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, 2012

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

  Yes ¨    No x

129.0 million shares of Common Stock, $0.01 par value, issued and outstanding at July 27, 2012.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART I.  FINANCIAL INFORMATION
ITEM 1.  Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets June 30, 2012 and December 31, 2011	1
Consolidated Statements of Income For the three months ended and six months ended June 30, 2012 and 2011	2
Consolidated Statements of Cash Flows For the six months ended June 30, 2012 and 2011	3
Consolidated Statement of Equity For the six months ended June 30, 2012	4
Notes to Consolidated Financial Statements	5
ITEM 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk	48
ITEM 4. Controls and Procedures	51
PART II. OTHER INFORMATION	52

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	June 30, 2012		December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents	$	302,157	$	419,098
Accounts receivable		284,591		302,675
Commodity derivative contracts		99,458		50,964
Inventories		18,517		20,173
Investment		562,491		611,671
Deferred income taxes		53,300		20,723
Prepaid expenses and other current assets		14,323		16,073
		1,334,837		1,441,377
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		13,533,372		12,016,252
Not subject to amortization		1,747,325		2,409,449
Other property and equipment		152,385		145,959
		15,433,082		14,571,660
Less allowance for depreciation, depletion, amortization and impairment		(7,210,472)		(6,846,365)
		8,222,610		7,725,295
Goodwill		535,140		535,140
Commodity Derivative Contracts		54,431		12,678
Other Assets		84,417		76,982
	$	10,231,435	$	9,791,472
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	439,718	$	385,231
Commodity derivative contracts		-		3,761
Royalties and revenues payable		103,074		97,095
Stock-based compensation		14,586		21,676
Interest payable		66,005		39,342
Other current liabilities		67,525		79,081
		690,908		626,186
Long-Term Debt		3,918,940		3,760,952
Other Long-Term Liabilities
Asset retirement obligation		239,165		230,633
Commodity derivative contracts		454		823
Other		16,524		15,749
		256,143		247,205
Deferred Income Taxes		1,601,934		1,461,897
Commitments and Contingencies (Note 8)
Equity
Stockholders’ equity
Common stock, $0.01 par value, 250.0 million shares authorized, 143.9 million shares issued at June 30, 2012 and December 31, 2011		1,439		1,439
Additional paid-in capital		3,415,323		3,434,928
Retained earnings		471,903		337,991
Treasury stock, at cost, 15.0 million shares and 13.3 million shares at June 30, 2012 and December 31, 2011, respectively		(560,343)		(509,722)
		3,328,322		3,264,636
Noncontrolling interest
Preferred stock of subsidiary		435,188		430,596
		3,763,510		3,695,232
	$	10,231,435	$	9,791,472

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,
	2012		2011		2012		2011
Revenues
Oil sales	$	519,508	$	399,306	$	986,996	$	731,149
Gas sales		45,959		113,670		99,483		210,472
Other operating revenues		1,257		1,809		4,520		3,478
		566,724		514,785		1,090,999		945,099
Costs and Expenses
Lease operating expenses		87,662		82,142		170,668		154,393
Steam gas costs		9,711		16,865		20,835		32,626
Electricity		10,777		10,371		22,151		20,091
Production and ad valorem taxes		19,085		16,920		31,716		28,448
Gathering and transportation expenses		19,029		16,841		35,301		29,588
General and administrative		31,701		30,783		70,083		66,806
Depreciation, depletion and amortization		250,730		150,757		428,427		285,300
Accretion		3,750		4,314		7,503		8,571
Other operating income		(1,276)		(303)		(2,537)		(607)
		431,169		328,690		784,147		625,216
Income from Operations		135,555		186,095		306,852		319,883
Other (Expense) Income
Interest expense		(52,977)		(37,242)		(98,230)		(69,646)
Debt extinguishment costs		(5,167)		-		(5,167)		-
Gain (loss) on mark-to-market derivative contracts		221,783		18,912		112,733		(32,084)
Gain (loss) on investment measured at fair value		86,750		43,307		(49,180)		110,561
Other income		834		996		429		1,550
Income Before Income Taxes		386,778		212,068		267,437		330,264
Income tax expense
Current		(986)		(387)		(1,005)		(759)
Deferred		(153,517)		(86,789)		(107,460)		(133,634)
Net Income		232,275	$	124,892		158,972	$	195,871
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		(9,076)				(18,092)
Net Income Attributable to Common Stockholders	$	223,199			$	140,880
Earnings per Common Share
Basic	$	1.72	$	0.88	$	1.09	$	1.39
Diluted	$	1.70	$	0.87	$	1.07	$	1.37
Weighted Average Common Shares Outstanding
Basic		130,019		141,797		129,683		141,335
Diluted		131,509		143,300		131,701		143,361

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,
	2012		2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	158,972	$	195,871
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		428,427		285,300
Accretion		7,503		8,571
Deferred income tax expense		107,460		133,634
Debt extinguishment costs		939		-
(Gain) loss on mark-to-market derivative contracts		(112,733)		32,084
Loss (gain) on investment measured at fair value		49,180		(110,561)
Non-cash compensation		26,229		28,031
Other non-cash items		3,060		(302)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		13,290		(21,470)
Accounts payable and other liabilities		(60,006)		(14,103)
Income taxes receivable/payable		8,635		40,370
Net cash provided by operating activities		630,956		577,425
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(824,280)		(800,170)
Acquisition of oil and gas properties		(20,141)		(32,456)
Proceeds from sales of oil and gas properties, net of costs and expenses		42,842		11,987
Derivative settlements		17,862		(30,039)
Additions to other property and equipment		(6,426)		(6,534)
Net cash used in investing activities		(790,143)		(857,212)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		4,334,675		2,679,200
Repayments of revolving credit facilities		(4,771,675)		(2,989,200)
Principal payments of long-term debt		(156,182)		-
Proceeds from issuance of Senior Notes		750,000		600,000
Costs incurred in connection with financing arrangements		(12,582)		(11,320)
Purchase of treasury stock		(88,490)		-
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		(13,500)		-
Other		-		4
Net cash provided by financing activities		42,246		278,684
Net decrease in cash and cash equivalents		(116,941)		(1,103)
Cash and cash equivalents, beginning of period		419,098		6,434
Cash and cash equivalents, end of period	$	302,157	$	5,331

See notes to consolidated financial statements.

3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF EQUITY (Unaudited)

(share and dollar amounts in thousands)

															Noncontrolling
															Interest
															in the
					Additional								Total		Form of
	Common Stock				Paid-in		Retained		Treasury Stock				Stockholders’		Preferred Stock		Total
	Shares		Amount		Capital		Earnings		Shares		Amount		Equity		of Subsidiary		Equity
Balance at December 31, 2011		143,924	$	1,439	$	3,434,928	$	337,991		(13,302)	$	(509,722)	$	3,264,636	$	430,596	$	3,695,232
Net income		-		-		-		140,880		-		-		140,880		18,092		158,972
Restricted stock awards		-		-		11,282		-		-		-		11,282		-		11,282
Treasury stock purchases		-		-		-		-		(2,390)		(88,490)		(88,490)		-		(88,490)
Issuance of treasury stock for restricted stock awards		-		-		(30,887)		(6,964)		729		37,851		-		-		-
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-		-		-		-		-		-		-		(13,500)		(13,500)
Exercise of stock options and other		-		-		-		(4)		-		18		14		-		14
Balance at June 30, 2012		143,924	$	1,439	$	3,415,323	$	471,903		(14,963)	$	(560,343)	$	3,328,322	$	435,188	$	3,763,510

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 located in the United States.

Our consolidated financial statements include the accounts of all our consolidated subsidiaries. We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. All significant intercompany transactions have been eliminated. 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, 2012 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 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, 2011.

Asset Retirement Obligation.    The following table reflects the changes in our asset retirement obligation during the six months ended June 30, 2012 (in thousands):

Asset retirement obligation - December 31, 2011	$	238,381
Settlements		(2,694)
Accretion expense		7,503
Asset retirement additions		2,344
Asset retirement obligation - June 30, 2012 (1)	$	245,534

(1) $6.4 million is included in other current liabilities.

Earnings Per Share. For the three and six months ended June 30, 2012 and 2011, the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
Weighted average common shares outstanding - basic		130,019		141,797		129,683		141,335
Unvested restricted stock, restricted stock units and stock options		1,490		1,503		2,018		2,026
Weighted average common shares outstanding - diluted		131,509		143,300		131,701		143,361

5

In the three months ended June 30, 2012 and 2011, 0.9 million and 1.0 million restricted stock units, respectively, and in the six months ended June 30, 2012 and 2011, 0.5 million and 1.0 million restricted stock units, respectively, were excluded in computing diluted earnings per share because they were antidilutive due to the impact of the unrecognized compensation cost on the calculation of assumed proceeds in the application of the treasury stock method.

In computing our earnings per share for the three and six months ended June 30, 2012, we decreased our reported net income by $9.1 million and $18.1 million, respectively, for preferred stock dividends attributable to the noncontrolling interest associated with our consolidated subsidiary Plains Offshore Operations Inc., or Plains Offshore. We owned 100% of the common shares of Plains Offshore during the three and six months ended June 30, 2012, and because Plains Offshore had a net loss for the three and six months ended June 30, 2012, we did not allocate any undistributed earnings to the noncontrolling interest preferred stock. In the event that Plains Offshore has net income in future periods, we will be required to allocate distributed and undistributed earnings between the common and preferred shares of Plains Offshore.

Inventories.    Oil inventories are carried at the lower of the cost to produce or market value, and materials and supplies inventories are stated at the lower of cost or market with cost determined on an average cost method. At June 30, 2012 and December 31, 2011, inventory consisted of the following (in thousands):

	June 30,		December 31,
	2012		2011
Oil	$	6,664	$	7,075
Materials and supplies		11,853		13,098
	$	18,517	$	20,173

Oil and Natural Gas Properties Not Subject to Amortization.    The cost of unproved oil and natural gas properties are 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. 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 these transfers into our amortization base impacts our depreciation, depletion and amortization, or DD&A, rate and full cost ceiling test.

6

During the first quarter of 2012, due to low natural gas prices, our assessment of the unproved property in the Haynesville Shale area indicated an impairment and accumulated costs of approximately $483 million were transferred to the full cost pool.

