Plains Exploration & Production 10-Q 2013 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

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

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

129.5 million shares of Common Stock, $0.01 par value, issued and outstanding at April 26, 2013.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART  I.  FINANCIAL INFORMATION
ITEM 1.  Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets March 31, 2013 and December 31, 2012	1
Consolidated Statements of Income For the three months ended March 31, 2013 and 2012	2
Consolidated Statements of Cash Flows For the three months ended March 31, 2013 and 2012	3
Consolidated Statement of Equity For the three months ended March 31, 2013	4
Notes to Consolidated Financial Statements	5
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
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)

	March 31, 2013		December 31, 2012
ASSETS
Current Assets
Cash and cash equivalents	$	54,270	$	180,565
Accounts receivable		563,313		584,722
Commodity derivative contracts		2,892		56,208
Inventories		33,830		27,672
Investment		833,767		818,223
Deferred income taxes		227,051		150,876
Prepaid expenses and other current assets		45,062		21,464
		1,760,185		1,839,730
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		19,236,999		18,814,337
Not subject to amortization		3,700,129		3,631,475
Other property and equipment		164,890		153,344
		23,102,018		22,599,156
Less allowance for depreciation, depletion, amortization and impairment		(8,392,756)		(7,870,356)
		14,709,262		14,728,800
Goodwill		535,140		535,140
Commodity Derivative Contracts		-		903
Other Assets		185,787		193,710
	$	17,190,374	$	17,298,283
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	421,405	$	431,422
Commodity derivative contracts		62,569		18,942
Royalties and revenues payable		165,520		139,717
Interest payable		142,285		105,440
Other current liabilities		113,384		120,192
Current maturities of long-term debt		164,288		164,288
		1,069,451		980,001
Long-Term Debt		9,559,247		9,979,369
Other Long-Term Liabilities
Asset retirement obligation		579,089		565,989
Commodity derivative contracts		118,427		26,810
Other		17,837		19,105
		715,353		611,904
Deferred Income Taxes		1,863,678		1,770,568
Commitments and Contingencies (Note 9)
Equity
Stockholders’ equity
Common stock, $0.01 par value, 250.0 million shares authorized, 143.9 million shares issued at March 31, 2013 and December 31, 2012		1,439		1,439
Additional paid-in capital		3,413,932		3,437,826
Retained earnings		658,772		637,411
Treasury stock, at cost, 14.4 million shares and 15.0 million shares at March 31, 2013 and December 31, 2012, respectively		(533,920)		(560,198)
		3,540,223		3,516,478
Noncontrolling interest
Preferred stock of subsidiary		442,422		439,963
		3,982,645		3,956,441
	$	17,190,374	$	17,298,283

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     March 31,
	2013		2012
Revenues
Oil sales	$	1,158,438	$	467,488
Gas sales		72,331		53,524
Other operating revenues		1,346		3,263
		1,232,115		524,275
Costs and Expenses
Lease operating expenses		170,233		83,006
Steam gas costs		14,604		11,124
Electricity		11,056		11,374
Production and ad valorem taxes		28,632		12,631
Gathering and transportation expenses		22,618		16,272
General and administrative
G&A		44,765		38,382
Acquisition and merger related costs		1,199		-
Depreciation, depletion and amortization		530,460		177,697
Accretion		10,015		3,753
Other operating expense (income)		1,196		(1,261)
		834,778		352,978
Income from Operations		397,337		171,297
Other (Expense) Income
Interest expense		(140,998)		(45,253)
Debt extinguishment costs		(18,053)		-
Loss on mark-to-market derivative contracts		(202,023)		(109,050)
Gain (loss) on investment measured at fair value		15,544		(135,930)
Other income (expense)		395		(405)
Income (Loss) Before Income Taxes		52,202		(119,341)
Income tax (expense) benefit
Current		(4,790)		(19)
Deferred		(15,618)		46,057
Net Income (Loss)		31,794		(73,303)
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		(9,209)		(9,016)
Net Income (Loss) Attributable to Common Stockholders	$	22,585	$	(82,319)
Earnings (Loss) per Common Share
Basic	$	0.17	$	(0.64)
Diluted	$	0.17	$	(0.64)
Weighted Average Common Shares Outstanding
Basic		130,284		129,348
Diluted		132,930		129,348

See notes to consolidated financial statements.

2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Three Months Ended
	March 31,
	2013		2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	31,794	$	(73,303)
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		530,460		177,697
Accretion		10,015		3,753
Deferred income tax expense (benefit)		15,618		(46,057)
Debt extinguishment costs		(4,903)		-
Loss on mark-to-market derivative contracts		202,023		109,050
(Gain) loss on investment measured at fair value		(15,544)		135,930
Non-cash compensation		13,496		18,232
Other non-cash items		2,706		1,421
Change in assets and liabilities from operating activities
Accounts receivable and other assets		4,857		4,857
Accounts payable and other liabilities		23,770		(5,338)
Income taxes receivable/payable		4,431		9,169
Net cash provided by operating activities		818,723		335,411
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(467,737)		(401,311)
Acquisition of oil and gas properties		(31,748)		(16,573)
Proceeds from sales of oil and gas properties, net of costs and expenses		-		42,656
Derivative settlements		(13,516)		9,321
Additions to other property and equipment		(7,909)		(2,904)
Other		(681)		-
Net cash used in investing activities		(521,591)		(368,811)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		3,328,700		2,515,500
Repayments of revolving credit facilities		(3,573,500)		(2,440,500)
Principal payments of long-term debt		(171,180)		-
Costs incurred in connection with financing arrangements		(697)		(125)
Purchase of treasury stock		-		(88,490)
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		(6,750)		(6,750)
Net cash used in financing activities		(423,427)		(20,365)
Net decrease in cash and cash equivalents		(126,295)		(53,765)
Cash and cash equivalents, beginning of period		180,565		419,098
Cash and cash equivalents, end of period	$	54,270	$	365,333

