less allowance for depreciation, depletion, amortization and impairment		(5,917,947)		(5,616,628)
		7,045,487		6,832,722
Goodwill		535,237		535,237
Commodity Derivative Contracts		40,378		-
Other Assets		58,643		60,137
	$	7,922,673	$	7,734,731
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	196,363	$	248,454
Commodity derivative contracts		29,009		59,176
Royalties and revenues payable		72,813		78,590
Interest payable		48,414		45,743
Deferred income taxes		-		153,473
Other current liabilities		72,205		97,115
		418,804		682,551
Long-Term Debt		2,722,134		2,649,689
Other Long-Term Liabilities
Asset retirement obligation		226,235		214,231
Other		22,944		55,531
		249,179		269,762
Deferred Income Taxes		1,176,780		933,748
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common stock, $0.01 par value, 250.0 million shares authorized, 143.9 million shares issued at June 30, 2010 and December 31, 2009		1,439		1,439
Additional paid-in capital		3,400,263		3,381,566
Retained earnings		150,584		51,204
Treasury stock, at cost, 3.8 million shares and 4.5 million shares at June 30, 2010 and December 31, 2009, respectively		(196,510)		(235,228)
		3,355,776		3,198,981
	$	7,922,673	$	7,734,731

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 June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Revenues
Oil sales	$	276,263	$	219,589	$	552,267	$	376,203
Gas sales		87,678		58,541		195,417		129,805
Other operating revenues		652		551		959		1,185
		364,593		278,681		748,643		507,193
Costs and Expenses
Lease operating expenses		57,536		63,404		120,039		134,288
Steam gas costs		15,357		10,912		35,020		26,469
Electricity		11,115		12,368		21,149		23,310
Production and ad valorem taxes		3,828		10,457		12,275		22,078
Gathering and transportation expenses		12,912		8,671		22,331		15,318
General and administrative		30,301		37,554		67,691		74,647
Depreciation, depletion and amortization		123,810		90,822		246,203		178,936
Impairment of oil and gas properties		59,475		-		59,475		-
Accretion		4,407		3,556		8,818		7,087
Legal recovery		-		(87,272)		(8,423)		(87,272)
Other operating (income) expense		(3,945)		1,499		(4,514)		5,956
		314,796		151,971		580,064		400,817
Income from Operations		49,797		126,710		168,579		106,376
Other (Expense) Income
Interest expense		(28,039)		(15,935)		(49,092)		(37,932)
Debt extinguishment costs		-		(667)		(728)		(10,910)
Gain (loss) on mark-to-market derivative contracts		57,984		(89,717)		65,840		(1,578)
Other income		11,235		899		12,541		192
Income Before Income Taxes		90,977		21,290		197,140		56,148
Income tax (expense) benefit
Current		(2,672)		43,730		(7,410)		(12,061)
Deferred		(42,930)		(21,371)		(85,827)		4,760
Net Income	$	45,375	$	43,649	$	103,903	$	48,847
Earnings per Share
Basic	$	0.32	$	0.37	$	0.74	$	0.43
Diluted	$	0.32	$	0.37	$	0.73	$	0.43
Weighted Average Shares Outstanding
Basic		140,560		118,145		140,153		112,979
Diluted		141,557		118,798		141,752		113,541

See notes to consolidated financial statements.

2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

		Six Months Ended June 30,
		2010		2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	103,903	$	48,847
Items not affecting cash flows from operating activities	��
Depreciation, depletion and amortization			246,203		178,936
Impairment of oil and gas properties			59,475		-
Accretion			8,818		7,087
Deferred income tax expense (benefit)			85,827		(4,760)
Debt extinguishment costs			728		10,910
(Gain) loss on mark-to-market derivative contracts			(65,840)		1,578
Noncash compensation			22,955		32,566
Other noncash items			1,672		2,913
Change in assets and liabilities from operating activities
Accounts receivable and other assets			27,231		22,667
Accounts payable and other liabilities			(31,365)		(15,435)
Income taxes receivable/payable			14,825		(143,619)
Net cash provided by operating activities			474,432		141,690
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties			(558,386)		(826,961)
Acquisition of oil and gas properties			43,923		-
Proceeds from sales of oil and gas properties			7,230		-
Derivative settlements			(16,153)		1,380,322
Additions to other property and equipment			(4,394)		(9,360)
Net cash (used in) provided by investing activities			(527,780)		544,001
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities			860,455		2,240,090
Repayments of revolving credit facilities			(1,090,455)		(3,545,090)
Proceeds from issuance of Senior Notes			300,000		523,099
Costs incurred in connection with financing arrangements			(5,932)		(12,114)
Derivative settlements			-		1,392
Issuance of common stock			-		250,874
Other			-		28
Net cash provided by (used in) financing activities			64,068		(541,721)
Net increase in cash and cash equivalents			10,720		143,970
Cash and cash equivalents, beginning of period			1,859		311,875
Cash and cash equivalents, end of period		$	12,579	$	455,845

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
	Common Stock							Treasury Stock
	Shares	Amount						Shares	Amount		Total
Balance at December 31, 2009	143,924	$	1,439	$	3,381,566	$	51,204	(4,512)	$	(235,228)	$	3,198,981
Net income	-		-		-		103,903	-		-		103,903
Restricted stock awards	-		-		52,881		-	-		-		52,881
Issuance of treasury stock for restricted stock awards and other	-		-		(34,184)		(4,523)	724		38,718		11
Balance at June 30, 2010	143,924	$	1,439	$	3,400,263	$	150,584	(3,788)	$	(196,510)	$	3,355,776

See notes to consolidated financial statements.

4

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Summary of Significant Accounting Policies

Plains Exploration & Production Company, a Delaware corporation formed in 2002 (“PXP”, “us”, “our” or “we”), is 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.

Our consolidated financial statements include the accounts of all our wholly owned subsidiaries. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation. All adjustments, consisting only of normal recurring adjustments that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. The results of our operations for the six months ended June 30, 2010 are not necessarily indicative of the results to be expected for the full year.

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC, regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements and should be read in conjunction with the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009.

Asset Retirement Obligation. The following table reflects the changes in our asset retirement obligation during the six months ended June 30, 2010 (in thousands):

Asset retirement obligation - December 31, 2009	$	221,367
Settlements		(2,280)
Accretion expense		8,818
Additions		3,886
Asset retirement obligation - June 30, 2010(1)	$	231,791
(1) $5.6 million is included in other current liabilities.

Earnings Per Share. For the three and six months ended June 30, 2010 and 2009 the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):

	Three Months Ended June 30,		Six Months Ended June 30,
	2010	2009	2010	2009
Weighted average common shares outstanding - basic	140,560	118,145	140,153	112,979
Unvested restricted stock, restricted stock units and stock options	997	653	1,599	562
Weighted average common shares outstanding - diluted	141,557	118,798	141,752	113,541

In the three months ended June 30, 2010 and 2009, 2.9 million and 3.0 million restricted stock units, respectively, and in the six months ended June 30, 2010 and 2009, 1.4 million and 3.2 million restricted stock units, respectively, were excluded in computing diluted earnings per share because they were antidilutive due to the impact of the unrecognized compensation cost on the calculation of assumed proceeds in the application of the treasury stock method. In computing earnings per share, no adjustments were made to reported net income.

5

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

	June 30,     2010		December 31, 2009
Oil	$	6,670	$	6,488
Materials and supplies		12,154		13,446
	$	18,824	$	19,934

Oil and Natural Gas Properties Not Subject to Amortization. The cost of unproved oil and natural gas properties is excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are assessed periodically, at least annually, to determine whether impairment has occurred. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment considers the following factors, among others; intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and impairment of oil and gas properties. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, geological and geophysical evaluations, the assignment of proved reserves, availability of capital, and other factors. The timing of transfer of costs into our amortization base impacts our depreciation, depletion, and amortization, or DD&A, rate and full cost ceiling test.

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

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

• the cost of unproved properties not being amortized; plus

• the lower of cost or estimated fair value of unproved properties included in the costs being amortized (net of related tax effects).

The ceiling limitation is applied separately for each country. In the second quarter of 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and have decided not to pursue additional exploratory activities in this area. As described underOil and Natural Gas Properties Not Subject to Amortization, the costs related to the Vietnam oil and gas properties were transferred to our Vietnam full cost pool where they were subject to the ceiling test limitation described underImpairments of Oil and Gas Properties.Because our Vietnam full cost pool has no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million. We also recorded a corresponding tax benefit of $23.0 million.

Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline in the future, impairments of our oil and gas properties could occur. Impairments required by these rules do not impact our cash flows from operating activities.

6

Goodwill. In a purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed, including deferred income taxes recorded in connection with the transaction, over the fair value of the net assets acquired. At June 30, 2010, goodwill totaled $535 million and represented approximately 7% of our total assets.

Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. A two-step impairment test is used to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized, if any. The first step of the goodwill impairment test compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired, thus the second step of the impairment test is unnecessary.

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

We follow the full cost method of accounting for oil and gas activities and all of our producing properties are located in the United States. We have determined that for the purpose of performing an impairment test, we have one reporting unit.