Stock-Based Compensation.    Stock-based compensation for the three and six months ended June 30, 2012 and 2011 was (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
Stock-based compensation included in:
General and administrative expense	$	8,385	$	9,522	$	22,192	$	23,365
Lease operating expenses		(388)		1,703		4,037		4,666
Oil and natural gas properties		2,257		2,976		7,527		7,495
Total stock-based compensation	$	10,254	$	14,201	$	33,756	$	35,526

During the first six months of 2012, we granted 877 thousand RSUs at an average fair value of $42.59 per share to be settled in shares of common stock, 1.2 million RSUs at an average fair value of $43.04 per share to be settled in cash and 478 thousand stock appreciation rights with an average exercise price of $42.88 per share.

Additionally, we issued 225 thousand RSUs to be settled in cash that are subject to a market condition in which the price performance of PXP common stock is compared to an average of two peer indices. Based on the performance, these units may settle upon vesting at 0% to 150% of the number of awards granted as determined by linear interpolation.

We used a Monte-Carlo simulation model to estimate the fair value of the cash-settled RSUs subject to the market condition. This model involves forecasting potential future stock price paths based on the expected return on our common stock and the indices and their volatility, then calculating the fair value of RSUs to be granted based on the results of the simulations. At June 30, 2012, we estimated that these units had a weighted average fair value of $28.68 per unit, an aggregate fair value of $6.5 million and a weighted average remaining contractual life of 1.8 years.

Stock Repurchase Program.    In January 2012, we repurchased 2.4 million common shares at an average cost of $37.02 per share, totaling $88.5 million. Subsequent to these repurchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock, all of which is available for repurchase, and extended the program until January 2016.

Noncontrolling Interest in the Form of Preferred Stock of Subsidiary.    Noncontrolling interest in the form of preferred stock of subsidiary represents the ownership interest held by third parties in the net assets of our consolidated subsidiary Plains Offshore, in the form of convertible perpetual preferred stock and associated non-detachable warrants.

7

The preferred stock of Plains Offshore is classified as permanent equity in our consolidated balance sheet since redemption for cash of the preferred interests is within our and Plains Offshore’s control. The non-detachable warrants are considered to be embedded instruments for accounting purposes as the instrument cannot be both legally detached and separately exercised from the host preferred stock, nor can the non-detachable warrants be transferred or sold without also transferring the ownership in the preferred stock.

During the three months ended June 30, 2012, Plains Offshore declared a quarterly dividend on the preferred stock of approximately $9.1 million, or $20.12 per share of preferred stock, $15.00 per share of which was paid in cash with the remaining deferred. During the six months ended June 30, 2012, Plains Offshore declared quarterly dividends on the preferred stock of approximately $18.1 million, or $40.14 per share of preferred stock, $30.00 per share of which was paid in cash with the remaining deferred. Deferred dividends accumulate and compound quarterly at 8% per year until paid.

Recent Accounting Pronouncements.    In December 2011, the Financial Accounting Standards Board, or FASB, issued authoritative guidance requiring entities to disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as financial instruments and transactions subject to agreements similar to master netting arrangements. The additional disclosures will enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning on or after January 1, 2013, and will primarily impact our disclosures associated with our commodity derivative instruments. We are currently evaluating the impact of this guidance.

Note 2 — Long-Term Debt

At June 30, 2012 and December 31, 2011, long-term debt consisted of (in thousands):

	June 30, 2012		December 31, 2011
Senior revolving credit facility	$	298,000	$	735,000
Plains Offshore senior credit facility		-		-
7  3/4% Senior Notes due 2015		-		79,281
10% Senior Notes due 2016 (1)		176,299		175,385
7% Senior Notes due 2017		-		76,901
7  5/8% Senior Notes due 2018		400,000		400,000
6  1/8% Senior Notes due 2019		750,000		-
8  5/8% Senior Notes due 2019 (2)		394,641		394,385
7  5/8% Senior Notes due 2020		300,000		300,000
6  5/8% Senior Notes due 2021		600,000		600,000
6  3/4% Senior Notes due 2022		1,000,000		1,000,000
	$	3,918,940	$	3,760,952

(1) The amount is net of unamortized discount of $8.6 million and $9.5 million at June 30, 2012 and December 31, 2011, respectively.

(2) The amount is net of unamortized discount of $5.4 million and $5.6 million at June 30, 2012 and December 31, 2011, respectively.

8

Senior Revolving Credit Facility.     In February 2012, our borrowing base was increased from $1.8 billion to approximately $2.3 billion until the next scheduled redetermination date on or before May 1, 2013. The commitments remained unchanged at $1.4 billion. 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 factors. We are required, among other things, to make a mandatory prepayment if the combined total borrowings under both our senior revolving credit facility and the Plains Offshore senior credit facility exceed the borrowing base. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit, a $50 million commitment for swingline loans and matures on May 4, 2016. At June 30, 2012, we had $1.2 million in letters of credit outstanding under our senior revolving credit facility.

Amounts borrowed under our senior revolving credit facility bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% 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 overnight federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts 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 4.50 to 1.

Plains Offshore Senior Credit Facility.     The aggregate commitments of the lenders under the Plains Offshore senior credit facility are $300 million. The Plains Offshore senior credit facility contains a $50 million limit on letters of credit and matures on November 18, 2016. At June 30, 2012, Plains Offshore had no letters of credit outstanding under its senior credit facility.

Amounts borrowed under the Plains Offshore senior credit facility bear an interest rate, at Plains Offshore’s election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; or (ii) a variable amount ranging from 0.50% to 1.50% 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%. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under the Plains Offshore senior credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing.

9

The borrowings under the Plains Offshore senior credit facility are guaranteed on a senior basis by PXP and certain of our subsidiaries, and are secured on a pari passu basis by liens on the same collateral that secures PXP’s senior revolving credit facility. The Plains Offshore senior credit facility contains certain affirmative and negative covenants, including limiting Plains Offshore’s ability, among other things, to create liens, incur other indebtedness, make dividends (excluding dividends on preferred stock) or other distributions, make investments, change the nature of Plains Offshore’s business and merge or consolidate, sell assets, enter into certain types of swap agreements and enter into certain transactions with affiliates, as well as other customary events of default, including a cross-default to PXP’s senior revolving credit facility. If an event of default (as defined in our senior revolving credit facility) has occurred and is continuing under our senior revolving credit facility that has not been cured or waived by the lenders thereunder then the Plains Offshore lenders could accelerate and demand repayment of the Plains Offshore senior credit facility.

Short-term Credit Facility.    We have an uncommitted short-term unsecured credit facility, or short-term facility, under which we may make borrowings from time to time until June 1, 2013, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding 14 days and all amounts outstanding are due and payable no later than June 1, 2013. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and us.

We borrow under our short-term facility to fund our working capital needs. The funding requirements are typically generated due to the timing differences between payments and receipts associated with our oil and gas production. We generally pay off the short-term facility with receipts from the sales of our oil and gas production or borrowings under our senior revolving credit facility. No amounts were outstanding under the short-term facility at June 30, 2012. The daily average outstanding balance for the three and six months ended June 30, 2012 was $48.8 million and $45.9 million, respectively.

6  ¹/₈% Senior Notes. In April 2012, we issued $750 million of 6 ¹/₈% Senior Notes due 2019, or the 6 ¹/₈% Senior Notes, at par. We received approximately $737.5 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, including the redemption of $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes due 2015, or the 7 ³/₄% Senior Notes, and $76.9 million aggregate principal amount of our 7% Senior Notes due 2017, or the 7% Senior Notes. We may redeem all or part of the 6 ¹/₈% Senior Notes on or after June 15, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₈% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control triggering event, as defined in the indenture, we will be required to make an offer to repurchase the 6 ¹/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

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The 6 ¹/₈% Senior Notes are general unsecured senior obligations. They are jointly and severally guaranteed by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of a subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have outstanding any guarantee of any of our or any of our subsidiary guarantor’s indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. The 6 ¹/₈% 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 6 ¹/₈% Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility and the Plains Offshore senior 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, including indebtedness under the Plains Offshore senior credit facility, which we guarantee, and the shares of preferred stock issued by Plains Offshore.

Redemption of 7 ³/₄% Senior Notes and 7% Senior Notes.    During the second quarter of 2012, we redeemed the remaining $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes at 101.938% of the principal amount and the remaining $76.9 million aggregate principal amount of our 7% Senior Notes at 103.500% of the principal amount. We made payments totaling $80.8 million and $79.6 million to retire the 7 ³/₄% Senior Notes and the 7% Senior Notes, respectively. During the three and six months ended June 30, 2012, we recognized $5.2 million of debt extinguishment costs, including $0.9 million of unamortized debt issue costs in connection with the retirement of these Senior Notes.

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, put options, 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 and Plains Offshore’s senior credit facility is variable, while our senior notes are at fixed rates.

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

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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. Cash settlements with respect to derivatives that contain a significant financing element are reflected as financing activities in the statement of cash flows.

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

Under a swap contract, the counterparty is required to make a payment to us if the index price for any settlement period is less than the fixed price, and we are required to make a payment to the counterparty if the index price for any settlement period is greater than the fixed price. The amount we receive or pay is the difference between the index price and the fixed price multiplied by the contract volumes. If we have less production than the volumes specified under the swap transaction when the index price exceeds the fixed price, we must make payments against which there are no offsetting revenues from production.

During the three months ended June 30, 2012, we entered into Brent crude oil put option spread contracts on 30,000 BOPD for 2014 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $5.594 per barrel. Additionally, we entered into natural gas swap contracts on 80,000 MMBtu per day for 2012 with an average price of $2.72 per MMBtu.

See Note 5 – Fair Value Measurements of Assets and Liabilities, for additional discussion on the fair value measurement of our derivative contracts.