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, 2012		143,924	$	1,439	$	3,437,826	$	637,411		(14,959)		$(560,198)	$	3,516,478	$	439,963	$	3,956,441
Net income		-		-		-		22,585		-		-		22,585		9,209		31,794
Restricted stock awards		-		-		1,157		-		-		-		1,157		-		1,157
Issuance of treasury stock for restricted stock awards		-		-		(25,051)		(1,224)		527		26,275		-		-		-
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-		-		-		-		-		-		-		(6,750)		(6,750)
Other		-		-		-		-		-		3		3		-		3
Balance at March 31, 2013		143,924	$	1,439	$	3,413,932	$	658,772		(14,432)	$	(533,920)	$	3,540,223	$	442,422	$	3,982,645

See notes to consolidated financial statements.

4

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1 — Summary of Significant Accounting Policies

Plains Exploration & Production Company, a Delaware corporation formed in 2002 (“PXP”, “us”, “our” or “we”), is an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are primarily located in the United States.

Our consolidated financial statements include the accounts of all our 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 three months ended March 31, 2013 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, 2012.

Asset Retirement Obligation.    The following table reflects the changes in our asset retirement obligation during the three months ended March 31, 2013 (in thousands):

Asset retirement obligation - December 31, 2012	$	584,501
Settlements		(691)
Accretion expense		10,015
Asset retirement additions		3,413
Asset retirement obligation - March 31, 2013 (1)	$	597,238

(1) $18.1 million is included in other current liabilities.

Earnings Per Share. For the three months ended March 31, 2013 and 2012, the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):

	Three Months Ended   March 31,
	2013		2012
Weighted average common shares outstanding - basic		130,284		129,348
Unvested restricted stock and restricted stock units		2,646		-
Weighted average common shares outstanding - diluted		132,930		129,348

5

In computing our earnings per share for the three months ended March 31, 2013 and 2012, we decreased our reported net income by approximately $9.2 million and $9.0 million, respectively, in 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 months ended March 31, 2013 and 2012, and because Plains Offshore had a net loss for the three months ended March 31, 2013 and 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 March 31, 2013 and December 31, 2012, inventory consisted of the following (in thousands):

	March 31,   2013		December 31,   2012
Oil	$	13,119	$	11,394
Materials and supplies		20,711		16,278
	$	33,830	$	27,672

Stock-Based Compensation.Stock-based compensation for the three months ended March 31, 2013 was $18.4 million, of which $12.9 million is included in general and administrative expense, or G&A, $0.6 million is included in lease operating expense and $4.9 million is included in oil and natural gas properties. Stock-based compensation for the three months ended March 31, 2012 was $23.5 million, of which $13.8 million is included in G&A, $4.4 million is included in lease operating expense and $5.3 million is included in oil and natural gas properties.

During the three months ended March 31, 2013, we granted 850 thousand restricted stock units, or RSUs, at an average fair value of $48.33 per share to be settled in shares of common stock, 1.5 million RSUs at an average fair value of $47.09 per share to be settled in cash and 524 thousand stock appreciation rights, or SARs, with an average exercise price of $48.15 per share.

Included in the 1.5 million RSUs to be settled in cash are 225 thousand RSUs that are subject to a market condition in which the price performance of PXP’s 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. On the grant date, we estimated that these units had a weighted average fair value of $40.17 per unit, an aggregate fair value of $9.0 million and a weighted average remaining contractual life of 2.2 years.

6

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.

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 March 31, 2013, Plains Offshore declared quarterly dividends on the preferred stock of approximately $9.2 million, or $20.43 per share of preferred stock, $15.00 per share of which was paid in cash with the remaining deferred. During the three months ended March 31, 2012, Plains Offshore declared quarterly dividends on the preferred stock of approximately $9.0 million, or $20.02 per share of preferred stock, $15.00 per share of which was paid in cash with the remaining deferred. Deferred dividends accumulate and compound quarterly at 8% per year until paid.

The following table presents a reconciliation of changes in noncontrolling interest for the three months ended March 31, 2013 and 2012 (in thousands):

	Three Months Ended March 31,
	2013		2012
Noncontrolling interest at beginning of period	$	439,963	$	430,596
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		9,209		9,016
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		(6,750)		(6,750)
Noncontrolling interest at end of period	$	442,422	$	432,862

Note 2 — Proposed Merger with Freeport-McMoRan Copper & Gold Inc.

On December 5, 2012, we entered into an Agreement and Plan of Merger, or the Freeport-McMoRan Merger Agreement, with Freeport-McMoRan Copper & Gold Inc., or Freeport-McMoRan, and IMONC LLC, a wholly owned subsidiary of Freeport-McMoRan, or the Merger Sub, pursuant to which Freeport-McMoRan will acquire PXP for approximately $6.9 billion in cash and stock, based on the closing price of Freeport-McMoRan stock on December 4, 2012.

The Freeport-McMoRan Merger Agreement provides that PXP will merge with and into the Merger Sub, with the Merger Sub continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. Subject to the terms and conditions of the Freeport-McMoRan Merger Agreement, PXP stockholders have the right to receive 0.6531 shares of Freeport-McMoRan common stock and $25.00 in cash, equivalent to total consideration of $50.00 per PXP share, based on the closing price of Freeport-McMoRan stock on December 4, 2012. PXP stockholders may elect to receive cash or stock consideration, subject to proration in the event of oversubscription, with the value of the cash and stock per share consideration to be equalized at closing.