The first step of the goodwill impairment test requires that we make an estimate of the fair value of the reporting unit. Quoted market prices in active markets are the best evidence of fair value. We estimate the fair value of the reporting unit by applying a control premium to the quoted market price of our common stock. We determine the control premium through reference to control premiums in merger and acquisition transactions for our industry and other comparable industries. This requires that we make certain judgments about the selection of merger and acquisition transactions and transaction premiums.

We perform our goodwill impairment test annually as of December 31. We also perform interim goodwill impairment tests if events occur or circumstances change that would indicate the fair value of our reporting unit may be below its carrying amount. Due to adverse market conditions affecting the oil and gas industry in the second quarter of 2010, we performed an interim goodwill impairment test as of June 30, 2010. Based on that test, we concluded that the fair value of the reporting unit exceeded the carrying value of the reporting unit by 13%; therefore, the second step of the goodwill impairment test was not required.

Events affecting oil and gas prices may cause a decrease in the fair value of the reporting unit, and we could have an impairment of our goodwill in future periods. An impairment of goodwill could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders’ equity.

Stock Based Compensation. Stock based compensation for the three and six months ended June 30, 2010 and 2009 was (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Stock based compensation included in:
General and administrative expenses	$	8,305	$	15,397	$	22,921	$	29,914
Lease operating expenses		(2,250)		2,671		34		2,652
Oil and natural gas properties		2,120		4,872		6,963		8,272
Total stock based compensation	$	8,175	$	22,940	$	29,918	$	40,838

During the first six months of 2010, we granted 1.6 million restricted stock units, or RSUs, at an average fair value of $31.24 per share and 845 thousand stock appreciation rights with an average exercise price of $31.52 per share.

Certain of our RSUs were classified as liability awards at December 31, 2009 because we did not have sufficient shares available for issuance under our stock compensation plans. In May 2010, we received stockholder approval for our 2010 Incentive Award Plan, which increased the available shares. As a result, these RSUs are now classified as equity awards in our consolidated balance sheet. These RSUs will no longer be revalued each period.

7

Comprehensive Income. When we acquired Pogo Producing Company, or Pogo, on November 6, 2007, we assumed responsibility for a defined benefit pension plan for Pogo employees. We terminated the plan and recognized in income the remaining balance in accumulated other comprehensive loss. The pension liability adjustment net of related tax benefit for the three and six months ended June 30, 2009 was $678 thousand and $684 thousand, respectively. Comprehensive income for the three and six months ended June 30, 2009 was $44.3 million and $49.5 million, respectively.

Recent Accounting Pronouncements.In June 2009, the FASB issued authoritative guidance for improving financial reporting by enterprises involved with variable interest entities. This guidance eliminates the exemption for qualifying special purpose entities, includes a new approach for determining who should consolidate a variable interest entity, and presents changes as to when it is necessary to reassess who should consolidate a variable interest entity. The guidance is effective for fiscal years beginning after November 15, 2009, and for interim periods within that first annual reporting period. We adopted the provisions of this standard effective January 1, 2010, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.

Note 2—Long-Term Debt

At June 30, 2010 and December 31, 2009, long-term debt consisted of (in thousands):

	June 30, 2010		December 31, 2009
Senior revolving credit facility	$	-	$	230,000
7  3/4% Senior Notes due 2015		600,000		600,000
10% Senior Notes due 2016(1)		528,453		526,222
7% Senior Notes due 2017		500,000		500,000
7  5/8% Senior Notes due 2018		400,000		400,000
8  5/8% Senior Notes due 2019(2)		393,681		393,467
7  5/8% Senior Notes due 2020		300,000		-
	$	2,722,134	$	2,649,689

(1)    The amount is net of unamortized discount of $36.5 million and $38.8 million at June 30, 2010 and December 31, 2009, respectively.

(2)    The amount is net of unamortized discount of $6.3 million and $6.5 million at June 30, 2010 and December 31, 2009, respectively.

In March 2010, our borrowing base was adjusted from $1.22 billion to $1.13 billion in recognition of our issuance of the 7 ⁵/8% Senior Notes due 2020, or the 7 ⁵/8% Senior Notes, and subsequently increased to $1.3 billion in April 2010 after entering into an amendment to our senior revolving credit facility. In addition, the amendment allows us to increase our investments in certain subsidiaries and joint ventures. Our senior revolving credit facility also contains a $250 million limit on letters of credit and a $50 million commitment for swingline loans. As of June 30, 2010, our borrowing base was $1.3 billion, approximately all of which was available, and we had $1.4 million in letters of credit outstanding.

8

Amounts borrowed under our senior revolving credit facility bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 2.00% to 2.75%; (ii) a variable amount ranging from 1.00% to 1.75% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus ¹/2 of 1%, and (3) the adjusted LIBOR plus 1%; or (iii) the over-night federal funds rate plus an additional variable amount ranging from 2.00% to 2.75% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on the utilization rate as a percentage of the total amount of funds borrowed under our senior revolving credit facility to the conforming borrowing base. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and range from 2.00% to 2.75%. Commitment fees are 0.50% of the amount available for borrowing.

Our senior revolving credit facility is secured by 100% of the shares of stock in certain of our domestic subsidiaries, 65% of the shares of stock in certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic proved oil and gas properties. Our senior revolving credit facility 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.

In March 2010, we issued $300 million of 7 ⁵/8% Senior Notes which were sold to the public at par. We received approximately $294 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 7 ⁵/8% Senior Notes on or after April 1, 2015 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to April 1, 2013 we may, at our option, redeem up to 35% of the 7 ⁵/8% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 7 ⁵/8% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 7 ⁵/8% Senior Notes are general unsecured senior obligations. They are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. These 7 ⁵/8% 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 7 ⁵/8% Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries.

Subsequent Event

In August 2010, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and the lenders party thereto, or our Amended Credit Agreement, which amends and restates our senior revolving credit facility, or our Prior Credit Facility. The aggregate commitments of the lenders under our Amended Credit Agreement are $1.4 billion. Our Amended Credit Agreement provides for an initial borrowing base of $1.6 billion that will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Our Amended Credit Agreement contains the same limits on letters of credit and swingline loans, and matures in August 2015. To secure borrowings under our Amended Credit Agreement, we have pledged 100% of the shares of stock in certain of our domestic subsidiaries, 65% of the shares of stock in certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic proved oil and gas properties.

9

Amounts borrowed under our Amended Credit Agreement bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.75% to 2.75%; (ii) a variable amount ranging from 0.75% to 1.75% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus ¹/2 of 1%, and (3) the adjusted LIBOR plus 1%; or (iii) the over-night federal funds rate plus an additional variable amount ranging from 1.75% to 2.75% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on the utilization rate as a percentage of the total amount of funds borrowed under our Amended Credit Agreement to the borrowing base. Letter of credit fees under our Amended Credit Agreement are based on the utilization rate and range from 1.75% to 2.75%. Commitment fees are 0.50% of the amount available for borrowing.

Our Amended Credit Agreement contains negative covenants that are similar to those in our Prior Credit Facility. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined) of no greater than 4.50 to 1.

Note 3—Commodity Derivative Contracts

General

We are exposed to various market risks, including volatility in oil and gas commodity prices and interest rates. The level of derivative activity we engage in depends on our view of market conditions, available derivative prices and operating strategy. A variety of derivative instruments, such as swaps, collars, puts, calls and various combinations of these instruments, may be utilized to manage our exposure to the volatility of oil and gas commodity prices. Currently, we do not use derivatives to manage our interest rate risk. The interest rate on our senior revolving credit facility is variable, while our senior notes are at fixed interest rates, thereby mitigating our interest rate risk exposure.

All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized in our consolidated 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. The derivative instruments we have in place are not classified as hedges for accounting purposes.

Cash settlements with respect to derivatives that contain a significant financing element are reflected as financing activities in the statement of cash flows. Cash settlements with respect to derivatives that are not accounted for under hedge accounting and do not have a significant financing element are reflected as investing activities in the statement of cash flows.

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

In a typical collar transaction, if the floating price based on a market index is below the floor price in the derivative contract, we receive from the counterparty an amount equal to this difference multiplied by the specified volume. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specified volume. We may pay a premium to the counterparty in exchange for a certain floor or ceiling. Any premium reduces amounts we would receive under the floor or increases amounts we would pay above the ceiling. If the floating price exceeds the floor price or is less than the ceiling price, then no payment, other than the premium, is required. If we have less production than the volumes specified under the collar transaction when the floating price exceeds the ceiling price, we must make payments against which there are no offsetting revenues from production.

In April 2010, we entered into crude oil put option spread contracts on 31,000 barrels of oil per day in 2011 and 40,000 barrels of oil per day in 2012. Both the 2011 and 2012 put options have a floor price of $80 with a limit of $60 per barrel. Additionally, during April we also acquired crude oil three-way collars that have floor price of $80 with a limit of $60 and a ceiling price of $110 on 9,000 barrels of oil per day for 2011.