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As of June 30, 2012, 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
2012
Jul - Dec	Three-way collars (2)	40,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$120.00 Ceiling
2013
Jan - Dec	Put options (3)	17,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.253 per Bbl	Brent
Jan - Dec	Put options (3)	13,000 Bbls	$100.00 Floor with an $80.00 Limit	$6.800 per Bbl	Brent
Jan - Dec	Three-way collars (2)	25,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$124.29 Ceiling
Jan - Dec	Three-way collars (2)	5,000 Bbls	$90.00 Floor with a $70.00 Limit	-	Brent
			$126.08 Ceiling
2014
Jan - Dec	Put options (3)	50,000 Bbls	$90.00 Floor with a $70.00 Limit	$5.979 per Bbl	Brent
Sales of Natural Gas Production
2012
Jul - Dec	Put options (4)	120,000 MMBtu	$4.30 Floor with a $3.00 Limit	$0.298 per MMBtu	Henry Hub
Jul - Dec	Three-way collars (5)	40,000 MMBtu	$4.30 Floor with a $3.00 Limit	-	Henry Hub
			$4.86 Ceiling
Jul - Dec	Swap contracts (6)	80,000 MMBtu	$2.72	-	Henry Hub
2013
Jan - Dec	Swap contracts (6)	110,000 MMBtu	$4.27	-	Henry Hub
2014
Jan - Dec	Swap contracts (6)	100,000 MMBtu	$4.09	-	Henry Hub

(1) The average strike prices do not reflect any premiums to purchase the put options.

(2) If the index price is less than the per barrel floor, we receive the difference between the per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and the per barrel ceiling if the index price is greater than the per barrel ceiling. If the index price is at or above the per barrel floor but at or below the per barrel ceiling, no cash settlement is required.

(3) If the index price is less than the per barrel floor, we receive the difference between the 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 the per barrel floor, we pay only the option premium.

(4) If the index price is less than the per MMBtu floor, we receive the difference between the per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above the per MMBtu floor, we pay only the option premium.

(5) If the index price is less than the per MMBtu floor, we receive the difference between the per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and the per MMBtu ceiling if the index price is greater than the per MMBtu ceiling. If the index price is at or above the per MMBtu floor but at or below the per MMBtu ceiling, no cash settlement is required.

(6) If the index price is less than the fixed price, we receive the difference between the fixed price and the index price. We pay the difference between the index price and the fixed price if the index price is greater than the fixed price.

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Balance Sheet

At June 30, 2012 and December 31, 2011, we had the following outstanding commodity derivative contracts recorded in our balance sheet (in thousands):

		Estimated Fair Value
Instrument Type	Balance Sheet Classification	June 30, 2012		December 31, 2011
Crude oil puts	Commodity derivative contracts - current assets	$	31,756	$	-
Crude oil collars	Commodity derivative contracts - current assets		60,470		10,623
Natural gas puts	Commodity derivative contracts - current assets		23,906		41,335
Natural gas collars	Commodity derivative contracts - current assets		7,871		13,163
Natural gas swaps	Commodity derivative contracts - current assets		12,050		-
Crude oil puts	Commodity derivative contracts - non-current assets		157,159		48,306
Crude oil collars	Commodity derivative contracts - non-current assets		22,019		-
Natural gas swaps	Commodity derivative contracts - non-current assets		17,200		12,951
Total derivative instruments		$	332,431	$	126,378

The following table provides supplemental information to reconcile the fair value of our derivative contracts to our balance sheet at June 30, 2012 and December 31, 2011, considering the deferred premiums, accrued interest and related settlement payable/receivable amounts which are not included in the fair value amounts disclosed in the table above (in thousands):

	June 30, 2012		December 31, 2011
Net fair value asset	$	332,431	$	126,378
Deferred premium and accrued interest on derivative contracts		(184,001)		(62,430)
Settlement payable		-		(5,106)
Settlement receivable		5,005		216
Net commodity derivative asset	$	153,435	$	59,058
Commodity derivative contracts - current asset	$	99,458	$	50,964
Commodity derivative contracts - non-current asset		54,431		12,678
Commodity derivative contracts - current liability		-		(3,761)
Commodity derivative contracts - non-current liability		(454)		(823)
	$	153,435	$	59,058

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, 2012 and 2011, pre-tax amounts recognized in our income statements for derivative transactions were as follows (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Gain (loss) on mark-to-market derivative contracts	$	221,783	$	18,912	$	112,733	$	(32,084)

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Cash Payments and Receipts

During the six months ended June 30, 2012 and 2011, cash (payments) receipts for derivatives were as follows (in thousands):

	Six Months Ended June 30,
	2012		2011
Oil derivatives	$	(13,047)	$	(30,659)
Natural gas derivatives		30,909		620
	$	17,862	$	(30,039)

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 derivative contracts. As a result of the netting provisions under the agreements, our maximum amount of loss due to credit risk is limited to the net amounts due 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, 2012 was $155.0 million.

Contingent Features

As of June 30, 2012, the counterparties to our commodity derivative contracts consisted 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 cross-default and acceleration provisions relative to our material debt agreements. If we were to default on any of our material debt agreements, it would be a violation of these provisions, and the counterparties to our derivative agreements could request immediate payment on derivative instruments that are in a net liability position at that time. As of June 30, 2012, we were in a net asset position with all of the counterparties to our derivative instruments.

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Note 4 — Investment

At June 30, 2012 and 2011, we owned 51.0 million shares of McMoRan Exploration Co. common stock, approximately 31.6% and 32.2%, respectively, of its common shares outstanding. In December 2010, we acquired the McMoRan common stock and other consideration in exchange for all of our interests in our U.S. Gulf of Mexico leasehold located in less than 500 feet of water. We entered into a stockholder agreement with McMoRan requiring us to refrain from certain activities that could be undertaken to acquire control of McMoRan. We may sell shares of McMoRan common stock pursuant to underwritten offerings, in periodic sales under the shelf registration statement filed by McMoRan (subject to certain volume limitations), pursuant to the exercise of piggyback registration rights or as otherwise permitted by applicable law.

We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as a gain or loss on investment measured at fair value in our income statement. We believe that using fair value as a measurement basis for our investment is useful to our investors because our earnings on the investment will be dependent on the fair value on the date we divest the shares. At June 30, 2012, the McMoRan shares were valued at approximately $562.5 million, based on McMoRan’s closing stock price of $12.67 on June 30, 2012, discounted to reflect certain limitations on the marketability of the McMoRan shares. During the three months ended June 30, 2012 and 2011, we recorded unrealized gains of $86.8 million and $43.3 million, respectively, on our investment. During the six months ended June 30, 2012 and 2011, we recorded an unrealized loss of $49.2 million and an unrealized gain of $110.6 million, respectively, on our investment.

McMoRan follows the successful efforts method of accounting for its oil and natural gas activities. Under this method of accounting, all costs associated with oil and gas lease acquisition, successful exploratory wells and all development wells are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves on a field basis. Unproved leasehold costs are capitalized pending the results of exploration efforts. Exploration costs, including geological and geophysical expenses, exploratory dry holes and delay rentals, are charged to expense when incurred. Below is summarized financial information of our proportionate share of McMoRan’s results of operations (in thousands):

	Six Months Ended
	June 30,
	2012 (1)		2011
Results of Operations (2)
Revenues	$	63,498	$	95,090
Operating loss		(17,435)		(14,380)
Loss from continuing operations		(17,297)		(16,873)
Net loss applicable to common stock		(25,391)		(25,035)

(1) Amounts are based on McMoRan’s Form 8-K dated July 17, 2012.

(2) Amounts represent our 31.6% and 32.2% equity ownership in McMoRan as of June 30, 2012 and 2011, respectively.

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Note 5 — 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 and investment are recorded at fair value on a recurring basis in our balance sheet with the changes in fair value recorded in our income statement. The following table presents, for each fair value hierarchy level, our commodity derivative assets and liabilities and our investment measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011 (in thousands):

			Fair Value Measurements at Reporting Date Using
			Quoted Prices		Significant
			in Active		Other		Significant
			Markets for		Observable		Unobservable
			Identical Assets		Inputs		Inputs
	Fair Value		(Level 1)		(Level 2)		(Level 3)
June 30, 2012
Commodity derivative contracts (1)
Crude oil puts	$	188,915	$	-	$	68,342	$	120,573
Crude oil collars		82,488		-		-		82,488
Natural gas puts		23,906		-		-		23,906
Natural gas collars		7,871		-		-		7,871
Natural gas swaps		29,251		-		29,251		-
Investment (2)		562,491		-		-		562,491
	$	894,922	$	-	$	97,593	$	797,329
December 31, 2011
Commodity derivative contracts (1)
Crude oil puts	$	48,306	$	-	$	-	$	48,306
Crude oil collars		10,623		-		(669)		11,292
Natural gas puts		41,335		-		-		41,335
Natural gas collars		13,163		-		-		13,163
Natural gas swaps		12,951		-		12,951		-
Investment (2)		611,671		-		-		611,671
	$	738,049	$	-	$	12,282	$	725,767

(1) Option premium and accrued interest of $184.0 million and $62.4 million at June 30, 2012 and December 31, 2011, respectively, settlement payable of $5.1 million at December 31, 2011 and settlement receivable of $5.0 million and $0.2 million at June 30, 2012 and December 31, 2011, respectively, are not included in the fair value of derivatives.

(2) Represents our equity investment in McMoRan which would otherwise be reported under the equity method of accounting.

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The fair value amounts of our put and collar derivative instruments are estimated using an option-pricing model, which uses various inputs including NYMEX and ICE price quotations, volatilities, interest rates and contract terms. The fair value of our swap derivative instruments are estimated using a pricing model which has various inputs including NYMEX price quotations, interest rates and contract terms. We adjust the valuations 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.

We classify derivatives that have identical assets or liabilities with quoted, unadjusted prices in active markets as Level 1. We classify 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 and/or interpolate data between data points for thinly traded instruments. As of June 30, 2012, our 2012, 2013 and 2014 natural gas swaps and 2013 crude oil puts are classified as Level 2 and our 2012 natural gas puts and collars, 2012 and 2013 crude oil collars and 2014 crude oil puts are classified as Level 3 instruments.

We determine the fair value of our investment by discounting for lack of marketability at the reporting date. The discount factor for lack of marketability is determined by utilizing both Protective put and Asian put option models. Both of these options are valued using a Black-Scholes option-pricing model which utilizes various inputs including the closing price of the McMoRan common stock, implied volatility of the instrument, number of shares being valued, length of time that would be necessary to dispose of our investment, expected dividend and risk-free interest rates. As of June 30, 2012, we have classified our investment as Level 3 since the fair value is determined by utilizing significant inputs that are unobservable.

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.