7

The Freeport-McMoRan Merger Agreement provides that each share of restricted stock and each stock-settled RSU that has been granted or contractually promised by PXP as of the date of the Freeport-McMoRan Merger Agreement and that is outstanding immediately prior to or upon the effective time of the merger, including each stock-settled RSU that will become issuable or creditable in connection with the consummation of the merger pursuant to any employment agreement, RSU agreement or other written agreement, will become fully vested and be converted into the right to receive, at the election of the holder, cash consideration or stock consideration, except for certain stock-settled RSUs held by PXP’s named executive vice presidents that will convert into stock consideration (with right to elect up to 25% as cash consideration), and certain stock-settled RSUs held by Mr. Flores that will automatically convert into stock consideration, in each case pursuant to the terms of the executive’s respective letter agreement among each named executive officer, Freeport-McMoRan and PXP. Each cash-settled RSU that has been granted or contractually promised by PXP as of the date of the Freeport-McMoRan Merger Agreement and that is outstanding immediately prior to or upon the effective time of the merger will become fully vested in accordance with the terms of the applicable award agreement and be converted into the right to receive cash consideration, payable at such time as the cash per-share consideration is payable generally to PXP stockholders who elect to receive cash consideration. SARs relating to shares of PXP common stock outstanding and unexercised that have been granted or contractually promised by PXP as of the date of the Freeport-McMoRan Merger Agreement and that are outstanding immediately prior to or upon the effective time of the merger will become fully vested and be converted into SARs relating to shares of Freeport-McMoRan common stock. All restricted stock, stock-settled RSUs, cash-settled RSUs and SARs granted or issued by PXP after the date of the Freeport-McMoRan Merger Agreement and prior to the merger will be converted into the same type of award covering shares of Freeport-McMoRan pursuant to the formula set forth in the Freeport-McMoRan Merger Agreement, with the same terms and conditions as prior to the completion of the merger.

The Freeport-McMoRan Merger Agreement provides that, upon termination of the Freeport-McMoRan Merger Agreement under certain circumstances, PXP may be required to reimburse Freeport-McMoRan for its expenses in an amount up to $69.0 million and/or pay Freeport-McMoRan a termination fee in an amount equal to $207.0 million less any expenses reimbursed by PXP.

Completion of the merger is subject to customary conditions, including approval by PXP stockholders and receipt of required regulatory approvals. PXP will hold a special meeting of its stockholders on May 20, 2013 to vote on the merger. The merger is expected to close in the second quarter of 2013.

8

On December 5, 2012, Freeport-McMoRan entered into an Agreement and Plan of Merger, or the MMR Merger Agreement, with McMoRan Exploration Co., or McMoRan, and INAVN Corp., a wholly owned subsidiary of Freeport-McMoRan, or the MMR Merger Sub, pursuant to which MMR Merger Sub will be merged with and into McMoRan, or the MMR Merger, with McMoRan continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. The per share consideration consists of $14.75 in cash and 1.15 units of a royalty trust, which will hold a 5% overriding royalty interest in future production from McMoRan’s existing ultra-deep exploration properties. In connection with the MMR Merger, on December 5, 2012, PXP and Freeport-McMoRan entered into a Voting and Support Agreement, or the Support Agreement. The Support Agreement generally requires that PXP, in its capacity as a stockholder of 31.3% of McMoRan, vote all of its shares of McMoRan common stock in favor of the MMR Merger and against alternative transactions and generally prohibits us from transferring our shares of McMoRan common stock prior to the consummation of the MMR Merger. The Support Agreement will terminate upon the earlier of (i) the Expiration Date (defined as the earlier of (A) the consummation of the MMR Merger and (B) the termination of the MMR Merger Agreement) and (ii) any breach by Freeport-McMoRan of its obligation under the Freeport-McMoRan Merger Agreement not to change the merger consideration in the MMR Merger Agreement, amend the covenant relating to standstill waivers in the MMR Merger Agreement or otherwise materially amend any material provision of the MMR Merger Agreement, or terminate the MMR Merger Agreement, without PXP’s prior written consent. The MMR Merger is subject to the approval of the shareholders of McMoRan, including the approval of an amendment to McMoRan’s certificate of incorporation, receipt of regulatory approvals and customary closing conditions.

Note 3 — Acquisitions

Gulf of Mexico

During the fourth quarter of 2012, we completed the acquisition of certain oil and gas interests in and near the Holstein, Diana, Hoover, Horn Mountain, Marlin, Dorado, King and Ram Powell Fields located in the Gulf of Mexico from BP Exploration & Production Inc. and BP America Production Company, or BP, subject to customary post-closing adjustments. We also completed the acquisition of the 50% working interest in the Holstein Field located in the Gulf of Mexico from Shell Offshore Inc., or Shell, subject to customary post-closing adjustments. After pre-closing adjustments, we paid cash consideration of approximately $5.36 billion and $532.1 million, respectively, for these acquisitions from BP and Shell. We accounted for these acquisitions, collectively referred to as the Gulf of Mexico Acquisition, effective October 1, 2012, as acquisitions of businesses under purchase accounting rules. The assets acquired and liabilities assumed were recorded based on their estimated fair values. The fair values are preliminary subject to our determination of asset retirement obligations and fair values of assets acquired and liabilities assumed that have not been completed as of March 31, 2013. These and other estimates are subject to change as additional information becomes available and is assessed by us and BP and Shell, respectively, and agreement is reached on the respective final settlement statements. We expect to finalize the fair values of assets acquired and liabilities assumed in the third quarter of 2013.