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

10

As of June 30, 2010, we had the following outstanding commodity derivative contracts, all of which settle monthly:

Period	Instrument Type	Daily Volumes	Average Price(1)	Average Deferred Premium	Index
Sales of Crude Oil Production
2010
July - Dec	Put options	40,000 Bbls	$55.00 Strike price	$5.00 per Bbl (2)	WTI
2011
Jan - Dec	Put options (3)	31,000 Bbls	$80.00 Floor with a $60.00 Limit	$5.023 per Bbl	WTI
Jan - Dec	Three-way collars  (4)	9,000 Bbls	$80.00 Floor with a $60.00 Limit	$1.00 per Bbl	WTI
			$110.00 Ceiling
2012
Jan - Dec	Put options (3)	40,000 Bbls	$80.00 Floor with a $60.00 Limit	$6.087 per Bbl	WTI
Sales of Natural Gas Production
2010
July - Dec	Three-way collars (5)	85,000 MMBtu	$6.12 Floor with a $4.64 Limit	$0.034 per MMBtu	Henry Hub
			$8.00 Ceiling

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

(2) In addition to the deferred premium, an upfront payment of $3.86 per barrel was paid upon entering into these derivative contracts.

(3) If the index price is less than the $80 per barrel floor, we receive the difference between the $80 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above $80 per barrel, we pay only the option premium.

(4) If the index price is less than the $80 per barrel floor, we receive the difference between the $80 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. We pay the difference between the index price and $110 per barrel plus the option premium if the index price is greater than the $110 per barrel ceiling. If the index price is at or above $80 per barrel but at or below $110 per barrel, we pay only the option premium.

(5) If the index price is less than the $6.12 per MMBtu floor, we receive the difference between the $6.12 per MMBtu floor and the index price up to a maximum of $1.48 per MMBtu less the option premium. We pay the difference between the index price and $8.00 per MMBtu plus the option premium if the index price is greater than the $8.00 per MMBtu ceiling. If the index price is at or above $6.12 per MMBtu but at or below $8.00 per MMBtu, we pay only the option premium.

Balance Sheet

At June 30, 2010 and December 31, 2009, we had the following outstanding commodity derivative contracts, none of which were designated as hedging instruments, recorded in our consolidated balance sheet (in thousands):

		Estimated Fair Value
Instrument Type	Balance Sheet Classification	June 30, 2010		December 31, 2009
Crude oil puts	Commodity derivative contracts - current assets	$	41,982	$	15,173
Crude oil collars	Commodity derivative contracts - current assets		8,765		-
Natural gas collars	Commodity derivative contracts - current assets		16,619		14,312
Crude oil puts	Commodity derivative contracts - non-current assets		150,581		-
Crude oil collars	Commodity derivative contracts - non-current assets		6,608		-
Total derivative instruments		$	224,555	$	29,485

11

The following table provides supplemental information to reconcile the fair value of the derivative contracts to our consolidated balance sheet at June 30, 2010 and December 31, 2009, considering the deferred premiums and accrued interest and related settlement payable amounts which are not included in the fair value amounts disclosed in the table above (in thousands):

	June 30, 2010		December 31,  2009
Net fair value asset	$	224,555	$	29,485
Deferred premium and accrued interest on derivative contracts		(183,562)		(73,305)
Settlement payable		(6,001)		(3,404)
Net commodity derivative asset (liability)	$	34,992	$	(47,224)
Commodity derivative contracts - current asset	$	23,623	$	11,952
Commodity derivative contracts - non-current asset		40,378		-
Commodity derivative contracts - current liability		(29,009)		(59,176)
	$	34,992	$	(47,224)

We present the fair value of our derivative contracts on a net basis where the right of offset is provided for in our counterparty agreements.

Income Statement

During the three and six months ended June 30, 2010 and 2009, pre-tax amounts recognized in our income statements were as follows (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Gain (loss) on mark-to-market derivative contracts	$	57,984	$	(89,717)	$	65,840	$	(1,578)

Cash Payments and Receipts

During the six months ended June 30, 2010 and 2009, cash (payments) receipts for derivatives were as follows (in thousands):

	Six Months Ended June 30,
	2010		2009
Oil derivatives
Settlements	$	(32,403)	$	159,592
Monetization of crude oil puts and swaps		-		1,074,361
Natural gas derivatives		16,250		147,761
	$	(16,153)	$	1,381,714

Credit Risk

We generally do not require collateral or other security to support derivative instruments subject to credit risk. However, the agreements with each of the counterparties to our derivative instruments contain netting provisions within the agreements. If a default occurs under the agreements, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contracts with the amount due from the defaulting party under the derivatives contracts. As a result of the netting provisions under the agreements, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that we would have incurred if all the counterparties to our derivative contracts failed to perform according to the terms of the derivative contracts at June 30, 2010 was $42.8 million.

12

Contingent Features

As of June 30, 2010, the counterparties to our commodity derivative contracts consist of nine financial institutions. Our counterparties or their affiliates are generally also lenders under our senior revolving credit facility. As a result, the counterparties to our derivative agreements share in the collateral supporting our senior revolving credit facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.

Certain of our derivative agreements contain provisions that require cross defaults and acceleration of those instruments to any material debt. If we were to default on any of our material debt agreements, it would be a violation of these provisions, and the counterparties to the derivative instruments could request immediate payment on derivative instruments that are in a net liability position at that time. As of June 30, 2010, we were in a net liability position with two of the counterparties to our derivative instruments, totaling $7.2 million.

Note 4—Fair Value Measurements of Assets and Liabilities

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Our commodity derivative instruments are recorded at fair value on a recurring basis in our consolidated balance sheet with changes in fair value recorded in our consolidated income statement. The following table presents, for each fair value hierarchy level, our commodity derivative assets and liabilities measured at fair value on a recurring basis as of June 30, 2010 and December 31, 2009 (in thousands):

			Fair Value Measurements at Reporting Date Using
	Fair Value (1)		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
June 30, 2010
Crude oil puts	$	192,563	$	-	$	192,563	$	-
Crude oil collars		15,373		-		15,373		-
Natural gas collars		16,619		-		-		16,619
	$	224,555	$	-	$	207,936	$	16,619
December 31, 2009
Crude oil puts	$	15,173	$	-	$	15,173	$	-
Natural gas collars		14,312		-		-		14,312
	$	29,485	$	-	$	15,173	$	14,312

(1) Option premium and accrued interest of $183.6 million in 2010 and $73.3 million in 2009 and settlement payable of $6.0 million in 2010 and $3.4 million in 2009 are not included in the fair value of derivatives.

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

13

We classify derivatives that have identical assets or liabilities with quoted, unadjusted prices in active markets as Level 1. We classify our derivatives as Level 2 if the inputs used in the valuation model are directly or indirectly observable for substantially the full term of the instrument; however, if the significant inputs are not observable for substantially the full term of the instrument, we classify those derivatives as Level 3. We determine whether the market for our derivative instruments is active or inactive based on transaction volume for such instruments and classify as Level 3 those instruments that are not actively traded. For these inputs, we utilize pricing and volatility information from other instruments with similar characteristics and extrapolate data between data points for thinly traded instruments. As of June 30, 2010, our crude oil put options and crude oil collars are classified as Level 2, and our natural gas collars are classified as Level 3 instruments. We determine the appropriate level for each financial asset and liability on a quarterly basis and recognize any transfers at the beginning of the reporting period.

The following table presents a reconciliation of changes in fair value of financial assets and liabilities classified as Level 3 for the six months ended June 30, 2010 and 2009 (in thousands):

	Commodity Derivative Contracts (1)
	Six Months Ended June 30,
	2010		2009
Fair value at beginning of period	$	14,312	$	1,790,718
Transfers(2)		-		(124,690)
Realized and unrealized gains included in earnings (3)		19,072		204,568
Purchases		-		1,038
Settlements		(16,765)		(1,709,226)
Fair value at end of period	$	16,619	$	162,408
Change in unrealized gains and losses relating to assets and liabilities held as of  the end of the period (3)	$	11,124	$	59,077

(1) Deferred option premiums and interest are not included in the fair value of derivatives.

(2) During the first quarter of 2009, the inputs used to value our $55 crude put options were directly or indirectly observable and our $55 crude puts were transferred to Level 2.

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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Nonfinancial assets and liabilities, such as goodwill and other property and equipment, are measured at fair value on a nonrecurring basis upon impairment; however, we have no material assets or liabilities that are reported at fair value on a nonrecurring basis in our consolidated balance sheet.

Fair Value of Other Financial Instruments

Authoritative guidance on financial instruments requires certain fair value disclosures, such as those on our long-term debt, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. Derivative financial instruments included in our consolidated balance sheet are stated at fair value; however, certain of our derivative financial instruments have a deferred premium, including our crude oil put option contracts, crude oil collars and natural gas collars. The deferred premium reduces the asset or increases the liability depending on the fair value of the derivative financial instrument.

The carrying value of our senior revolving credit facility approximates fair value, as interest rates are variable, based on prevailing market rates. The fair value of our Senior Notes is based on quoted market prices from trades of such debt.