We adopted the guidance amending certain accounting and disclosure requirements related to fair value measurements on January 1, 2012. The guidance clarifies (i) the requirement that the highest and best use concept is only relevant for measuring nonfinancial assets, (ii) requirements to measure the fair value of instruments classified in shareholders’ equity and (iii) the requirement to disclose quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy. The guidance also (i) permits a reporting entity to measure the fair value of certain financial assets and liabilities managed in a portfolio at the price that would be received to sell a net asset position or transfer a net liability position for a particular risk, (ii) eliminates premiums or discounts related to size as a characteristic of the reporting entity’s holding and (iii) expands disclosures for fair value measurement. The provisions of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.

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The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts and our investment measured at fair value as of June 30, 2012 (in thousands):

	Quantitative Information About Level 3 Fair Value Measurements
	Fair Value		Valuation Technique	Unobservable Input	Range (Weighted Average)
June 30, 2012
Commodity derivative contracts (1)
Crude oil puts	$	120,573	Option pricing model	Implied volatility	26% - 34% (30%)
Crude oil collars		82,488	Option pricing model	Implied volatility	25% - 49% (32%)
Natural gas puts		23,906	Option pricing model	Implied volatility	40% - 57% (51%)
Natural gas collars		7,871	Option pricing model	Implied volatility	40% - 57% (51%)
Investment (2)		562,491	Option pricing model	Discount for lack	10% - 16% (13%)
				of marketability

(1) Represents the range of implied volatility associated with the forward commodity prices used in the valuation of our derivative contracts. We have determined that a market participant would use a similar volatility curve when pricing similar commodity derivative contracts.

(2) Represents the range of discount for lack of marketability associated with our investment in the common stock of McMoRan. The discount for lack of marketability is derived by an analysis of publicly traded option contracts of McMoRan common stock as of the valuation date. We have determined that a market participant would use a similar valuation methodology when pricing an investment with similar terms.

The significant unobservable inputs used in the fair value measurement of our commodity derivative contracts are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement.

Implied volatility associated with the common stock of McMoRan is a significant unobservable input used in the determination of the discount for lack of marketability of our investment measured at fair value. Significant increases (decreases) in volatility in isolation would result in a significantly higher (lower) discount factor for lack of marketability. Additionally, another significant unobservable input, the expected term of our investment, impacts the discount factor for lack of marketability. Significant increases (decreases) in the expected term in isolation would result in a significantly higher (lower) discount factor for lack of marketability. A higher discount factor would result in a lower fair value measurement of our investment.

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The following table presents a reconciliation of changes in fair value of our financial assets and liabilities classified as Level 3 for the six months ended June 30, 2012 and 2011 (in thousands):

	Six Months Ended June 30,
	2012				2011
	Commodity Derivatives (1)		Investment		Commodity Derivatives (1)		Investment
Fair value at beginning of period	$	114,096	$	611,671	$	4,785	$	664,346
Transfers into Level 3 (2)		(668)		-		-		-
Transfers out of Level 3 (3)		(48,306)		-		-		-
Realized and unrealized gains and losses included in earnings (4)		97,339		(49,180)		7,872		110,561
Purchases		106,477		-		-		-
Settlements		(34,100)		-		(620)		-
Fair value at end of period	$	234,838	$	562,491	$	12,037	$	774,907
Change in unrealized gains and losses relating to assets and liabilities held as of the end of the period (4)	$	101,799	$	(49,180)	$	6,563	$	110,561

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

(2) During the six months ended June 30, 2012, the inputs used to value certain of our 2012 crude oil collars were significantly unobservable and those contracts were transferred from Level 2 to Level 3.

(3) During the six months ended June 30, 2012, the inputs used to value certain of our 2013 crude oil puts were directly or indirectly observable and those contracts were transferred from Level 3 to Level 2.

(4) Realized and unrealized gains and losses included in earnings for the period are reported as gain (loss) on mark-to-market derivative contracts and gain (loss) on investment measured at fair value in our income statement for our commodity derivative contracts and our investment, respectively.

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 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 balance sheet are stated at fair value; however, certain of our derivative financial instruments have a deferred premium, including our crude oil and natural gas put options. The deferred premium reduces the asset or increases the liability depending on the fair value of the derivative financial instrument.

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The following table presents the carrying amounts and fair values of our other financial instruments as of June 30, 2012 and December 31, 2011 (in thousands):

	June 30, 2012				December 31, 2011
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Current Asset (1)
Cash and cash equivalents	$	302,157	$	302,157	$	419,098	$	419,098
Current Liability (2)
Deferred premium and accrued interest on derivative contracts		41,600		41,600		13,029		13,029
Non-Current Liability (2)
Deferred premium and accrued interest on derivative contracts		142,401		142,401		49,401		49,401
Long-Term Debt (3)
Senior revolving credit facility		298,000		298,000		735,000		735,000
Plains Offshore senior credit facility		-		-		-		-
7 3/4% Senior Notes		-		-		79,281		81,858
10% Senior Notes		176,299		192,166		175,385		194,239
7% Senior Notes		-		-		76,901		79,593
7 5/8% Senior Notes		400,000		425,000		400,000		424,000
6 1/8% Senior Notes		750,000		753,750		-		-
8 5/8% Senior Notes		394,641		435,585		394,385		433,331
7 5/8% Senior Notes		300,000		316,500		300,000		324,750
6 5/8% Senior Notes		600,000		606,000		600,000		630,000
6 3/4% Senior Notes		1,000,000		1,020,000		1,000,000		1,047,500

(1) Our cash and cash equivalents consist primarily of money market mutual funds and would have been classified as Level 1 under the fair value hierarchy.

(2) If our deferred premium and accrued interest payable on our commodity derivative contracts had been measured at fair value, it would have been classified as Level 3 under the fair value hierarchy.

(3) The carrying value of our senior revolving credit facility approximates its fair value, as interest rates are variable, based on prevailing market rates. Our senior revolving credit facility would have been classified as Level 1 under the fair value hierarchy. If our senior notes had been measured at fair value, we would have classified them as Level 1 under the fair value hierarchy as the inputs utilized for the measurement would be quoted, unadjusted prices from over-the-counter markets for debt instruments.

Note 6 — Divestment

During the first quarter of 2012, we completed the divestment of our interests in approximately 2,000 gross leasehold acres in our Texas Panhandle properties. After the exercise of third party preferential rights and preliminary closing adjustments, we received approximately $43.4 million in cash. The transactions were effective November 1, 2011. The proceeds were recorded as a reduction to capitalized costs pursuant to full cost accounting rules.

At June 30, 2012, we continue to have interests in approximately 40,000 gross leasehold acres in the Texas Panhandle. We expect to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments.

21

Note 7 — Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items which are recorded in the period that the specific item occurs. For the three and six months ended June 30, 2012, our income tax expense was approximately 40% and 41% of the pre-tax income, respectively.

The variance in our estimated annual effective tax rate from the 35% federal statutory rate for both periods include the tax effects of estimated annual permanent differences, including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.

Note 8 — Commitments, Contingencies and Industry Concentration

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.

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, $85.1 million ($145.2 million undiscounted), is included in our asset retirement obligation as reflected on our 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 $84.3 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At June 30, 2012, the escrow account had a balance of $20.9 million. The fair value of our guarantee at June 30, 2012, $0.3 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in our balance sheet.

22

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. We are self-insured for named windstorms in the U.S. Gulf of Mexico. 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. 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.

Industry Concentration

Effective May 1, 2012, Phillips 66 was spun off from ConocoPhillips at which time we consented to the assignment of our Crude Oil Purchase Agreement from ConocoPhillips to Phillips 66. During 2011, sales to ConocoPhillips accounted for 41% of our total revenues.

23

Note 9 — Consolidating Financial Statements

We are the issuer of $565 million 10% Senior Notes, of which $184.9 million aggregate principal amount remains outstanding, $400 million 7 ⁵/₈% Senior Notes due 2018, $750 million 6 ¹/₈% Senior Notes, $400 million 8 ⁵/₈% Senior Notes, $300 million 7 ⁵/₈% Senior Notes due 2020, $600 million 6 ⁵/₈% Senior Notes and $1 billion 6 ³/₄% Senior Notes as of June 30, 2012, which are jointly and severally guaranteed by certain of our existing domestic subsidiaries (referred to as “Guarantor Subsidiaries”). In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of a subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have outstanding any guarantee of any of our or any of our subsidiary guarantor’s indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. Certain of our subsidiaries do not guarantee the Senior Notes (referred to as “Non-Guarantor Subsidiaries”).

Plains Offshore.     In October 2011, we entered into a securities purchase agreement with EIG Global Energy Partners for a 20% equity interest in Plains Offshore. As a result, the associated properties were transferred from PXP, which is reported as Issuer, to Plains Offshore, which is reported as a Non-Guarantor Subsidiary. We have retrospectively adjusted the Issuer, Non-Guarantor Subsidiaries and Intercompany Eliminations columns of the consolidating statements of income for the three and six months ended June 30, 2011 and cash flows for the six months ended June 30, 2011 to reflect the transfer of these deepwater assets.

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.