9

Unaudited Pro Forma Impact of Gulf of Mexico Acquisition

The following unaudited pro forma information shows the pro forma effect of the Gulf of Mexico Acquisition and its associated financing, consisting of our Senior Notes offering completed in October 2012 and our revolving line of credit and term loan credit facilities, collectively the Amended Credit Facility, for the three months ended March 31, 2012. We believe the assumptions used provide a reasonable basis for representing the pro forma significant effects directly attributable to the Gulf of Mexico Acquisition and its associated financing. The unaudited pro forma information assumes such transaction occurred on January 1, 2011. The unaudited pro forma information does not purport to represent what our results of operations would have been if such transaction had occurred on January 1, 2011 (in thousands):

	Three Months Ended   March 31, 2012
Revenues	$	1,100,982
Net income from continuing operations		118,593
Net income attributable to common stockholders		109,577

Note 4 — Long-Term Debt

At March 31, 2013 and December 31, 2012, long-term debt consisted of (in thousands):

	March 31,   2013		December 31,   2012
Amended Credit Facility
Revolving line of credit	$	1,325,200	$	1,570,000
Five-year term loan due 2017(1)		731,537		730,638
Seven-year term loan due 2019(2)		1,221,751		1,220,844
Plains Offshore senior credit facility		-		-
10% Senior Notes due 2016(3)		-		177,266
7  5/8% Senior Notes due 2018		400,000		400,000
6  1/8% Senior Notes due 2019		750,000		750,000
8  5/8% Senior Notes due 2019(4)		395,047		394,909
7  5/8% Senior Notes due 2020		300,000		300,000
6  1/2% Senior Notes due 2020		1,500,000		1,500,000
6  5/8% Senior Notes due 2021		600,000		600,000
6  3/4% Senior Notes due 2022		1,000,000		1,000,000
6  7/8% Senior Notes due 2023		1,500,000		1,500,000
		9,723,535		10,143,657
Current maturities of long-term debt		(164,288)		(164,288)
	$	9,559,247	$	9,979,369

(1) The amount is net of unamortized issue costs of $18.5 million and $19.4 million at March 31, 2013 and December 31, 2012, respectively.

(2) The amount is net of unamortized issue costs of $28.2 million and $29.2 million at March 31, 2013 and December 31, 2012, respectively.

(3) The amount is net of unamortized discount of $7.6 million at December 31, 2012.

(4) The amount is net of unamortized discount of $5.0 million and $5.1 million at March 31, 2013 and December 31, 2012, respectively.

10

Amended Credit Facility. In November 2012, we entered into the Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and the lenders party thereto, or the Amended Credit Agreement, which amended and restated our senior revolving credit facility. The Amended Credit Agreement provided for (i) a five-year revolving line of credit, a five-year term loan and a seven-year term loan and (ii) an initial borrowing base of $5.175 billion, which will be redetermined on an annual basis, with us and the lenders of the revolving line of credit each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness (including the outstanding commitments under the credit agreement dated November 18, 2011 among Plains Offshore, JPMorgan Chase Bank, N.A. as administrative agent and the lenders party thereto from time to time) and other factors. Our next redetermination will occur on or before September 5, 2013.

Revolving Line of Credit. The aggregate commitments of the lenders under the revolving line of credit are $3.0 billion and can be increased to $3.6 billion if certain conditions are met. We are required, among other things, to make a mandatory prepayment if the combined total borrowings under our Amended Credit Facility and the Plains Offshore senior credit facility exceed the borrowing base. Additionally, our revolving line of credit contains a $750 million sub limit on letters of credit and a $100 million sub limit for swingline loans and matures on November 30, 2017. At March 31, 2013, we had $2.9 million in letters of credit outstanding under our revolving line of credit.

Amounts borrowed under our revolving line of credit 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 alternate base rate, or ABR, which is the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, N.A., (2) the federal funds rate, plus0.50%, and (3) the adjusted one-month 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 Eurodollar rate and the ABR will be increased 0.25% while any term loans are outstanding. The additional variable amount of interest payable is based on the utilization rate as a percentage of the total amount of funds borrowed under our Amended Credit Facility and the Plains Offshore senior credit facility to the borrowing base. Letter of credit fees under our revolving line of credit are based on the utilization rate and range from 1.50% to 2.50% and will be increased by 0.25% while any term loans are outstanding. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing.

Five-Year Term Loan and Seven-Year Term Loan. The Amended Credit Agreement provided for the $750.0 million five-year term loan due 2017 and the $1.25 billion seven-year term loan due 2019. The term loans bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus 3.00% or (ii) 2.00% plus the ABR, which is the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, N.A., (2) the federal funds rate, plus 0.50%, and (3) the adjusted one-month LIBOR plus 1.00%. In no event can LIBOR for the seven-year term loan be less than 1.00% per year. The five-year term loan is payable in four annual installments each equal to 10% of the original principal balance due and payable on the last business day of December beginning on December 31, 2013 and the remaining balance due on its five-year maturity on November 30, 2017. The seven-year term loan is payable in six annual installments each equal to 7.143% of the original principal balance due and payable on the last business day of December beginning on December 31, 2013 and the remaining balance due on its seven-year maturity on November 30, 2019. The current portion of the five-year term loan and seven-year term loan is $75.0 million and $89.3 million, respectively, at March 31, 2013.