14

The following table presents the carrying amounts and fair values of our other financial instruments as of June 30, 2010 and December 31, 2009 (in thousands):

	June 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Current Liability
Deferred premium and accrued interest on derivative contracts	$	66,752	$	66,752	$	73,305	$	73,305
Non-Current Liability
Deferred premium and accrued interest on derivative contracts		116,810		116,810		-		-
Long-Term Debt
Senior revolving credit facility		-		-		230,000		230,000
7 3/4% Senior Notes		600,000		594,000		600,000		610,500
10% Senior Notes		528,453		604,550		526,222		618,675
7% Senior Notes		500,000		477,500		500,000		491,250
75/8% Senior Notes		400,000		391,000		400,000		409,000
85/8% Senior Notes		393,681		405,000		393,467		411,000
75/8% Senior Notes		300,000		291,000		-		-

Note 5—Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items which are recorded in the period that the specific item occurs. For the three months ended June 30, 2010, income tax expense was approximately 50% of pre-tax income, and for the six months ended June 30, 2010, income tax expense was approximately 47% of pre-tax income. The variance in our estimated annual effective tax rate from the 35% federal statutory rate primarily results from the tax effects of estimated annual permanent differences, including (1) expenses that are not deductible because of Internal Revenue Service limitations, and (2) state income taxes. Specific items affecting income tax expense for the six months ended June 30, 2010 included a tax benefit related to the impairment of our Vietnam oil and gas properties, adjustments to deferred taxes for differences in the reporting of stock based compensation expense for financial statement and income tax reporting purposes and changes to our balance of accrued interest recorded on unrecognized tax benefits.

Note 6—Commitments and Contingencies

Environmental matters. As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 100 years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.

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

15

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, $60 million ($114 million undiscounted), is included in our asset retirement obligation as reflected on our consolidated balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $67 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At June 30, 2010, the escrow account had a balance of $14.2 million. The fair value of our guarantee at June 30, 2010, $0.7 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in our consolidated balance sheet.

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

In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. While there are signs that the economy may be improving, business conditions may remain challenging. Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact their ability to pay out claims.

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

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

Note 7—Consolidating Financial Statements

We are the issuer of $600 million of 7³/₄% Senior Notes, $565 million of 10% Senior Notes, $500 million of 7% Senior Notes, $400 million of 7⁵/₈% Senior Notes, $400 million of 8⁵/₈% Senior Notes and $300 million of 7⁵/₈% Senior Notes as of June 30, 2010, 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.

16

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

JUNE 30, 2010

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	11,401		$	8		$	1,170		$	-		$	12,579
Accounts receivable and other current assets		132,391			115,140			519			(17,701	)		230,349
		143,792			115,148			1,689			(17,701	)		242,928
Property and Equipment, at cost
Oil and natural gas properties - full cost method		4,370,505			8,403,393			59,475			-			12,833,373
Other property and equipment		50,850			35,648			43,563			-			130,061
		4,421,355			8,439,041			103,038			-			12,963,434
Less allowance for depreciation, depletion, amortization and impairment		(2,316,824	)		(5,407,498	)		(59,479	)		1,865,854			(5,917,947	)
		2,104,531			3,031,543			43,559			1,865,854			7,045,487
Investment in and Advances to Affiliates		4,445,041			(1,783,749	)		(62,431	)		(2,598,861	)		-
Other Assets		93,687			540,571			-			-			634,258
	$	6,787,051		$	1,903,513		$	(17,183	)	$	(750,708	)	$	7,922,673
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	281,193		$	152,707		$	2,605		$	(17,701	)	$	418,804
Long-Term Debt		2,722,134			-			-			-			2,722,134
Other Long-Term Liabilities		183,837			65,342			-			-			249,179
Deferred Income Taxes		244,111			(71,231	)		(1,421	)		1,005,321			1,176,780
Stockholders’ Equity		3,355,776			1,756,695			(18,367	)		(1,738,328	)		3,355,776
	$	6,787,051		$	1,903,513		$	(17,183	)	$	(750,708	)	$	7,922,673

17

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2009

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,304		$	11		$	544		$	-		$	1,859
Accounts receivable and other current assets		210,625			113,320			2,820			(21,989	)		304,776
		211,929			113,331			3,364			(21,989	)		306,635
Property and Equipment, at cost
Oil and natural gas properties - full cost method		4,161,478			8,104,424			57,781			-			12,323,683
Other property and equipment		49,403			35,648			40,616			-			125,667
		4,210,881			8,140,072			98,397			-			12,449,350
Less allowance for depreciation, depletion, amortization and impairment		(2,212,695	)		(5,346,513	)		(14	)		1,942,594			(5,616,628	)
		1,998,186			2,793,559			98,383			1,942,594			6,832,722
Investment in and Advances to Affiliates		4,668,480			(1,650,163	)		(68,081	)		(2,950,236	)		-
Other Assets		55,994			539,380			-			-			595,374
	$	6,934,589		$	1,796,107		$	33,666		$	(1,029,631	)	$	7,734,731
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	528,157		$	171,529		$	4,854		$	(21,989	)	$	682,551
Long-Term Debt		2,649,689			-			-			-			2,649,689
Other Long-Term Liabilities		207,035			62,727			-			-			269,762
Deferred Income Taxes		350,727			(151,610	)		5,699			728,932			933,748
Stockholders’ Equity		3,198,981			1,713,461			23,113			(1,736,574	)		3,198,981
	$	6,934,589		$	1,796,107		$	33,666		$	(1,029,631	)	$	7,734,731

18

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2010

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	229,592	$	46,671	$	-	$	-	$	276,263
Gas sales		15,476		72,202		-		-		87,678
Other operating revenues		410		242		-		-		652
		245,478		119,115		-		-		364,593
Costs and Expenses
Production costs		70,399		30,349		-		-		100,748
General and administrative		21,504		8,707		90		-		30,301
Depreciation, depletion, amortization and accretion		56,184		32,895		-		39,138		128,217
Impairment of oil and gas properties		-		-		59,475		-		59,475
Other operating income		-		(3,945)		-		-		(3,945)
		148,087		68,006		59,565		39,138		314,796
Income (Loss) from Operations		97,391		51,109		(59,565)		(39,138)		49,797
Other (Expense) Income
Equity in earnings of subsidiaries		(43,497)		(139)		-		43,636		-
Interest expense		(17)		(27,510)		(512)		-		(28,039)
Gain on mark-to-market derivative contracts		57,984		-		-		-		57,984
Other income (expense)		8		11,469		(242)		-		11,235
Income (Loss) Before Income Taxes		111,869		34,929		(60,319)		4,498		90,977
Income tax (expense) benefit		(66,494)		(13,462)		2,740		31,614		(45,602)
Net Income (Loss)	$	45,375	$	21,467	$	(57,579)	$	36,112	$	45,375

19

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2009

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	181,842		$	37,747		$	-		$	-		$	219,589
Gas sales		13,044			45,497			-			-			58,541
Other operating revenues		239			312			-			-			551
		195,125			83,556			-			-			278,681
Costs and Expenses
Production costs		69,523			36,289			-			-			105,812
General and administrative		23,926			13,456			172			-			37,554
Depreciation, depletion, amortization and accretion		51,613			44,442			6			(1,683	)		94,378
Impairment of oil and gas properties		-			231,629			-			(231,629	)		-
Legal recovery		(81,790	)		(5,482	)		-			-			(87,272	)
Other operating expense		597			902			-			-			1,499
		63,869			321,236			178			(233,312	)		151,971
Income (Loss) from Operations		131,256			(237,680	)		(178	)		233,312			126,710
Other Income (Expense)
Equity in earnings of subsidiaries		77,737			(199	)		-			(77,538	)		-
Interest expense		(10,990	)		(3,402	)		(1,543	)		-			(15,935	)
Debt extinguishment costs		(667	)		-			-			-			(667	)
Loss on mark-to-market derivative contracts		(89,717	)		-			-			-			(89,717	)
Other income (expense)		990			(70	)		(21	)		-			899
Income (Loss) Before Income Taxes		108,609			(241,351	)		(1,742	)		155,774			21,290
Income tax (expense) benefit		(64,960	)		91,684			579			(4,944	)		22,359
Net Income (Loss)	$	43,649		$	(149,667	)	$	(1,163	)	$	150,830		$	43,649

20

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2010

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	463,767		$	88,500		$	-		$	-		$	552,267
Gas sales		40,990			154,427			-			-			195,417
Other operating revenues		516			443			-			-			959
		505,273			243,370			-			-			748,643
Costs and Expenses
Production costs		145,859			64,955			-			-			210,814
General and administrative		46,362			21,234			95			-			67,691
Depreciation, depletion, amortization and accretion		115,318			62,962			-			76,741			255,021
Impairment of oil and gas properties		-			-			59,475			-			59,475
Legal recovery		-			(8,423	)		-			-			(8,423	)
Other operating income		-			(4,514	)		-			-			(4,514	)
		307,539			136,214			59,570			76,741			580,064
Income (Loss) from Operations		197,734			107,156			(59,570	)		(76,741	)		168,579
Other (Expense) Income
Equity in earnings of subsidiaries		(43,883	)		(10	)		-			43,893			-
Interest expense		(30	)		(48,019	)		(1,043	)		-			(49,092	)
Debt extinguishment costs		(728	)		-			-			-			(728	)
Gain on mark-to-market derivative contracts		65,840			-			-			-			65,840
Other income (expense)		623			12,063			(145	)		-			12,541
Income (Loss) Before Income Taxes		219,556			71,190			(60,758	)		(32,848	)		197,140
Income tax (expense) benefit		(115,653	)		(27,956	)		2,938			47,434			(93,237	)
Net Income (Loss)	$	103,903		$	43,234		$	(57,820	)	$	14,586		$	103,903