24

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

JUNE 30, 2012

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	-	$	-	$	302,157	$	-	$	302,157
Accounts receivable and other current assets		963,567		66,563		2,550		-		1,032,680
		963,567		66,563		304,707		-		1,334,837
Property and Equipment, at cost
Oil and natural gas properties - full cost method		5,040,534		8,904,391		1,335,772		-		15,280,697
Other property and equipment		57,136		42,749		52,500		-		152,385
		5,097,670		8,947,140		1,388,272		-		15,433,082
Less allowance for depreciation, depletion, amortization and impairment		(2,497,360)		(7,553,165)		(999,711)		3,839,764		(7,210,472)
		2,600,310		1,393,975		388,561		3,839,764		8,222,610
Investment in and Advances to Affiliates		4,420,679		(1,286,634)		(75,979)		(3,058,066)		-
Other Assets		117,901		551,125		4,962		-		673,988
	$	8,102,457	$	725,029	$	622,251	$	781,698	$	10,231,435
LIABILITIES AND EQUITY
Current Liabilities	$	554,589	$	65,533	$	70,786	$	-	$	690,908
Long-Term Debt		3,918,940		-		-		-		3,918,940
Other Long-Term Liabilities		219,482		35,835		826		-		256,143
Deferred Income Taxes		81,124		80,875		29,943		1,409,992		1,601,934
Equity
Stockholders’ equity		3,328,322		542,786		85,508		(628,294)		3,328,322
Noncontrolling interest Preferred stock of subsidiary		-		-		435,188		-		435,188
		3,328,322		542,786		520,696		(628,294)		3,763,510
	$	8,102,457	$	725,029	$	622,251	$	781,698	$	10,231,435

25

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2011

(in thousands of dollars)

					Non-
			Guarantor		Guarantor		Intercompany
	Issuer		Subsidiaries		Subsidiaries		Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	3,189	$	6	$	415,903	$	-	$	419,098
Accounts receivable and other current assets		885,860		136,642		444		(667)		1,022,279
		889,049		136,648		416,347		(667)		1,441,377
Property and Equipment, at cost
Oil and natural gas properties - full cost method		4,301,524		8,841,469		1,282,708		-		14,425,701
Other property and equipment		52,906		42,747		50,306		-		145,959
		4,354,430		8,884,216		1,333,014		-		14,571,660
Less allowance for depreciation, depletion, amortization and impairment		(2,327,063)		(6,392,068)		(1,059,186)		2,931,952		(6,846,365)
		2,027,367		2,492,148		273,828		2,931,952		7,725,295
Investment in and Advances to Affiliates		4,583,550		(1,282,085)		(73,079)		(3,228,386)		-
Other Assets		73,832		548,615		2,353		-		624,800
	$	7,573,798	$	1,895,326	$	619,449	$	(297,101)	$	9,791,472
LIABILITIES AND EQUITY
Current Liabilities	$	443,098	$	135,681	$	48,074	$	(667)	$	626,186
Long-Term Debt		3,760,952		-		-		-		3,760,952
Other Long-Term Liabilities		211,106		35,296		803		-		247,205
Deferred Income Taxes		(105,994)		437,367		31,757		1,098,767		1,461,897
Equity
Stockholders’ equity		3,264,636		1,286,982		108,219		(1,395,201)		3,264,636
Noncontrolling interest Preferred stock of subsidiary		-		-		430,596		-		430,596
		3,264,636		1,286,982		538,815		(1,395,201)		3,695,232
	$	7,573,798	$	1,895,326	$	619,449	$	(297,101)	$	9,791,472

26

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2012

(in thousands of dollars)

			Guarantor		Non- Guarantor		Intercompany
	Issuer		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Revenues
Oil sales	$	491,594	$	27,914	$	-	$	-	$	519,508
Gas sales		6,977		38,982		-		-		45,959
Other operating revenues		177		1,080		-		-		1,257
		498,748		67,976		-		-		566,724
Costs and Expenses
Production costs		108,854		37,188		222		-		146,264
General and administrative		23,306		6,470		1,925		-		31,701
Depreciation, depletion, amortization and accretion		105,917		35,528		135		112,900		254,480
Impairment of oil and gas properties		-		198,139		-		(198,139)		-
Other operating expense (income)		1,001		(2,277)		-		-		(1,276)
		239,078		275,048		2,282		(85,239)		431,169
Income (Loss) from Operations		259,670		(207,072)		(2,282)		85,239		135,555
Other (Expense) Income
Equity in earnings of subsidiaries		(121,031)		-		-		121,031		-
Interest expense		(8)		(51,597)		(1,372)		-		(52,977)
Debt extinguishment costs		(5,167)		-		-		-		(5,167)
Gain on mark-to-market derivative contracts		221,783		-		-		-		221,783
Gain on investment measured at fair value		86,750		-		-		-		86,750
Other income		657		163		14		-		834
Income (Loss) Before Income Taxes		442,654		(258,506)		(3,640)		206,270		386,778
Income tax (expense) benefit		(219,455)		97,274		1,296		(33,618)		(154,503)
Net Income (Loss)		223,199		(161,232)		(2,344)		172,652		232,275
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		-		-		(9,076)		-		(9,076)
Net Income (Loss) Attributable to Common Stockholders	$	223,199	$	(161,232)	$	(11,420)	$	172,652	$	223,199

27

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2011

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	327,501	$	70,883	$	922	$	-	$	399,306
Gas sales		2,621		111,049		-		-		113,670
Other operating revenues		269		1,540		-		-		1,809
		330,391		183,472		922		-		514,785
Costs and Expenses
Production costs		90,391		52,748		-		-		143,139
General and administrative		18,860		11,663		260		-		30,783
Depreciation, depletion, amortization and accretion		46,436		66,911		103		41,621		155,071
Impairment of oil and gas properties		-		143,173		462,596		(605,769)		-
Other operating income		-		(303)		-		-		(303)
		155,687		274,192		462,959		(564,148)		328,690
Income (Loss) from Operations		174,704		(90,720)		(462,037)		564,148		186,095
Other (Expense) Income
Equity in earnings of subsidiaries		(19,628)		4		-		19,624		-
Interest expense		(393)		(36,159)		(690)		-		(37,242)
Gain on mark-to-market derivative contracts		18,912		-		-		-		18,912
Gain on investment measured at fair value		43,307		-		-		-		43,307
Other income		225		760		11		-		996
Income (Loss) Before Income Taxes		217,127		(126,115)		(462,716)		583,772		212,068
Income tax (expense) benefit		(92,235)		46,438		162,083		(203,462)		(87,176)
Net Income (Loss)	$	124,892	$	(79,677)	$	(300,633)	$	380,310	$	124,892

28

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2012

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	927,957	$	59,039	$	-	$	-	$	986,996
Gas sales		12,354		87,129		-		-		99,483
Other operating revenues		690		3,830		-		-		4,520
		941,001		149,998		-		-		1,090,999
Costs and Expenses
Production costs		208,783		71,455		433		-		280,671
General and administrative		49,102		17,063		3,918		-		70,083
Depreciation, depletion, amortization and accretion		181,949		79,751		268		173,962		435,930
Impairment of oil and gas properties		-		1,081,774		-		(1,081,774)		-
Other operating expense (income)		1,001		(3,538)		-		-		(2,537)
		440,835		1,246,505		4,619		(907,812)		784,147
Income (Loss) from Operations		500,166		(1,096,507)		(4,619)		907,812		306,852
Other (Expense) Income
Equity in earnings of subsidiaries		(201,100)		-		-		201,100		-
Interest expense		(33)		(95,618)		(2,579)		-		(98,230)
Debt extinguishment costs		(5,167)		-		-		-		(5,167)
Gain on mark-to-market derivative contracts		112,733		-		-		-		112,733
Loss on investment measured at fair value		(49,180)		-		-		-		(49,180)
Other income		107		296		26		-		429
Income (Loss) Before Income Taxes		357,526		(1,191,829)		(7,172)		1,108,912		267,437
Income tax (expense) benefit		(216,646)		447,633		2,554		(342,006)		(108,465)
Net Income (Loss)		140,880		(744,196)		(4,618)		766,906		158,972
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		-		-		(18,092)		-		(18,092)
Net Income (Loss) Attributable to Common Stockholders	$	140,880	$	(744,196)	$	(22,710)	$	766,906	$	140,880

29

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2011

(in thousands of dollars)

			Guarantor		Non- Guarantor		Intercompany
	Issuer		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Revenues
Oil sales	$	604,895	$	125,332	$	922	$	-	$	731,149
Gas sales		5,990		204,482		-		-		210,472
Other operating revenues		505		2,973		-		-		3,478
		611,390		332,787		922		-		945,099
Costs and Expenses
Production costs		168,736		96,410		-		-		265,146
General and administrative		41,377		24,790		639		-		66,806
Depreciation, depletion, amortization and accretion		89,631		125,229		146		78,865		293,871
Impairment of oil and gas properties		-		313,167		475,990		(789,157)		-
Other operating income		-		(607)		-		-		(607)
		299,744		558,989		476,775		(710,292)		625,216
Income (Loss) from Operations		311,646		(226,202)		(475,853)		710,292		319,883
Other (Expense) Income
Equity in earnings of subsidiaries		(40,290)		(4)		-		40,294		-
Interest expense		(957)		(67,229)		(1,460)		-		(69,646)
Loss on mark-to-market derivative contracts		(32,084)		-		-		-		(32,084)
Gain on investment measured at fair value		110,561		-		-		-		110,561
Other income (expense)		695		956		(101)		-		1,550
Income (Loss) Before Income Taxes		349,571		(292,479)		(477,414)		750,586		330,264
Income tax (expense) benefit		(153,700)		108,434		167,140		(256,267)		(134,393)
Net Income (Loss)	$	195,871	$	(184,045)	$	(310,274)	$	494,319	$	195,871

30

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2012

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	140,880		$	(744,196	)	$	(4,618	)	$	766,906		$	158,972
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		181,949			1,161,525			268			(907,812	)		435,930
Equity in earnings of subsidiaries		201,100			-			-			(201,100	)		-
Deferred income tax expense (benefit)		154,547			(356,498	)		(1,814	)		311,225			107,460
Debt extinguishment costs		939			-			-			-			939
Gain on mark-to-market derivative contracts		(112,733	)		-			-			-			(112,733	)
Loss on investment measured at fair value		49,180			-			-			-			49,180
Non-cash compensation		21,485			4,744			-			-			26,229
Other non-cash items		2,542			518			-			-			3,060
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(49,731	)		67,981			(4,960	)		-			13,290
Accounts payable and other liabilities		(26,166	)		(18,699	)		(15,141	)		-			(60,006	)
Income taxes receivable/payable		8,635			-			-			-			8,635
Net cash provided by (used in) operating activities		572,627			115,375			(26,265	)		(30,781	)		630,956
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(606,657	)		(155,717	)		(61,906	)		-			(824,280	)
Acquisition of oil and gas properties		(7,361	)		-			(12,780	)		-			(20,141	)
Proceeds from sales of oil and gas properties, net of costs and expenses		42,842			-			-			-			42,842
Derivative settlements		17,862			-			-			-			17,862
Additions to other property and equipment		(4,230	)		(1	)		(2,195	)		-			(6,426	)
Net cash used in investing activities		(557,544	)		(155,718	)		(76,881	)		-			(790,143	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		4,334,675			-			-			-			4,334,675
Repayments of revolving credit facilities		(4,771,675	)		-			-			-			(4,771,675	)
Principal payments of long-term debt		(156,182	)		-			-			-			(156,182	)
Proceeds from issuance of Senior Notes		750,000			-			-			-			750,000
Costs incurred in connection with financing arrangements		(12,582	)		-			-			-			(12,582	)
Purchase of treasury stock		(88,490	)		-			-			-			(88,490	)
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-			-			(13,500	)		-			(13,500	)
Investment in and advances to affiliates		(74,018	)		40,337			2,900			30,781			-
Net cash (used in) provided by financing activities		(18,272	)		40,337			(10,600	)		30,781			42,246
Net decrease in cash and cash equivalents		(3,189	)		(6	)		(113,746	)		-			(116,941	)
Cash and cash equivalents, beginning of period		3,189			6			415,903			-			419,098
Cash and cash equivalents, end of period	$	-		$	-		$	302,157		$	-		$	302,157