11

Our Amended 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 Amended 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 or guarantee other indebtedness, 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, sell certain assets including capital stock of subsidiaries, 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 March 31, 2013, 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, N.A., (2) the federal funds rate, plus 0.50%, and (3) the adjusted LIBOR plus 1.00%. The additional variable amount of interest payable is based on the utilization rate as a percentage of the total amount of funds borrowed under both our revolving line of credit and the Plains Offshore senior credit facility and the borrowing base under our Amended 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 apari passu basis by liens on the same collateral that secures PXP’s Amended 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 Amended Credit Facility. If an event of default (as defined in our Amended Credit Facility) has occurred and is continuing under our Amended 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.

12

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 revolving line of credit. At March 31, 2013, we had $0.2 million outstanding under the short-term facility which we have included in long-term borrowings as we intend and have the ability to pay this balance with borrowings under the revolving line of credit. The daily average outstanding balance for the three months ended March 31, 2013 was $44.5 million.

Redemption of 10% Senior Notes.During the first quarter of 2013, we redeemed the remaining $184.9 million aggregate principal amount of our 10% Senior Notes due 2016, or the 10% Senior Notes, at 105% of the principal amount. We made payments totaling $194.1 million to retire the 10% Senior Notes. During the three months ended March 31, 2013, we recognized $18.1 million of debt extinguishment costs, including $8.8 million of unamortized original issue discount and debt issue costs in connection with the retirement of these Senior Notes.

Subsequent Event

On May 1, 2013, our Board of Directors approved the call for redemption of the $400 million aggregate principal amount of our outstanding 7 ⁵/₈% Senior Notes due 2018 at 103.813% of the principal amount. We expect to make payments totaling $415.3 million to retire the 7 ⁵/₈% Senior Notes due 2018 in June 2013. We expect to recognize approximately $18.1 million of debt extinguishment costs, including $2.8 million of unamortized debt issue costs upon retirement of these Senior Notes.

Note 5 — 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 rates on our revolving line of credit, term loans and Plains Offshore’s senior credit facility are 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.

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.

13

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.

See Note 7 – Fair Value Measurements of Assets and Liabilities, for additional discussion on the fair value measurement of our derivative contracts.

14

As of March 31, 2013, 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
2013
Apr - Dec	Swap contracts(2)	40,000 Bbls	$109.23	-	Brent
Apr - Dec	Put options(3)	13,000 Bbls	$100.00 Floor with an $80.00 Limit	$6.800 per Bbl	Brent
Apr - Dec	Three-way collars(4)	25,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$124.29 Ceiling
Apr - Dec	Three-way collars(4)	5,000 Bbls	$90.00 Floor with a $70.00 Limit	-	Brent
			$126.08 Ceiling
Apr - Dec	Put options(3)	17,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.253 per Bbl	Brent
2014
Jan - Dec	Put options(3)	5,000 Bbls	$100.00 Floor with an $80.00 Limit	$7.110 per Bbl	Brent
Jan - Dec	Put options(3)	30,000 Bbls	$95.00 Floor with a $75.00 Limit	$6.091 per Bbl	Brent
Jan - Dec	Put options(3)	75,000 Bbls	$90.00 Floor with a $70.00 Limit	$5.739 per Bbl	Brent
2015
Jan - Dec	Put options(3)	84,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.889 per Bbl	Brent
Sales of Natural Gas Production
2013
Apr - Dec	Swap contracts(2)	110,000 MMBtu	$4.27	-	Henry Hub
2014
Jan - Dec	Swap contracts(2)	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 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.

(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 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.

15

Balance Sheet

At March 31, 2013 and December 31, 2012, we had the following outstanding commodity derivative contracts recorded in our balance sheet (in thousands):

		Estimated Fair Value
Instrument Type	Balance Sheet Classification	March 31, 2013		December 31, 2012
Crude oil puts	Commodity derivative contracts - current assets	$	33,307	$	28,348
Crude oil collars	Commodity derivative contracts - current assets		8,958		17,263
Crude oil swaps	Commodity derivative contracts - current assets		13,747		33,416
Natural gas swaps	Commodity derivative contracts - current assets		1,892		29,052
Crude oil puts	Commodity derivative contracts - non-current assets		267,731		412,348
Natural gas swaps	Commodity derivative contracts - non-current (liabilities) assets		(2,525)		2,170
Total derivative instruments		$	323,110	$	522,597

The following table provides supplemental information to reconcile the fair value of our derivative contracts to our balance sheet at March 31, 2013 and December 31, 2012, 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):

	March 31,   2013		December 31,    2012
Net fair value asset	$	323,110	$	522,597
Deferred premium and accrued interest on derivative contracts		(494,819)		(511,255)
Settlement payable		(6,395)		-
Settlement receivable		-		17
Net commodity derivative (liability) asset	$	(178,104)	$	11,359
Commodity derivative contracts - current asset	$	2,892	$	56,208
Commodity derivative contracts - non-current asset		-		903
Commodity derivative contracts - current liability		(62,569)		(18,942)
Commodity derivative contracts - non-current liability		(118,427)		(26,810)
	$	(178,104)	$	11,359

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 months ended March 31, 2013 and 2012, pre-tax amounts recognized in our income statements for derivative transactions were as follows (in thousands):

	Three Months Ended March 31,
	2013		2012
Loss on mark-to-market derivative contracts		$    (202,023)		$    (109,050)

16

Cash Payments and Receipts

During the three months ended March 31, 2013 and 2012, cash (payments) receipts for derivatives were as follows (in thousands):

	Three Months Ended March 31,
	2013		2012
Oil derivatives	$	(22,741)	$	(5,856)
Natural gas derivatives		9,225		15,177
	$	(13,516)	$	9,321

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. 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.