21

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2009

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	312,450		$	63,753		$	-		$	-		$	376,203
Gas sales		30,738			99,067			-			-			129,805
Other operating revenues		560			625			-			-			1,185
		343,748			163,445			-			-			507,193
Costs and Expenses
Production costs		146,285			75,178			-			-			221,463
General and administrative		50,865			23,433			349			-			74,647
Depreciation, depletion, amortization and accretion		104,197			84,882			10			(3,066	)		186,023
Impairment of oil and gas properties		-			867,856			-			(867,856	)		-
Legal recovery		(81,790	)		(5,482	)		-			-			(87,272	)
Other operating expense		5,054			902			-			-			5,956
		224,611			1,046,769			359			(870,922	)		400,817
Income (Loss) from Operations		119,137			(883,324	)		(359	)		870,922			106,376
Other Income (Expense)
Equity in earnings of subsidiaries		7,468			(392	)		-			(7,076	)		-
Interest expense		(18,303	)		(18,086	)		(1,543	)		-			(37,932	)
Debt extinguishment costs		(10,910	)		-			-			-			(10,910	)
Loss on mark-to-market derivative contracts		(1,578	)		-			-			-			(1,578	)
Other income (expense)		906			(681	)		(33	)		-			192
Income (Loss) Before Income Taxes		96,720			(902,483	)		(1,935	)		863,846			56,148
Income tax (expense) benefit		(47,873	)		341,006			579			(301,013	)		(7,301	)
Net Income (Loss)	$	48,847		$	(561,477	)	$	(1,356	)	$	562,833		$	48,847

22

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2010

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	103,903		$	43,234		$	(57,820	)	$	14,586		$	103,903
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		115,318			62,962			59,475			76,741			314,496
Equity in earnings of subsidiaries		43,883			10			-			(43,893	)		-
Deferred income tax (benefit) expense		(263,821	)		76,251			(2,992	)		276,389			85,827
Debt extinguishment costs		728			-			-			-			728
Gain on mark-to-market derivative contracts		(65,840	)		-			-			-			(65,840	)
Noncash compensation		17,722			5,233			-			-			22,955
Other noncash items		2,659			(1,185	)		198			-			1,672
Change in assets and liabilities from operating activities
Accounts receivable and other assets		28,972			(2,870	)		1,129			-			27,231
Accounts payable and other liabilities		(16,092	)		(15,290	)		17			-			(31,365	)
Income taxes receivable/payable		14,825			-			-			-			14,825
Net cash (used in) provided by operating activities		(17,743	)		168,345			7			323,823			474,432
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(255,650	)		(299,751	)		(2,985	)		-			(558,386	)
Acquisition of oil and gas properties		(59	)		43,982			-			-			43,923
Proceeds from sales of oil and gas properties		7,230			-			-			-			7,230
Derivative settlements		(16,153	)		-			-			-			(16,153	)
Additions to other property and equipment		(1,447	)		(1	)		(2,946	)		-			(4,394	)
Net cash used in investing activities		(266,079	)		(255,770	)		(5,931	)		-			(527,780	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		860,455			-			-			-			860,455
Repayments of revolving credit facilities		(1,090,455	)		-			-			-			(1,090,455	)
Proceeds from issuance of Senior Notes		300,000			-			-			-			300,000
Costs incurred in connection with financing arrangements		(5,932	)		-			-			-			(5,932	)
Investment in and advances to affiliates		229,851			87,422			6,550			(323,823	)		-
Net cash provided by financing activities		293,919			87,422			6,550			(323,823	)		64,068
Net increase (decrease) in cash and cash equivalents		10,097			(3	)		626			-			10,720
Cash and cash equivalents, beginning of period		1,304			11			544			-			1,859
Cash and cash equivalents, end of period	$	11,401		$	8		$	1,170		$	-		$	12,579

23

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2009

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	48,847		$	(561,477	)	$	(1,356	)	$	562,833		$	48,847
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		104,197			952,738			10			(870,922	)		186,023
Equity in earnings of subsidiaries		(7,468	)		392			-			7,076			-
Deferred income tax benefit		(32,932	)		(341,821	)		(579	)		370,572			(4,760	)
Debt extinguishment costs		10,910			-			-			-			10,910
Loss on mark-to-market derivative contracts		1,578			-			-			-			1,578
Noncash compensation		27,359			5,207			-			-			32,566
Other noncash items		2,796			46			71			-			2,913
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(16,777	)		41,392			(1,948	)		-			22,667
Accounts payable and other liabilities		4,314			(19,929	)		180			-			(15,435	)
Income taxes receivable/payable		(143,619	)		-			-			-			(143,619	)
Net cash (used in) provided by operating activities		(795	)		76,548			(3,622	)		69,559			141,690
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(362,986	)		(441,773	)		(22,202	)		-			(826,961	)
Derivative settlements		1,380,322			-			-			-			1,380,322
Additions to other property and equipment		(2,411	)		(600	)		(6,349	)		-			(9,360	)
Net cash provided by (used in) investing activities		1,014,925			(442,373	)		(28,551	)		-			544,001
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		2,240,090			-			-			-			2,240,090
Repayments of revolving credit facilities		(3,545,090	)		-			-			-			(3,545,090	)
Proceeds from issuance of Senior Notes		523,099			-			-			-			523,099
Costs incurred in connection with financing arrangements		(12,114	)		-			-			-			(12,114	)
Derivative settlements		1,392			-			-			-			1,392
Issuance of common stock		250,874			-			-			-			250,874
Investment in and advances to affiliates		(326,681	)		365,552			30,688			(69,559	)		-
Other		28			-			-			-			28
Net cash (used in) provided by financing activities		(868,402	)		365,552			30,688			(69,559	)		(541,721	)
Net increase (decrease) in cash and cash equivalents		145,728			(273	)		(1,485	)		-			143,970
Cash and cash equivalents, beginning of period		309,362			285			2,228			-			311,875
Cash and cash equivalents, end of period	$	455,090		$	12		$	743		$	-		$	455,845

24

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, 2009.

Company Overview

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

• Onshore California;

• Offshore California;

• the Gulf Coast Region;

• the Gulf of Mexico;

• the Mid-Continent Region; and

• the Rocky Mountains.

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. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities, including our significant Haynesville Shale acreage position and our Gulf of Mexico exploration discoveries. Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity.

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 agreements and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated income statement as changes occur in the NYMEX price indices. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk.

Recent Developments

In April 2010, the Deepwater Horizon drilling rig, which was engaged in deepwater Gulf of Mexico drilling operations for another operator, sank after an explosion and fire. In response to this event and the resulting oil spill, certain federal agencies and governmental officials ordered a six month moratorium on the drilling of new deepwater wells and a suspension of permitted wells currently being drilled in the deepwater Gulf of Mexico. The moratorium is scheduled to expire November 30, 2010. We have offshore exploration discoveries with no proved reserves or current production in the deepwater Gulf of Mexico and exploration, development and production ongoing in the Gulf of Mexico shelf and California. This event and its aftermath has created uncertainty with regard to offshore exploration and production activity, including future regulatory requirements, operational delays and cost increases. See Part II Other Information Item 1A – Risk Factors. As a result of these recent events, we have engaged Barclays Capital and Jefferies & Company to assist us in evaluating various alternatives with respect to our Gulf of Mexico operations.

25

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 twelve-month average first-day-of-the-month reference prices as adjusted for location and quality differentials to determine a ceiling value of our properties. Prior to the fourth quarter of 2009, we were required to price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts that qualify and are designated for hedge accounting treatment. The derivative instruments we have in place are not classified as hedges for accounting purposes. The rules require an impairment if our capitalized costs exceed the allowed “ceiling”. At June 30, 2010, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 16%. In the second quarter of 2010, we transferred costs related to the Vietnam oil and gas properties not subject to amortization to our Vietnam full cost pool, which has no associated proved oil and gas reserves. We recorded a non-cash pre-tax impairment charge of $59.5 million and a corresponding tax benefit of $23.0 million.

Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline in the future, impairments of our oil and gas properties could occur. Impairment charges required by these rules do not directly impact our cash flows from operating activities.

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

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

Results Overview

In the first half of 2010, we reported net income of $103.9 million, or $0.73 per diluted share, compared to net income of $48.8 million, or $0.43 per diluted share, in the first half of 2009. The increase primarily reflects higher commodity prices and an increased gain on mark-to-market derivative contracts partially offset by an impairment of our Vietnam oil and gas properties in 2010.