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2011

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	195,871		$	(184,045	)	$	(310,274	)	$	494,319		$	195,871
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		89,631			438,396			476,136			(710,292	)		293,871
Equity in earnings of subsidiaries		40,290			4			-			(40,294	)		-
Deferred income tax (benefit) expense		(24,508	)		(44,787	)		(124,961	)		327,890			133,634
Loss on mark-to-market derivative contracts		32,084			-			-			-			32,084
Gain on investment measured at fair value		(110,561	)		-			-			-			(110,561	)
Non-cash compensation		20,771			7,260			-			-			28,031
Other non-cash items		608			(977	)		67			-			(302	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		10,743			(33,567	)		1,354			-			(21,470	)
Accounts payable and other liabilities		(26,669	)		12,265			301			-			(14,103	)
Income taxes receivable/payable		40,370			-			-			-			40,370
Net cash provided by operating activities		268,630			194,549			42,623			71,623			577,425
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(329,365	)		(403,651	)		(67,154	)		-			(800,170	)
Acquisition of oil and gas properties		(7,086	)		(25,370	)		-			-			(32,456	)
Proceeds from sales of oil and gas properties, net of costs and expenses		11,987			-			-			-			11,987
Derivative settlements		(30,039	)		-			-			-			(30,039	)
Additions to other property and equipment		(4,021	)		(443	)		(2,070	)		-			(6,534	)
Net cash used in investing activities		(358,524	)		(429,464	)		(69,224	)		-			(857,212	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		2,679,200			-			-			-			2,679,200
Repayments of revolving credit facilities		(2,989,200	)		-			-			-			(2,989,200	)
Proceeds from issuance of Senior Notes		600,000			-			-			-			600,000
Costs incurred in connection with financing arrangements		(11,320	)		-			-			-			(11,320	)
Investment in and advances to affiliates		(190,011	)		234,914			26,720			(71,623	)		-
Other		4			-			-			-			4
Net cash provided by financing activities		88,673			234,914			26,720			(71,623	)		278,684
Net (decrease) increase in cash and cash equivalents		(1,221	)		(1	)		119			-			(1,103	)
Cash and cash equivalents, beginning of period		6,020			8			406			-			6,434
Cash and cash equivalents, end of period	$	4,799		$	7		$	525		$	-		$	5,331

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

The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report and our Form 10-K for the year ended December 31, 2011.

Company Overview

We are an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are located 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; 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 risk management program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities, including our California, Eagle Ford Shale, Haynesville Shale and Gulf of Mexico plays. 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 assets include 51.0 million shares of McMoRan common stock, approximately 31.6% of its common shares outstanding. We measure our equity investment at fair value. Unrealized gains and losses on the investment are reported in our income statement and could result in volatility in our earnings. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk – Equity Price Risk.

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 various derivative instruments to manage our exposure to 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 income statement as changes occur in the NYMEX and ICE 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 – Commodity Price Risk.

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Recent Developments

Debt Offering and Redemptions

In April 2012, we issued $750 million of 6 ¹/₈% Senior Notes at par. We received approximately $737.5 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, including the redemption of $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes and $76.9 million aggregate principal amount of our 7% Senior Notes.

During the second quarter of 2012, we made payments totaling $80.8 million and $79.6 million to retire the 7 ³/₄% Senior Notes and the 7% Senior Notes, respectively. In connection with the retirement of the 7 ³/₄% Senior Notes and the 7% Senior Notes, we recorded $5.2 million of debt extinguishment costs.

Derivatives

During the second quarter of 2012, we entered into Brent crude oil put option spread contracts on 30,000 BOPD for 2014 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $5.594 per barrel. Additionally, we entered into natural gas swap contracts on 80,000 MMBtu per day for 2012 with an average price of $2.72 per MMBtu.

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. The markets for oil and gas have historically 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. 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, 2012, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 28%.

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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. As of July 2012, the twelve-month average of the first-day-of-the-month reference price for natural gas declined from $3.15 per MMBtu at June 30, 2012 to $3.02 per MMBtu and the comparable price for oil declined from $95.67 per Bbl at June 30, 2012 to $94.84 per Bbl.

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, gathering and transportation costs and other costs necessary to operate our producing properties. 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.

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

Results Overview

For the six months ended June 30, 2012, we reported net income attributable to common stockholders of $140.9 million, or $1.07 per diluted share, compared to net income of $195.9 million, or $1.37 per diluted share, for the six months ended June 30, 2011. The decrease primarily reflects a loss on our investment in McMoRan measured at fair value, increased DD&A and lower gas revenues partially offset by higher oil revenues and a gain on mark-to-market derivative contracts. Significant transactions that affect comparisons between the periods include the divestment of our Panhandle and South Texas properties in the fourth quarter of 2011.

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Results of Operations

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
Sales Volumes
Oil and liquids sales (MBbls)		5,440		4,416		9,959		8,382
Gas (MMcf)
Production		21,398		27,405		42,692		51,635
Used as fuel		346		534		774		1,055
Sales		21,052		26,871		41,918		50,580
MBOE
Production		9,006		8,984		17,074		16,988
Sales		8,949		8,894		16,945		16,812
Daily Average Volumes
Oil and liquids sales (Bbls)		59,780		48,524		54,718		46,308
Gas (Mcf)
Production		235,142		301,162		234,572		285,280
Used as fuel		3,804		5,874		4,255		5,831
Sales		231,338		295,288		230,317		279,449
BOE
Production		98,970		98,718		93,814		93,855
Sales		98,336		97,739		93,105		92,883
Unit Economics (in dollars)
Average Index Prices
ICE Brent Price per Bbl	$	108.73	$	116.89	$	113.57	$	111.20
NYMEX Price per Bbl		93.35		102.34		98.15		98.50
NYMEX Price per Mcf		2.22		4.32		2.47		4.20
Average Realized Sales Price
Before Derivative Transactions
Oil (per Bbl)	$	95.50	$	90.42	$	99.11	$	87.23
Gas (per Mcf)		2.18		4.23		2.37		4.16
Per BOE		63.19		57.68		64.12		56.01
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	9.80	$	9.23	$	10.07	$	9.19
Steam gas costs		1.09		1.90		1.23		1.94
Electricity		1.20		1.17		1.31		1.20
Production and ad valorem taxes		2.13		1.90		1.87		1.69
Gathering and transportation		2.13		1.89		2.08		1.76
DD&A (oil and gas properties)		27.21		16.28		24.58		16.28

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
Oil derivatives	$	(7,191)	$	(15,018)	$	(13,047)	$	(30,659)
Natural gas derivatives		15,732		-		30,909		620
	$	8,541	$	(15,018)	$	17,862	$	(30,039)

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Comparison of Three Months Ended June 30, 2012 to Three Months Ended June 30, 2011

Oil and gas revenues.     Oil and gas revenues increased $52.5 million, to $565.5 million for 2012 from $513.0 million for 2011, primarily due to higher oil sales volumes and average realized oil prices partially offset by lower average realized gas prices and gas sales volumes.

Oil revenues increased $120.2 million, to $519.5 million for 2012 from $399.3 million for 2011, reflecting higher sales volumes ($97.8 million) and higher average realized prices ($22.4 million). Oil sales volumes increased 11.3 MBbls per day to 59.8 MBbls per day in 2012 from 48.5 MBbls per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestments, sales increased 17.2 MBbls per day in 2012. Our average realized price for oil increased $5.08 per Bbl to $95.50 per Bbl for 2012 from $90.42 per Bbl for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012 for our California crude oil production that replaces the percent of NYMEX index pricing with a market based pricing approach. The average ICE Brent index price for 2012 was $108.73 per Bbl compared to the average NYMEX index price of $102.34 per Bbl for 2011.

Gas revenues decreased $67.7 million, to $46.0 million in 2012 from $113.7 million in 2011, primarily reflecting lower average realized prices ($55.0 million) and lower sales volumes ($12.7 million). Our average realized price for gas was $2.18 per Mcf in 2012 compared to $4.23 per Mcf in 2011. Gas sales volumes decreased 64.0 MMcf per day to 231.3 MMcf per day in 2012 from 295.3 MMcf per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestments, sales increased 17.8 MMcf per day in 2012.

Lease operating expenses.     Lease operating expenses increased $5.6 million, to $87.7 million in 2012 from $82.1 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties and repairs and maintenance primarily at our California properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs.     Steam gas costs decreased $7.2 million, to $9.7 million in 2012 from $16.9 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 4.0 Bcf of natural gas at a cost of approximately $2.41 per MMBtu compared to 4.1 Bcf at a cost of approximately $4.13 per MMBtu in 2011.

Production and ad valorem taxes.     Production and ad valorem taxes increased $2.2 million, to $19.1 million in 2012 from $16.9 million in 2011, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Gathering and transportation expense.     Gathering and transportation expenses increased $2.2 million, to $19.0 million in 2012 from $16.8 million in 2011, primarily reflecting an increase in production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

37

Depreciation, depletion and amortization.     DD&A expense increased $99.9 million, to $250.7 million in 2012 from $150.8 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($98.2 million). Our oil and gas unit of production rate increased to $27.21 per BOE in 2012 compared to $16.28 per BOE in 2011.

The increased DD&A rate is primarily due to the prolonged decrease in natural gas prices as some of our proved undeveloped reserves are no longer expected to be developed in the next five years. Additionally, the increase is due to impairment and transfer of certain unproved properties to cost subject to amortization.

Interest expense.     Interest expense increased $15.8 million, to $53.0 million in 2012 from $37.2 million in 2011, primarily due to a decrease in interest capitalized and greater average debt outstanding partially offset by lower average interest rates. 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 $15.2 million and $33.5 million of interest in 2012 and 2011, respectively. The decreased capitalized interest is primarily attributable to a lower unevaluated oil and gas property balance in 2012.