Contingent Features

As of March 31, 2013, the counterparties to our commodity derivative contracts consisted of ten financial institutions. All of our counterparties or their affiliates are also lenders under our Amended Credit Facility. As a result, the counterparties to our derivative agreements share in the collateral supporting our Amended 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 March 31, 2013, we were in a net liability position with nine of the counterparties to our derivative instruments, totaling $178.1 million.

We adopted the guidance requiring disclosure of 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 on January 1, 2013. The additional disclosures enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on our financial position. The provisions of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.

17

The following table presents quantitative information about our commodity derivative contracts, all of which are offset on our balance sheet and subject to enforceable master netting arrangements as of March 31, 2013 and December 31, 2012 (in thousands):

	Gross Amounts of		Gross Amounts Offset in the		Net Amounts of Assets (Liabilities) Presented in the		Gross Amounts Not Offset in the Statement of Financial Position
	Recognized Assets (Liabilities)		Statement of Financial Position		Statement of Financial Position		Financial Instruments		Cash Collateral Received		Net Amount
March 31, 2013
Commodity derivative contracts
Assets	$	431,282	$	(428,390)	$	2,892	$	-	$	-	$	2,892
Liabilities		(609,386)		428,390		(180,996)		-		-		(180,996)
December 31, 2012
Commodity derivative contracts
Assets	$	778,548	$	(721,437)	$	57,111	$	-	$	-	$	57,111
Liabilities		(767,189)		721,437		(45,752)		-		-		(45,752)

Note 6 — Investment

At March 31, 2013 and 2012, we owned 51.0 million shares of McMoRan common stock, approximately 31.3% and 31.6%, 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.

On December 5, 2012, Freeport-McMoRan agreed to acquire McMoRan for per share consideration consisting of $14.75 in cash and 1.15 units of a royalty trust, which will hold a 5% overriding royalty interest in future production from McMoRan’s existing ultra-deep exploration properties. In connection with the MMR Merger, on December 5, 2012, we entered into the Support Agreement with Freeport-McMoRan, pursuant to which we are generally required to, in our capacity as a stockholder of 31.3% of McMoRan, vote all of our shares of McMoRan common stock in favor of the MMR Merger Agreement and against alternative transactions and generally prohibits us from transferring our shares of McMoRan common stock prior to the consummation of the MMR Merger.

18

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 March 31, 2013, the McMoRan shares were valued at approximately $833.8 million, based on McMoRan’s closing stock price of $16.35 on March 31, 2013, discounted by the time value of money corresponding to the maturity date of the expected close of the merger. During the three months ended March 31, 2013 and 2012, we recorded an unrealized gain of $15.5 million and an unrealized loss of $135.9 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):

	Three Months Ended
	March 31,
	2013(1)		2012
Results of Operations(2)
Revenues		$    25,493	$	34,964
Operating income		19,951		2,644
Income from continuing operations		19,956		2,716
Net income (loss) applicable to common stock		16,479		(1,533	)

(1) Amounts are based on McMoRan’s Form 10-Q dated May 6, 2013.

(2) Amounts represent our 31.3% and 31.6% equity ownership in McMoRan as of March 31, 2013 and 2012, respectively.

Note 7 — 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.

19

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 March 31, 2013 and December 31, 2012 (in thousands):

			Fair Value Measurements at Reporting Date Using
	Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
March 31, 2013
Commodity derivative contracts(1)
Crude oil puts	$	301,038	$	-	$	9,535	$	291,503
Crude oil collars		8,958		-		-		8,958
Crude oil swaps		13,747		-		13,747		-
Natural gas swaps		(633)		-		(633)		-
Investment(2)		833,767		-		-		833,767
	$	1,156,877	$	-	$	22,649	$	1,134,228
December 31, 2012
Commodity derivative contracts(1)
Crude oil puts	$	440,696	$	-	$	428,355	$	12,341
Crude oil collars		17,263		-		-		17,263
Crude oil swaps		33,416		-		33,416		-
Natural gas swaps		31,222		-		31,222		-
Investment(2)		818,223		-		-		818,223
	$	1,340,820	$	-	$	492,993	$	847,827

(1) Option premium and accrued interest of $494.8 million and $511.3 million at March 31, 2013 and December 31, 2012, respectively, and settlement payable of $6.4 million at March 31, 2013 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.

The fair value amounts of our put and collar derivative instruments are estimated using an option-pricing model, which uses various inputs including 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 and ICE 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.

20

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 March 31, 2013, our commodity derivative contracts are classified as follows:

• Our 2013 and 2014 natural gas swaps, our 2013 crude oil swaps and certain of our 2014 crude oil puts are classified as Level 2 instruments.

• Our 2013 crude oil puts and collars, certain of our 2014 crude oil puts and our 2015 crude oil puts are classified as Level 3 instruments.

On March 31, 2013, we determined the fair value of our investment using McMoRan’s closing stock price of $16.35, which we believe is consistent with the exit price notion and is representative of what a market participant would pay for McMoRan’s common stock in an arm’s length transaction. Additionally, we utilized a time value of money analysis to determine an implied discount rate. The implied discount is determined by utilizing a risk-free interest rate based on the U.S. Treasury Strip rate with a maturity date corresponding to the expected close of the merger.

As of March 31, 2013, our investment in McMoRan has been classified 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.