26

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 June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Sales Volumes
Oil and liquids sales (MBbls)		4,131		4,441		8,201		8,886
Gas (MMcf)
Production		22,110		17,972		44,123		35,607
Used as fuel		480		584		958		1,230
Sales		21,630		17,388		43,165		34,377
MBOE
Production		7,816		7,435		15,554		14,820
Sales		7,736		7,338		15,395		14,615
Daily Average Volumes
Oil and liquids sales (Bbls)		45,395		48,792		45,307		49,092
Gas (Mcf)
Production		242,961		197,500		243,773		196,727
Used as fuel		5,272		6,422		5,292		6,797
Sales		237,689		191,078		238,481		189,930
BOE
Production		85,889		81,710		85,935		81,880
Sales		85,010		80,638		85,053		80,747
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	78.05	$	59.79	$	78.46	$	51.68
Gas		4.09		3.50		4.67		4.17
Average Realized Sales Price Before Derivative Transactions
Oil (per Bbl)	$	66.87	$	49.44	$	67.34	$	42.33
Gas (per Mcf)		4.05		3.37		4.52		3.77
Per BOE		47.05		37.90		48.57		34.62
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	7.44	$	8.64	$	7.80	$	9.19
Steam gas costs		1.99		1.49		2.27		1.81
Electricity		1.44		1.69		1.37		1.59
Production and ad valorem taxes		0.49		1.43		0.80		1.51
Gathering and transportation		1.67		1.18		1.45		1.05
Depreciation, depletion and amortization of oil and gas properties	$	15.33	$	11.49	$	15.33	$	11.49

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Oil derivatives
Settlements	$	(17,854)	$	2,716	$	(32,403)	$	159,592
Monetization of crude oil puts and swaps		-		-		-		1,074,361
Natural gas derivatives		11,161		83,449		16,250		147,761
	$	(6,693)	$	86,165	$	(16,153)	$	1,381,714

27

Comparison of Three Months Ended June 30, 2010 to Three Months Ended June 30, 2009

Oil and gas revenues.    Oil and gas revenues increased $85.8 million, to $363.9 million for 2010 from $278.1 million for 2009 primarily due to an increase in realized prices of $9.15 per BOE.

Oil revenues increased $56.7 million to $276.3 million for 2010 from $219.6 million for 2009 primarily reflecting higher average realized prices ($77.4 million), partially offset by lower sales volumes ($20.7 million). Our average realized price for oil increased $17.43 per Bbl to $66.87 per Bbl for 2010 from $49.44 per Bbl for 2009. The increase is primarily attributable to an increase in the NYMEX oil price, which averaged $78.05 per Bbl in 2010 versus $59.79 per Bbl in 2009. Oil sales volumes decreased 3.4 MBbls per day to 45.4 MBbls per day in 2010 from 48.8 MBbls per day in 2009, primarily reflecting decreased production from our onshore California properties.

Gas revenues increased $29.2 million to $87.7 million in 2010 from $58.5 million in 2009 due to an increase in sales volumes ($17.2 million) and an increase in realized prices ($12.0 million). Gas sales volumes increased from 191.1 MMcf per day in 2009 to 237.7 MMcf per day in 2010, primarily reflecting increased production from our Haynesville Shale properties. Our average realized price for gas was $4.05 per Mcf in 2010 compared to $3.37 per Mcf in 2009. Our realized price for gas increased primarily due to an increase in the NYMEX natural gas price, which averaged $4.09 per MMBtu in 2010 versus $3.50 per MMBtu in 2009.

Lease operating expenses.    Lease operating expenses decreased $5.9 million, to $57.5 million in 2010 from $63.4 million in 2009, primarily reflecting a decrease in stock based compensation expense and our program to reduce expenses. On a per unit basis, lease operating expenses decreased to $7.44 per BOE in 2010 from $8.64 per BOE in 2009.

Steam gas costs.    Steam gas costs increased $4.5 million, to $15.4 million in 2010 from $10.9 million in 2009, primarily reflecting the higher cost of gas used in steam generation. In 2010, we burned approximately 3.9 billion cubic feet, or Bcf, of natural gas at a cost of approximately $3.90 per MMBtu compared to 3.7 Bcf at a cost of approximately $2.94 per MMBtu in 2009.

Electricity.    Electricity decreased $1.3 million, to $11.1 million in 2010 from $12.4 million in 2009, primarily reflecting a decrease in rates in California. On a per unit basis, electricity was $1.44 per BOE in 2010 compared to $1.69 per BOE in 2009.

Production and ad valorem taxes.    Production and ad valorem taxes decreased $6.7 million, to $3.8 million in 2010 from $10.5 million in 2009, reflecting production tax abatements and lower ad valorem taxes. The reduction in ad valorem taxes reflects lower commodity prices at the time of assessment.

Gathering and transportation expense.    Gathering and transportation expenses increased $4.2 million, to $12.9 million in 2010 from $8.7 million in 2009, primarily reflecting an increase in production from our Haynesville Shale properties.

General and administrative expense.    G&A expense decreased $7.3 million, to $30.3 million in 2010 from $37.6 million in 2009. The decrease is primarily due to a decrease in stock based compensation expense.

Depreciation, depletion and amortization.    DD&A expense increased $33.0 million, to $123.8 million in 2010 from $90.8 million in 2009. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($28.6 million) and increased production ($5.8 million). Our oil and gas unit of production rate increased to $15.33 per BOE in 2010 compared to $11.49 per BOE in 2009.

Impairment of oil and gas properties.    In the second quarter of 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and have decided not to pursue additional exploratory activities in this area. The costs related to Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling test limitation. Because our Vietnam full cost pool has no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million.

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Legal recovery.    We received a net recovery of $87.3 million in 2009 as our share of a portion of the judgments in the Amber Resources Company et al. v. United States related lawsuits.

Other operating (income) expense.    Other operating income in 2010 consisted primarily of production tax abatements related to production in prior years.

Interest expense.    Interest expense increased $12.1 million, to $28.0 million in 2010 from $15.9 million in 2009, primarily due to greater average debt outstanding in the second quarter of 2010. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $32.1 million and $29.5 million of interest in 2010 and 2009, respectively.

Gain (loss) on mark-to-market derivative contracts.    The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our consolidated income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized a $58.0 million gain related to mark-to-market derivative contracts in the second quarter of 2010, which was primarily associated with an increase in the fair value of our 2011 and 2012 crude oil puts and collars due to lower crude oil prices. In the second quarter of 2009, we recognized an $89.7 million loss related to mark-to-market derivative contracts.

Other income.    Other income in 2010 consisted primarily of interest on MMS royalty refunds related to production in prior years.

Income taxes.    For the second quarter of 2010, income tax expense was approximately 50% of pre-tax income. The variance between this effective tax rate and the 35% federal statutory rate results from the tax effects of estimated annual permanent differences, including (1) expenses that are not deductible because of Internal Revenue Service limitations, and (2) state income taxes. In addition, specific items affecting our income tax expense for the second quarter of 2010 included a tax benefit related to the impairment of our Vietnam oil and gas properties and changes to our balance of accrued interest recorded on unrecognized tax benefits. As income before income taxes changes in future quarters, our effective tax rate may increase or decrease.

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

Comparison of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2009

Oil and gas revenues.    Oil and gas revenues increased $241.7 million, to $747.7 million for 2010 from $506.0 million for 2009 primarily due to an increase in realized prices of $13.95 per BOE.

Oil revenues increased $176.1 million to $552.3 million for 2010 from $376.2 million for 2009 primarily reflecting higher average realized prices ($222.2 million), partially offset by decreased sales volumes ($46.1 million). Our average realized price for oil increased $25.01 per Bbl to $67.34 per Bbl for 2010 from $42.33 per Bbl for 2009. The increase is primarily attributable to an increase in the NYMEX oil price, which averaged $78.46 per Bbl in 2010 versus $51.68 per Bbl in 2009. Oil sales volumes decreased 3.8 MBbls per day to 45.3 MBbls per day in 2010 from 49.1 MBbls per day in 2009, primarily reflecting decreased production from our onshore California properties.

Gas revenues increased $65.6 million to $195.4 million in 2010 from $129.8 million in 2009 due to an increase in sales volumes ($39.8 million) and an increase in realized prices ($25.8 million). Gas sales volumes increased from 189.9 MMcf per day in 2009 to 238.5 MMcf per day in 2010, primarily reflecting increased production from our Haynesville Shale properties. Our average realized price for gas was $4.52 per Mcf in 2010 compared to $3.77 per Mcf in 2009. Our realized price for gas increased primarily due to an increase in the NYMEX natural gas price, which averaged $4.67 per MMBtu in 2010 versus $4.17 per MMBtu in 2009.

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Lease operating expenses.    Lease operating expenses decreased $14.3 million, to $120.0 million in 2010 from $134.3 million in 2009, primarily reflecting the results of our program to reduce expenses. On a per unit basis, lease operating expenses decreased to $7.80 per BOE in 2010 from $9.19 per BOE in 2009.

Steam gas costs.    Steam gas costs increased $8.5 million, to $35.0 million in 2010 from $26.5 million in 2009, primarily reflecting higher cost of gas used in steam generation. In 2010, we burned approximately 7.6 Bcf of natural gas at a cost of approximately $4.60 per MMBtu compared to 7.6 Bcf at a cost of approximately $3.49 per MMBtu in 2009.