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 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 $221.8 million gain related to mark-to-market derivative contracts in the second quarter of 2012, which was primarily associated with an increase in the fair value of our crude oil derivative contracts due to decreased forward prices. In the second quarter of 2011, we recognized a $18.9 million gain related to mark-to-market derivative contracts.

Gain (loss) on investment measured at fair value.     At June 30, 2012, we owned 51.0 million shares of McMoRan common stock. We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as gain on investment measured at fair value in our income statement.

We recognized an $86.8 million gain in the second quarter of 2012 related to our McMoRan investment, which was primarily associated with an increase in McMoRan’s stock price. In the second quarter of 2011, we recognized a $43.3 million gain related to our McMoRan investment.

Income taxes.     For the three months ended June 30, 2012 and 2011, our income tax expense was approximately 40% and 41% of pre-tax income, respectively. The variance between these effective tax rates and the 35% federal statutory rate results from the tax effects of estimated annual permanent differences, including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.

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Comparison of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2011

Oil and gas revenues.     Oil and gas revenues increased $144.9 million, to $1.1 billion for 2012 from $941.6 million for 2011, primarily due to higher oil sales volumes and average realized oil prices partially offset by lower average realized gas prices and gas sales volumes.

Oil revenues increased $255.9 million, to $987.0 million for 2012 from $731.1 million for 2011, reflecting higher sales volumes ($156.3 million) and higher average realized prices ($99.6 million). Oil sales volumes increased 8.4 MBbls per day to 54.7 MBbls per day in 2012 from 46.3 MBbls per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestments, sales increased 13.4 MBbls per day in 2012. Our average realized price for oil increased $11.88 per Bbl to $99.11 per Bbl for 2012 from $87.23 per Bbl for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012 for our California crude oil production that replaces the percent of NYMEX index pricing with a market based pricing approach. The average ICE Brent index price for 2012 was $113.57 per Bbl compared to the average NYMEX index price of $98.50 per Bbl for 2011.

Gas revenues decreased $111.0 million, to $99.5 million in 2012 from $210.5 million in 2011, primarily reflecting lower average realized prices ($90.4 million) and lower sales volumes ($20.6 million). Our average realized price for gas was $2.37 per Mcf in 2012 compared to $4.16 per Mcf in 2011. Gas sales volumes decreased 49.1 MMcf per day to 230.3 MMcf per day in 2012 from 279.4 MMcf per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestments, sales increased 23.1 MMcf per day in 2012.

Lease operating expenses.     Lease operating expenses increased $16.3 million, to $170.7 million in 2012 from $154.4 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties and higher well workovers and repairs and maintenance primarily at our California properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs.     Steam gas costs decreased $11.8 million, to $20.8 million in 2012 from $32.6 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 8.0 Bcf of natural gas at a cost of approximately $2.59 per MMBtu compared to 8.1 Bcf at a cost of approximately $4.01 per MMBtu in 2011.

Production and ad valorem taxes.     Production and ad valorem taxes increased $3.3 million, to $31.7 million in 2012 from $28.4 million in 2011, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Gathering and transportation expenses.     Gathering and transportation expenses increased $5.7 million, to $35.3 million in 2012 from $29.6 million in 2011, primarily reflecting an increase in production from our Eagle Ford Shale properties and increased rates at our Haynesville Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

39

Depreciation, depletion and amortization.     DD&A expense increased $143.1 million, to $428.4 million in 2012 from $285.3 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($141.0 million). Our oil and gas unit of production rate was $24.58 per BOE in 2012 compared to $16.28 per BOE in 2011.

The increased DD&A rate is primarily due to the prolonged decrease in natural gas prices as some of our proved undeveloped reserves are no longer expected to be developed in the next five years. Additionally, the increase is due to impairment and transfer of certain unproved properties to cost subject to amortization.

Interest expense.     Interest expense increased $28.6 million, to $98.2 million in 2012 from $69.6 million in 2011, primarily due to a decrease in interest capitalized and greater average debt outstanding partially offset by lower average interest rates. 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 $32.3 million and $64.6 million of interest in 2012 and 2011, respectively. The decreased capitalized interest is primarily attributable to a lower unevaluated oil and gas property balance in 2012.

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 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 $112.7 million gain related to mark-to-market derivative contracts in the six months ended June 30, 2012, which was primarily associated with an increase in the fair value of our crude oil and natural gas derivative contracts due to decreased forward prices. In the six months ended June 30, 2011, we recognized a $32.1 million loss related to mark-to-market derivative contracts.

Gain (loss) on investment measured at fair value.     At June 30, 2012, we owned 51.0 million shares of McMoRan common stock. We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as a gain or loss on investment measured at fair value in our income statement.

We recognized a $49.2 million loss in the six months ended June 30, 2012 related to our McMoRan investment, which was primarily associated with a decrease in McMoRan’s stock price. In the six months ended June 30, 2011, we recognized a $110.6 million gain related to our McMoRan investment.

Income taxes.     For the six months ended June 30, 2012 and 2011, our income tax expense was approximately 41% of pre-tax income. The variance between these effective tax rates and the 35% federal statutory rate results from the tax effects of estimated annual permanent differences, including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.

40

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 these agreements. These situations 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. Volatility and disruption in the financial and credit markets 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, including those counterparties who may have exposure to certain European sovereign debt. 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, 2012, we had approximately $1.1 billion available for future secured borrowings under our senior revolving credit facility, which had commitments and a borrowing base of $1.4 billion and approximately $2.3 billion, respectively. At June 30, 2012, Plains Offshore had $300 million available for future secured borrowings under its senior credit facility.

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 factors. Our next scheduled redetermination will be on or before May 1, 2013. Declines in oil and gas prices may adversely affect our liquidity by lowering the amount of the borrowing base that lenders are willing to extend.

The commitments of each lender to make loans to us are several and not joint under our senior revolving credit facility. Accordingly, if any lender fails to make loans to us, our available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the credit facility. At June 30, 2012, the commitments are from a diverse syndicate of 21 lenders and no single lender’s commitment represents more than 9% of the total commitments.

In April 2012, we issued $750 million of 6 ¹/₈% Senior Notes and received approximately $737.5 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, including the redemption of $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes and $76.9 million aggregate principal amount of our 7% Senior Notes. See Financing Activities.

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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 various derivative instruments to manage our exposure to 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. 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 – Commodity Price Risk.

We have made and will continue to make substantial capital expenditures for the acquisition, development and exploration of oil and gas. Our 2012 capital budget is approximately $1.6 billion, including capitalized interest and general and administrative expenses. We intend to fund our 2012 capital budget from internally generated funds and borrowings under our senior revolving credit facility, with the portion of our 2012 budget related to Plains Offshore being funded with cash on hand. In addition, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

We believe that we have sufficient liquidity through our forecasted cash flow from operations and borrowing capacity under our senior revolving credit facility, cash on hand and the Plains Offshore senior credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies, anticipated capital expenditures and preferred stock dividends of Plains Offshore. We have no near-term debt maturities. Our senior revolving credit facility matures on May 4, 2016 and the earliest maturity of our senior notes will occur on March 1, 2016.

Working Capital

At June 30, 2012, we had working capital of approximately $643.9 million, primarily due to the current asset classification of our investment in the McMoRan common shares and cash on hand from the Plains Offshore preferred stock transaction in November 2011. Our working capital fluctuates for various reasons, including the fair value of our investment, commodity derivative instruments, deferred taxes and stock-based compensation.

Financing Activities

Senior Revolving Credit Facility.     In February 2012, our borrowing base was increased from $1.8 billion to approximately $2.3 billion until the next scheduled redetermination date on or before May 1, 2013. The commitments remained unchanged at $1.4 billion. 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 factors. We are required, among other things, to make a mandatory prepayment if the combined total borrowings under both our senior revolving credit facility and the Plains Offshore senior credit facility exceed the borrowing base. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit and a $50 million commitment for swingline loans. At June 30, 2012, we had $298.0 million in outstanding borrowings and $1.2 million in letters of credit outstanding under our senior revolving credit facility. The daily average outstanding balance for the three and six months ended June 30, 2012 was $389.3 million and $613.9 million, respectively.

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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 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% 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 overnight federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts 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 4.50 to 1.

Plains Offshore Senior Credit Facility.     The aggregate commitments of the lenders under the Plains Offshore senior credit facility are $300 million. The Plains Offshore senior credit facility contains a $50 million limit on letters of credit and matures on November 18, 2016. At June 30, 2012, Plains Offshore had no borrowings or letters of credit outstanding under its senior credit facility.

Amounts borrowed under the Plains Offshore senior credit facility bear an interest rate, at Plains Offshore’s election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; or (ii) a variable amount ranging from 0.50% to 1.50% 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%. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under the Plains Offshore senior credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing.

The borrowings under the Plains Offshore senior credit facility are guaranteed on a senior basis by PXP and certain of our subsidiaries, and are secured on a pari passu basis by liens on the same collateral that secures PXP’s senior revolving credit facility. The Plains Offshore senior credit facility contains certain affirmative and negative covenants, including limiting Plains Offshore’s ability, among other things, to create liens, incur other indebtedness, make dividends (excluding dividends on preferred stock) or other distributions, make investments, change the nature of Plains Offshore’s business and merge or consolidate, sell assets, enter into certain types of swap agreements and enter into certain transactions with affiliates, as well as other customary events of default, including a cross-default to PXP’s senior revolving credit facility. If an event of default (as defined in our senior revolving credit facility) has occurred and is continuing under our senior revolving credit facility that has not been cured or waived by the lenders thereunder then the Plains Offshore lenders could accelerate and demand repayment of the Plains Offshore senior credit facility.

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Short-term Credit Facility.     We have an uncommitted short-term unsecured credit facility, or short-term facility, under which we may make borrowings from time to time, until June 1, 2013, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding 14 days and all amounts outstanding are due and payable no later than June 1, 2013. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and us.

We borrow under our short-term facility to fund our working capital needs. The funding requirements are typically generated due to the timing differences between payments and receipts associated with our oil and gas production. We generally pay off the short-term facility with receipts from the sales of our oil and gas production or borrowings under our senior revolving credit facility. No amounts were outstanding under the short-term facility at June 30, 2012. The daily average outstanding balance for the three and six months ended June 30, 2012 was $48.8 million and $45.9 million, respectively.