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 March 31, 2013 (in thousands):

	Quantitative Information About Level 3 Fair Value Measurements
	Fair Value		Valuation Technique		Unobservable Input	Range (Weighted Average)
March 31, 2013
Commodity derivative contracts(1)
Crude oil puts	$	291,503		Option pricing model	Implied volatility	19% - 72% (22%)
Crude oil collars		8,958		Option pricing model	Implied volatility	16% - 72% (23%)
Investment(2)		833,767		Time value of money analysis	Expected term	0.00% - 0.01% (0.01%)

(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 time value of money associated with our investment in the common stock of McMoRan. The discount for time value of money is derived by an implied discount analysis 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.

21

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.

The expected term associated with the completion of the merger used in determination of the fair value of our investment is a significant unobservable input. The expected term of our investment impacts the implied discount to reflect the time value of money. Failure to complete the merger and the MMR Merger could modify the term in which we are able to sell our investment in McMoRan’s common shares. Significant increases (decreases) in the expected term in isolation would result in a significantly higher (lower) discount factor. A higher implied discount factor would result in a lower fair value measurement of our investment. Additionally, failure to complete the merger could result in changes to the method we use to determine fair value of our investment, which may result in the use of other significant unobservable inputs.

The following table presents a reconciliation of changes in fair value of our financial assets and liabilities classified as Level 3 for the three months ended March 31, 2013 and 2012 (in thousands):

	Three Months Ended March 31,
	2013				2012
	Commodity Derivatives (1)		Investment		Commodity Derivatives (1)		Investment
Fair value at beginning of period	$	29,604	$	818,223	$	114,096	$	611,671
Transfers into Level 3(2)		428,354		-		(668)		-
Transfers out of Level 3(3)		(12,341)		-		(2,817)		-
Realized and unrealized gains and losses included in earnings(4)		(145,156)		15,544		(108,275)		(135,930)
Purchases		-		-		69,721		-
Settlements		-		-		(14,135)		-
Fair value at end of period	$	300,461	$	833,767	$	57,922	$	475,741
Change in unrealized gains and losses relating to assets and liabilities held as of the end of the period(4)	$	(142,671)	$	15,544	$	(105,399)	$	(135,930)

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

(2) During the three months ended March 31, 2013, the inputs used to value our 2013 crude oil puts, certain of our 2014 crude oil puts and our 2015 crude oil puts were significantly unobservable and those contracts were transferred from Level 2 to Level 3.

(3) During the three months ended March 31, 2013, the inputs used to value certain of our 2014 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 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 at March 31, 2013 or December 31, 2012.

22

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.

The following table presents the carrying amounts and fair values of our other financial instruments as of March 31, 2013 and December 31, 2012 (in thousands):

	March 31, 2013				December 31, 2012
	Carrying   Amount		Fair Value		Carrying   Amount		Fair Value
Current Asset(1)
Cash and cash equivalents	$	54,270	$	54,270	$	180,565	$	180,565
Current Liability
Deferred premium and accrued interest on derivative contracts(2)		111,186		111,186		70,831		70,831
Current maturities of long-term debt(3)		164,288		164,288		164,288		164,288
Non-Current Liability(2)
Deferred premium and accrued interest on derivative contracts		383,633		383,633		440,424		440,424
Long-Term Debt(3)
Amended Credit Facility
Revolving line of credit		1,325,200		1,325,200		1,570,000		1,570,000
Five-year term loan		656,537		656,537		655,638		655,638
Seven-year term loan		1,132,463		1,132,463		1,131,556		1,131,556
Plains Offshore senior credit facility		-		-		-		-
10% Senior Notes		-		-		177,266		188,788
7 5/8% Senior Notes due 2018		400,000		418,000		400,000		421,000
6 1/8% Senior Notes		750,000		821,250		750,000		817,500
8 5/8% Senior Notes		395,047		448,378		394,909		449,209
7 5/8% Senior Notes due 2020		300,000		338,250		300,000		334,500
6 1/2% Senior Notes		1,500,000		1,657,500		1,500,000		1,661,250
6 5/8% Senior Notes		600,000		660,000		600,000		660,750
6 3/4% Senior Notes		1,000,000		1,113,750		1,000,000		1,122,500
6 7/8% Senior Notes		1,500,000		1,698,750		1,500,000		1,713,750

(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 revolving line of credit and term loans, including current portion, approximate fair value, as interest rates are variable, based on prevailing market rates. Our revolving line of credit and term loans 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.

23

Note 8 — Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items which are recorded in the period that the specific item occurs. For the three months ended March 31, 2013, our income tax expense was approximately 39% of pre-tax income. The variance in our estimated annual effective tax rate from the 35% federal statutory rate primarily results from the tax effects of estimated annual permanent differences, including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.

Note 9 — Commitments and Contingencies

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.

In California, the California Air Resources Board, or CARB, has developed regulations pursuant to the Global Warming Solutions Act of 2006, or Assembly Bill 32, that are intended to achieve an overall reduction in greenhouse gas emissions to 1990 levels, a 15% reduction by 2020. Because several of our operations emit greenhouse gases in excess of 25,000 metric tons per year, various operations in California are subject to the requirements of this program. In October 2011 CARB adopted the final Cap and Trade regulation which is intended to implement the Cap and Trade Program under Assembly Bill 32. Compliance with these regulations will require companies to periodically secure instruments known as offsets and allowances, each of which is equal to one metric ton of emissions under the Cap and Trade program. The price of these instruments will vary in accordance with market conditions. The total amount of instruments we owe will vary based on the total greenhouse gas emissions registered in any one year and the number of “free allowances” issued by CARB annually. In 2011 our California properties subject to regulation under Assembly Bill 32 emitted 955,000 metric tons of greenhouse gas emissions. In 2012 we were issued 644,000 free allowances by CARB based on estimated emissions using our 2011 verified emissions data. Based on these figures we will be required to secure an estimated 311,000 instruments to meet our 2013 obligations by the end of the first compliance period.