Production and ad valorem taxes.    Production and ad valorem taxes decreased $9.8 million, to $12.3 million in 2010 from $22.1 million in 2009, reflecting lower ad valorem taxes and production tax abatements. The reduction in ad valorem taxes reflects lower commodity prices at the time of assessment.

Gathering and transportation expense.    Gathering and transportation expenses increased $7.0 million, to $22.3 million in 2010 from $15.3 million in 2009, primarily reflecting an increase in production from our Haynesville Shale properties.

General and administrative expense.    G&A expense decreased $6.9 million, to $67.7 million in 2010 from $74.6 million in 2009, primarily due to a decrease in stock based compensation expense.

Depreciation, depletion and amortization.    DD&A expense increased $67.3 million, to $246.2 million in 2010 from $178.9 million in 2009. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($56.9 million) and increased production ($11.3 million). Our oil and gas unit of production rate increased to $15.33 per BOE in 2010 compared to $11.49 per BOE in 2009.

Impairment of oil and gas properties.    During the six months ended June 30, 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and have decided not to pursue additional exploratory activities in this area. The costs related to Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling test limitation. Because our Vietnam full cost pool has no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million.

Legal recovery.    We received a net recovery of $8.4 million in 2010 and $87.3 million in 2009 as our share of a portion of the judgments in the Amber Resources Company et al. v. United States related lawsuits.

Other operating (income) expense.    Other operating income in 2010 consisted primarily of severance tax abatements related to production in prior years. Other operating expense in 2009 consisted primarily of a restocking fee related to a cancelled purchase order, a valuation adjustment for materials and supplies inventory and idle drilling equipment costs resulting from unused contract commitments.

Interest expense.    Interest expense increased $11.2 million, to $49.1 million in 2010 from $37.9 million in 2009, primarily due to higher interest expense in 2010 on our fixed rate debt compared to our variable rate borrowings. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $66.4 million and $49.2 million of interest in 2010 and 2009, respectively. The increased capitalized interest is attributable to a higher unevaluated property balance and a higher average interest rate during 2010.

Debt extinguishment costs.    In connection with reductions of the borrowing base on our senior revolving credit facility, we recorded $0.7 million and $10.9 million of debt extinguishment costs in the six months ended June 30, 2010 and 2009, respectively.

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Gain (loss) on mark-to-market derivative contracts.    The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our consolidated income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized a $65.8 million gain related to mark-to-market derivative contracts in the six months ended June 30, 2010, which was primarily associated with an increase in fair value of our 2011 and 2012 crude oil puts and 2010 natural gas collars due to lower crude oil and natural gas prices. In the six months ended June 30, 2009, we recognized a $1.6 million loss related to mark-to-market derivative contracts.

Other income.    Other income in 2010 consisted primarily of interest on MMS royalty refunds related to production in prior years.

Income taxes.    For the six months ended June 30, 2010, our income tax expense was approximately 47% of pre-tax income. The variance between this effective tax rate and the 35% federal statutory rate results from the tax effects of estimated annual permanent differences, including (1) expenses that are not deductible because of Internal Revenue Service limitations, and (2) state income taxes. In addition, specific items affecting our income tax expense for the six months ended June 30, 2010 included a tax benefit related to the impairment of our Vietnam oil and gas properties, adjustments to deferred taxes for differences in the reporting of stock based compensation expense for financial statement and income tax reporting purposes and changes to our balance of accrued interest recorded on unrecognized tax benefits. As income before income taxes changes in future quarters, our effective tax rate may increase or decrease.

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

Liquidity and Capital Resources

Our liquidity may be affected by declines in oil and gas prices, an inability to access the capital and credit markets and the success of our commodity price risk management activities, which may subject us to the credit risk of the counterparties to such agreements. This situation may arise due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions that cause substantial or extended declines in oil and gas prices. While there are signs that the economy may be improving, the potential remains for further volatility and disruption in the capital and credit markets. The recent volatility and disruption have created conditions that may adversely affect the financial condition of lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, our insurers and our oil and natural gas purchasers. These market conditions may adversely affect our liquidity by limiting our ability to access the capital and credit markets.

Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity. At June 30, 2010, our borrowing base under our senior revolving credit facility was $1.3 billion, approximately all of which was available. Under the terms of our senior revolving credit facility, the borrowing base will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Declines in oil and gas prices may adversely affect our liquidity by lowering the amount of the borrowing base that the lenders are willing to extend. In August 2010, we entered into an Amended Credit Agreement which increased our borrowing capacity to approximately $1.4 billion. See Financing Activities.

The commitments of each lender to make loans to us are several and not joint under our senior revolving credit facility. Accordingly, if any lender fails to make loans to us, our available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the credit facility. At June 30, 2010, the commitments are from a diverse syndicate of 22 lenders and no single lender’s commitment represented more than 10% of the total commitments; our Amended Credit Agreement retained single lenders commitments below 10% of the total commitments.

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

Our 2010 capital budget is approximately $1.1 billion, including capitalized interest and general and administrative expense. We intend to fund our 2010 capital budget from internally generated funds, cash on hand and borrowings under our senior revolving credit facility.

We believe that we have sufficient liquidity through our forecasted cash flow 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, contingencies and anticipated capital expenditures. We have no near-term debt maturities. At June 30, 2010, our senior revolving credit facility had no amounts outstanding. The next maturity of our senior notes will occur on June 15, 2015.

Working Capital

At June 30, 2010, we had a working capital deficit of approximately $175.9 million. We generally have a working capital deficit because we use excess cash to pay down borrowings under our senior revolving credit facility. Our working capital fluctuates for various reasons, including the fair value of our commodity derivative instruments and stock appreciation rights.

Financing Activities

In March 2010, our borrowing base was adjusted from $1.22 billion to $1.13 billion in recognition of our issuance of the 7  ^5/8% Senior Notes and subsequently increased to $1.3 billion in April 2010 after entering into an amendment to our senior revolving credit facility. Our senior revolving credit facility contains a $250 million limit on letters of credit and a $50 million commitment for swingline loans. As of June 30, 2010, our borrowing base was $1.3 billion, approximately all of which was available, and we had $1.4 million in letters of credit outstanding. In August 2010, we entered into an Amended Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and the lenders party thereto, which amends and restates our Prior Credit Facility. The aggregate commitments of the lenders under our Amended Credit Agreement are $1.4 billion. Our Amended Credit Agreement provides for an initial borrowing base of $1.6 billion that will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Our Amended Credit Agreement contains the same limits on letters of credit and swingline loans, and matures in August 2015.

Amounts borrowed under our Amended Credit Agreement bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.75% to 2.75%; (ii) a variable amount ranging from 0.75% to 1.75% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus ¹/2 of 1%, and (3) the adjusted LIBOR plus 1%; or (iii) the over-night federal funds rate plus an additional variable amount ranging from 1.75% to 2.75% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on the utilization rate as a percentage of the total amount of funds borrowed under our Amended Credit Agreement to the borrowing base. Letter of credit fees under our Amended Credit Agreement are based on the utilization rate and range from 1.75% to 2.75%. Commitment fees are 0.50% of the amount available for borrowing.

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Our Amended Credit Agreement is secured by 100% of the shares of stock in certain of our domestic subsidiaries, 65% of the shares of stock in certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic proved oil and gas properties. Our Amended Credit Agreement 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 4.50 to 1.

In March 2010, we issued $300 million of 7 ⁵/8% Senior Notes, which were sold to the public at par. We received approximately $294 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 7 ⁵/8% Senior Notes on or after April 1, 2015 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to April 1, 2013 we may, at our option, redeem up to 35% of the 7 ⁵/8% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 7 ⁵/8% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 7 ⁵/8% Senior Notes are general unsecured senior obligations. They are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. These 7 ⁵/8% 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 7 ⁵/8% Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries.

Cash Flows

	Six Months Ended June  30,
	2010		2009
	(in millions)
Cash provided by (used in):
Operating activities	$	474.4	$	141.7
Investing activities		(527.8)		544.0
Financing activities		64.1		(541.7)

Net cash provided by operating activities was $474.4 million in 2010 compared to $141.7 million in 2009. The increase primarily reflects higher operating income in 2010 as a result of higher commodity prices. Additionally, cash provided by operations in 2009 included income tax payments related to 2008 taxable income and cash receipts for the legal recovery.

Net cash used in investing activities of $527.8 million in 2010 primarily reflects additions to oil and gas properties of $558.4 million, offset by a $43.9 million net cash inflow primarily associated with an adjustment to the final settlement of the $1.1 billion payment to Chesapeake Energy Corporation in September 2009 related to the prepayment of the Haynesville drilling carry. Net cash provided by investing activities of $544.0 million in 2009 primarily reflects derivative settlements received of $1.4 billion, partially offset by additions to oil and gas properties of $827.0 million.