6  ¹/₈% Senior Notes.     In April 2012, we issued $750 million of 6 ¹/₈% Senior Notes at par. We received approximately $737.5 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, including the redemption of $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes and $76.9 million aggregate principal amount of our 7% Senior Notes. We may redeem all or part of the 6 ¹/₈% Senior Notes on or after June 15, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₈% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control triggering event, as defined in the indenture, we will be required to make an offer to repurchase the 6 ¹/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 6 ¹/₈% Senior Notes are general unsecured senior obligations. They are jointly and severally guaranteed by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of a subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have outstanding any guarantee of any of our or any of our subsidiary guarantor’s indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. The 6 ¹/₈% 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 6 ¹/₈% Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility and the Plains Offshore senior 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, including indebtedness under the Plains Offshore senior credit facility, which we guarantee, and the shares of preferred stock issued by Plains Offshore.

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Redemption of 7 ³/₄% Senior Notes and 7% Senior Notes.    During the second quarter of 2012, we redeemed the remaining $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes at 101.938% of the principal amount and the remaining $76.9 million aggregate principal amount of our 7% Senior Notes at 103.500% of the principal amount. We made payments totaling $80.8 million and $79.6 million to retire the 7 ³/₄% Senior Notes and the 7% Senior Notes, respectively. During the three and six months ended June 30, 2012, we recognized $5.2 million of debt extinguishment costs, including $0.9 million of unamortized debt issue costs in connection with the retirement of these Senior Notes.

Cash Flows

	Six Months Ended June 30,
	2012		2011
	(in millions)
Cash provided by (used in):
Operating activities	$	631.0	$	577.4
Investing activities		(790.1)		(857.2)
Financing activities		42.2		278.7

Net cash provided by operating activities was $631.0 million for the six months ended June 30, 2012 compared to $577.4 million for the six months ended June 30, 2011. The increase primarily reflects higher oil sales volumes and average realized oil prices.

Net cash used in investing activities of $790.1 million for the six months ended June 30, 2012 primarily reflects additions to oil and gas properties of approximately $824.3 million, partially offset by the proceeds from the sale of our Panhandle properties of approximately $43.4 million. Net cash used in investing activities of $857.2 million for the six months ended June 30, 2011 primarily reflects additions to oil and gas properties of $800.2 million.

Net cash provided by financing activities of $42.2 million for the six months ended June 30, 2012 primarily reflects proceeds from the $750 million offering of 6 ¹/₈% Senior Notes partially offset by the net reduction in borrowings under our senior revolving credit facility of $437.0 million, the redemption of our 7 ³/₄% Senior Notes and our 7% Senior Notes and $88.5 million of treasury stock repurchases. Net cash provided by financing activities of $278.7 million for the six months ended June 30, 2011 primarily reflects proceeds from the $600 million offering of 6 ⁵/₈% Senior Notes partially offset by the net reduction in borrowings under our senior revolving credit facility of $310.0 million.

Stock Repurchase Program

Our board of directors has authorized the repurchase of shares 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. In January 2012, we repurchased 2.4 million common shares at an average cost of $37.02 per share, totaling $88.5 million. Subsequent to these repurchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock, all of which is available for repurchase, and extended the program until January 2016.

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Critical Accounting Policies and Estimates

Oil and Natural Gas Properties Not Subject to Amortization.     The cost of unproved oil and natural gas properties are 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. 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 these transfers into our amortization base impacts our DD&A rate and full cost ceiling test.

During the first quarter of 2012, due to low natural gas prices, our assessment of the unproved property in the Haynesville Shale area indicated an impairment and accumulated costs of approximately $483 million were transferred to the full cost pool.

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 such information over different reporting periods. All such 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, DD&A, commodity pricing and risk management activities, investment, stock-based compensation, allocation of purchase price in business combinations, goodwill and income taxes are discussed in our Annual Report on Form 10-K for the year ended December 31, 2011.

Recent Accounting Pronouncements

In December 2011, the FASB issued authoritative guidance requiring entities to disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as financial instruments and transactions subject to agreements similar to master netting arrangements. The additional disclosures will enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning on or after January 1, 2013, and will primarily impact our disclosures associated with our commodity derivative instruments. We are currently evaluating the impact of this guidance.

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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 and hydraulic fracturing;

• the effects of future laws and governmental regulation that result from the Macondo accident and oil spill in the U.S. Gulf of Mexico;

• the value of the common stock of McMoRan and our ability to dispose of those shares;

• 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 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, 2011.

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

The fair value amounts of our put and collar derivative instruments are estimated using an option-pricing model, which uses various inputs including NYMEX and ICE 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. Our Level 3 commodity derivative contracts represent 71% of the total commodity derivative contracts assets and liabilities’ fair value.

The significant unobservable inputs used in the fair value measurement of our commodity derivative contracts are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement.

See Note 3 – Commodity Derivative Contracts and Note 5 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our derivative activities and fair value measurements.

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As of June 30, 2012, we had the following outstanding commodity derivative contracts, all of which settle monthly:

				Average
	Instrument	Daily	Average	Deferred
Period	Type	Volumes	Price (1)	Premium	Index
Sales of Crude Oil Production
2012
Jul - Dec	Three-way collars (2)	40,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$120.00 Ceiling
2013
Jan - Dec	Put options (3)	17,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.253 per Bbl	Brent
Jan - Dec	Put options (3)	13,000 Bbls	$100.00 Floor with an $80.00 Limit	$6.800 per Bbl	Brent
Jan - Dec	Three-way collars (2)	25,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$124.29 Ceiling
Jan - Dec	Three-way collars (2)	5,000 Bbls	$90.00 Floor with a $70.00 Limit	-	Brent
			$126.08 Ceiling
2014
Jan - Dec	Put options (3)	50,000 Bbls	$90.00 Floor with a $70.00 Limit	$5.979 per Bbl	Brent
Sales of Natural Gas Production
2012
Jul - Dec	Put options (4)	120,000 MMBtu	$4.30 Floor with a $3.00 Limit	$0.298 per MMBtu	Henry Hub
Jul - Dec	Three-way collars (5)	40,000 MMBtu	$4.30 Floor with a $3.00 Limit	-	Henry Hub
			$4.86 Ceiling
Jul - Dec	Swap contracts (6)	80,000 MMBtu	$2.72	-	Henry Hub
2013
Jan - Dec	Swap contracts (6)	110,000 MMBtu	$4.27	-	Henry Hub
2014
Jan - Dec	Swap contracts (6)	100,000 MMBtu	$4.09	-	Henry Hub

(1) The average strike prices do not reflect any premiums to purchase the put options.

(2) If the index price is less than the per barrel floor, we receive the difference between the per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and the per barrel ceiling if the index price is greater than the per barrel ceiling. If the index price is at or above the per barrel floor but at or below the per barrel ceiling, no cash settlement is required.

(3) If the index price is less than the per barrel floor, we receive the difference between the 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 the per barrel floor, we pay only the option premium.

(4) If the index price is less than the per MMBtu floor, we receive the difference between the per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above the per MMBtu floor, we pay only the option premium.

(5) If the index price is less than the per MMBtu floor, we receive the difference between the per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and the per MMBtu ceiling if the index price is greater than the per MMBtu ceiling. If the index price is at or above the per MMBtu floor but at or below the per MMBtu ceiling, no cash settlement is required.

(6) If the index price is less than the fixed price, we receive the difference between the fixed price and the index price. We pay the difference between the index price and the fixed price if the index price is greater than the fixed price.

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The fair value of outstanding crude oil and natural gas commodity derivative instruments at June 30, 2012 and the change in fair value that would be expected from a 10% price increase or decrease is shown below (in millions):

			Effect of 10%
	Fair Value		Price		Price
	Asset		Increase		Decrease
Crude oil puts	$	189	$	(165)	$	(51)
Crude oil collars		82		(85)		89
Natural gas puts		24		(9)		(5)
Natural gas collars		8		(1)		1
Natural gas swaps		29		(32)		32
	$	332	$	(292)	$	66

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.

Equity Price Risk

We are exposed to market risk because we own an equity investment in McMoRan common stock. See Note 4 – Investment and Note 5 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our equity investment. At June 30, 2012, the investment, comprised of 51.0 million shares of McMoRan common stock, was valued at approximately $562.5 million. A 10% change in the underlying equity market price per share would result in a $56.3 million increase or decrease in the fair value of our investment, recognized in the income statement.

We determine the fair value of our investment by discounting for lack of marketability at the reporting date. The discount factor for lack of marketability is determined by utilizing both Protective put and Asian put option models. Both of these options are valued using a Black-Scholes option-pricing model which utilizes various inputs including the closing price of the McMoRan common stock, implied volatility of the instrument, number of shares being valued, length of time that would be necessary to dispose of our investment, expected dividend and risk-free interest rates. As of June 30, 2012, we classified our investment as Level 3 since the fair value is determined by utilizing significant inputs that are unobservable.

Implied volatility associated with the common stock of McMoRan is a significant unobservable input used in the determination of the discount for lack of marketability of our investment measured at fair value. Significant increases (decreases) in volatility in isolation would result in a significantly higher (lower) discount factor for lack of marketability. Additionally, another significant unobservable input, the expected term of our investment, impacts the discount factor for lack of marketability. Significant increases (decreases) in the expected term in isolation would result in a significantly higher (lower) discount factor for lack of marketability. A higher discount factor would result in a lower fair value measurement of our investment.

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ITEM 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rules 13a-15(e) and 15d-15(e) of 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, 2012 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, 2012 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 6. Exhibits

Exhibit No.	Description
4.1	Fourteenth Supplemental Indenture, dated as of April 27, 2012, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (including form of the 6 1/8% Senior Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed April 27, 2012, File No. 1-31470).
31.1*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Executive Officer.
31.2*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Financial Officer.
32.1**	Section 1350 Certificate of the Chief Executive Officer.
32.2**	Section 1350 Certificate of the Chief Financial Officer.
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

      ** Furnished herewith

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PLAINS EXPLORATION & PRODUCTION COMPANY
Date: August 2, 2012	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	Fourteenth Supplemental Indenture, dated as of April 27, 2012, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (including form of the 6 1/8% Senior Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed April 27, 2012, File No. 1-31470).
31.1*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Executive Officer.
31.2*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Financial Officer.
32.1**	Section 1350 Certificate of the Chief Executive Officer.
32.2**	Section 1350 Certificate of the Chief Financial Officer.
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
**	Furnished herewith

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