Net cash provided by financing activities of $64.1 million in 2010 primarily reflects proceeds from the $300 million offering of 7 ⁵/8% Senior Notes partially offset by the net reduction in borrowings under our senior revolving credit facility of $230.0 million. Net cash used in financing activities of $541.7 million in 2009 primarily reflects the $1.3 billion net reduction in borrowings under our senior revolving credit facility partially offset by net proceeds of $511.0 million from the offering of 10% Senior Notes due 2016 and the $250.9 million of proceeds from our common stock offering.

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Stock Repurchase Program

In December 2007, our Board of Directors authorized the repurchase of up to $1.0 billion of our common stock. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. We currently have $695.8 million in authorized repurchases remaining under the program.

Critical Accounting Policies and Estimates

Goodwill.    In a purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed, including deferred income taxes recorded in connection with the transaction, over the fair value of the net assets acquired. At June 30, 2010, goodwill totaled $535 million and represented approximately 7% of our total assets.

Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. A two-step impairment test is used to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized, if any. The first step of the goodwill impairment test compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired, thus the second step of the impairment test is unnecessary.

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

We follow the full cost method of accounting for oil and gas activities and all of our producing properties are located in the United States. We have determined that for the purpose of performing an impairment test, we have one reporting unit.

The first step of the goodwill impairment test requires that we make an estimate of the fair value of the reporting unit. Quoted market prices in active markets are the best evidence of fair value. We estimate the fair value of the reporting unit by applying a control premium to the quoted market price of our common stock. We determine the control premium through reference to control premiums in merger and acquisition transactions for our industry and other comparable industries. This requires that we make certain judgments about the selection of merger and acquisition transactions and transaction premiums.

We perform our goodwill impairment test annually as of December 31. We also perform interim goodwill impairment tests if events occur or circumstances change that would indicate the fair value of our reporting unit may be below its carrying amount. Due to adverse market conditions affecting the oil and gas industry in the second quarter of 2010, we performed an interim goodwill impairment test as of June 30, 2010. Based on that test, we concluded that the fair value of the reporting unit exceeded the carrying value of the reporting unit by 13%; therefore, the second step of the goodwill impairment test was not required.

Events affecting oil and gas prices may cause a decrease in the fair value of the reporting unit, and we could have an impairment of our goodwill in future periods. An impairment of goodwill could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders’ equity.

Management makes many estimates and assumptions in the application of generally accepted accounting principles that may have a material impact on our consolidated financial statements and related disclosures and on the comparability of this information over different reporting periods. All of these estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on information available prior to the issuance of the financial statements. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates. Critical accounting policies related to oil and gas reserves, impairments of oil and gas properties, oil and natural gas properties not subject to amortization, DD&A, commodity pricing and risk management activities, stock based compensation and allocation of purchase price in business combinations are discussed in our Annual Report on Form 10-K for the year ended December 31, 2009.

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Recent Accounting Pronouncements

In June 2009, the FASB issued authoritative guidance for improving financial reporting by enterprises involved with variable interest entities. This guidance eliminates the exemption for qualifying special purpose entities, includes a new approach for determining who should consolidate a variable interest entity, and presents changes as to when it is necessary to reassess who should consolidate a variable interest entity. The guidance is effective for fiscal years beginning after November 15, 2009, and for interim periods within that first annual reporting period. We adopted the provisions of this standard effective January 1, 2010, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.

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Statement Regarding Forward-Looking Statements

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

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

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

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

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

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

• the success of our derivative activities;

• the success of our risk management activities;

• the effects of competition;

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

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

• the impact of current and future laws and governmental regulations, including those related to climate change;

• the effects of the current moratorium on drilling of new deepwater wells as well as the effects of future laws and governmental regulation that result from the recent drilling rig accident and oil spill in the Gulf of Mexico;

• the outcome of our evaluation of various alternatives relating to our offshore operations;

• 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. We do not intend to update these forward-looking statements and information except as required by law. See Item 1A – Risk Factors of this report and our filings with the SEC, including Item 1A – Risk Factors and Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates in our Annual Report on Form 10-K for the year ended December 31, 2009 for additional discussion of risks and uncertainties.

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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 in our consolidated 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. The derivative instruments we have in place are not classified as hedges for accounting purposes.

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

As of June 30, 2010, we had the following outstanding commodity derivative contracts, all of which settle monthly:

Period	Instrument Type	Daily Volumes	Average Price (1)	Average Deferred Premium	Index
Sales of Crude Oil Production
2010
July - Dec	Put options	40,000 Bbls	$55.00 Strike price	$5.00 per Bbl(2)	WTI
2011
Jan - Dec	Put options  (3)	31,000 Bbls	$80.00 Floor with a $60.00 Limit	$5.023 per Bbl	WTI
Jan - Dec	Three-way collars  (4)	9,000 Bbls	$80.00 Floor with a $60.00 Limit	$1.00 per Bbl	WTI
			$110.00 Ceiling
2012
Jan - Dec	Put options  (3)	40,000 Bbls	$80.00 Floor with a $60.00 Limit	$6.087 per Bbl	WTI
Sales of Natural Gas Production
2010
July - Dec	Three-way collars (5)	85,000 MMBtu	$6.12 Floor with a $4.64 Limit	$0.034 per MMBtu	Henry Hub
			$8.00 Ceiling

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

(2) In addition to the deferred premium, an upfront payment of $3.86 per barrel was paid upon entering into these derivative contracts.

(3) If the index price is less than the $80 per barrel floor, we receive the difference between the $80 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above $80 per barrel, we pay only the option premium.

(4) If the index price is less than the $80 per barrel floor, we receive the difference between the $80 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. We pay the difference between the index price and $110 per barrel plus the option premium if the index price is greater than the $110 per barrel ceiling. If the index price is at or above $80 per barrel but at or below $110 per barrel, we pay only the option premium.

(5) If the index price is less than the $6.12 per MMBtu floor, we receive the difference between the $6.12 per MMBtu floor and the index price up to a maximum of $1.48 per MMBtu less the option premium. We pay the difference between the index price and $8.00 per MMBtu plus the option premium if the index price is greater than the $8.00 ceiling per MMBtu. If the index price is at or above $6.12 per MMBtu but at or below $8.00 per MMBtu, we pay only the option premium.

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The fair value of outstanding crude oil and natural gas commodity derivative instruments at June 30, 2010 and the change in fair value that would be expected from a 10% price increase/decrease is shown below (in millions):

			Effect of 10%
	Fair Value Asset		Price Increase		Price Decrease
Crude oil put options	$	193	$	(46)	$	55
Crude oil collars		15		(12)		11
Natural gas collars		17		(3)		3
	$	225	$	(61)	$	69

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

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

ITEM 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rules 13a-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended, or the Exchange Act). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer believe that the disclosure controls and procedures as of June 30, 2010 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.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2010 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1A. Risk Factors

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

Our operations in the Gulf of Mexico and offshore California could be adversely impacted by the recent drilling rig accident and resulting oil spill.

In April 2010, the Deepwater Horizon drilling rig, which was engaged in deepwater Gulf of Mexico drilling operations for another operator, sank after an explosion and fire. In response to this event and the resulting oil spill, certain federal agencies and governmental officials ordered a six-month moratorium on the drilling of new deepwater wells and a suspension of permitted wells currently being drilled in the deepwater Gulf of Mexico. The moratorium is scheduled to expire November 30, 2010.

We have offshore exploration, development and production ongoing in the Gulf of Mexico and California. This event and its aftermath will lead to additional governmental regulation of the offshore exploration and production industry. Recent legislative proposals include limitations upon, or elimination of, existing liability caps, an increased minimum level of financial responsibility and additional safety and spill-response requirements. We cannot predict with any certainty what form the additional regulation or limitations will take. The impact upon our business of such regulations or limitations could include cost increases, offshore exploration and development activity delay, as well as changes in the availability and cost of insurance.

Potential regulations regarding derivatives could adversely impact our ability to engage in commodity price risk management activities.

We use derivative instruments to manage our commodity price risk. The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which was signed into law in July 2010, contains measures aimed at increasing the transparency and stability of the over-the-counter, or OTC, derivative markets and preventing excessive speculation. The Dodd-Frank Act could restrict trading positions in the energy futures markets and may require us to comply with cash margin requirements. These changes could materially reduce our hedging opportunities and increase the costs associated with our hedging programs, both of which would negatively affect our revenues and cash flow.

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ITEM 6. Exhibits

Exhibit No.	Description
4.1	Amendment No. 5 to Amended Restated Credit Agreement, dated as of April 12, 2010, 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 April 12, 2010, File No. 001-31470).
10.1	Plains Exploration & Production Company 2010 Incentive Award Plan (incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed on March 30, 2010, File No. 001-31470).
31.1*	Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Chief Executive Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Chief Financial Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
*    Filed herewith

Items 1, 2, 3, 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: August 5, 2010
	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
4.1	Amendment No. 5 to Amended Restated Credit Agreement, dated as of April 12, 2010, 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 April 12, 2010, File No. 001-31470).
10.1	Plains Exploration & Production Company 2010 Incentive Award Plan (incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed on March 30, 2010, File No. 001-31470).
31.1*	Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Chief Executive Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Chief Financial Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
*    Filed herewith

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