During the three months ended March 31, 2013, we acquired 111,000 allowances at a weighted average price of $14.00 per allowance. The cost of these allowances is recorded as indefinite life intangible assets within other non-current assets on our balance sheet. We have elected to expense the cost of the allowances when the allowances are submitted to the state. We test the allowances annually at December 31 for impairment. Cash payments related to the allowances are classified as investing activities in the statement of cash flows.

24

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 platforms, 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 and facilities 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, $75.6 million ($151.3 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 March 31, 2013, the escrow account had a balance of $23.9 million. The fair value of our guarantee at March 31, 2013, $0.3 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in our balance sheet.

Operating Risks and Insurance Coverage.    Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, oil spills, releases of gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. 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.

Offshore Morocco Exploration.In January 2013, we announced we entered into a definitive agreement to participate in an exploration program offshore the Kingdom of Morocco. Subject to customary closing conditions, including the receipt of Moroccan governmental approvals (expected in 2013), we will make a cash payment of $15.0 million to farm-in to Pura Vida Energy’s 75% working interest in the approximate 2.7 million acre Mazagan permit area in the Essaouira Basin offshore Morocco. We will earn a 52% working interest and act as operator in exchange for funding 100% of the costs of certain specified exploration activities that will include a commitment to fund and drill two wells, and if agreed, various additional exploration operations subject to a maximum of $215.0 million. The first exploration well is expected to be drilled in 2014.

25

Firm Delivery Commitments.    We have oil production volume delivery commitments. If we are unable to meet the commitments to deliver this production, our maximum financial commitment at March 31, 2013 would be $48.9 million over the remaining contract term. We currently have sufficient reserves and production capacity to fulfill this commitment. In March 2013, we were producing 13.1 MBbls per day at these properties. As of March 31, 2013, our delivery commitments for the next five years and thereafter were as follows:

	Oil
	(MBbl)
2013		2,568
2014		4,473
2015		5,475
2016		5,490
2017		5,010
Thereafter		-
		23,016

Shareholder Class Actions.    Beginning on December 5, 2012, 27 purported shareholder class actions were filed challenging the merger of PXP with Freeport-McMoRan and the MMR Merger. The lawsuits were filed against PXP, Freeport-McMoRan and McMoRan and the boards of these companies as well as certain other named individuals. The shareholder class actions generally allege that the boards of these companies breached fiduciary duties and adversely affected shareholders by approving the merger and the MMR Merger. We believe these purported shareholder class actions are without merit and we intend to defend against them vigorously.

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 and gas. 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.

Subsequent Event

Drillship Commitments.In April 2013, we executed two drilling contracts with an affiliate of Noble Corporation for the Noble Sam Croft and Noble Tom Madden, both of which are new-build drillships that will support our deepwater Gulf of Mexico drilling activity. The drilling contracts for the Noble Sam Croft and the Noble Tom Madden each provide for a firm three-year commitment, expected to begin in the fourth quarter of 2014 and first quarter of 2015, respectively, at rates of approximately $0.6 million per day. Such rates are subject to standard reimbursement and contractual escalation provisions. The drilling contracts each further require us to pay approximately $24.0 million for mobilization.

26

Note 10 — Consolidating Financial Statements

We are the issuer of $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, $1.5 billion 6 ¹/₂% Senior Notes, $600 million 6 ⁵/₈% Senior Notes, $1 billion 6 ³/₄% Senior Notes and $1.5 billion 6 ⁷/₈% Senior Notes as of March 31, 2013, which are jointly and severally guaranteed by certain of our existing domestic subsidiaries (referred to as “Guarantor Subsidiaries”). In the future, a subsidiary guarantor’s guarantee 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 that 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 that subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as that subsidiary guarantor does not have outstanding any guarantee of any of our or any of our other subsidiary guarantors’ 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”).

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.

27

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

MARCH 31, 2013

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	62	$	-	$	54,208	$	-	$	54,270
Accounts receivable and other current assets		1,315,189		387,928		2,798		-		1,705,915
		1,315,251		387,928		57,006		-		1,760,185
Property and Equipment, at cost
Oil and natural gas properties - full cost method		6,123,584		15,203,655		1,609,889		-		22,937,128
Other property and equipment		61,011		48,093		55,786		-		164,890
		6,184,595		15,251,748		1,665,675		-		23,102,018
Less allowance for depreciation, depletion, amortization and impairment		(2,919,056)		(8,060,857)		(999,710)		3,586,867		(8,392,756)
		3,265,539		7,190,891		665,965		3,586,867		14,709,262
Investment in and Advances to Affiliates		10,048,880		(5,311,018)		(116,092)		(4,621,770)		-
Other Assets		164,758		587,461		11,199		(42,491)		720,927
	$	14,794,428	$	2,855,262	$	618,078	$	(1,077,394)	$	17,190,374
LIABILITIES AND EQUITY
Current Liabilities	$	871,437	$	109,895	$	88,119	$	-	$	1,069,451
Long-Term Debt		9,559,247		-		-		-		9,559,247
Other Long-Term Liabilities		348,015		366,253		1,085		-		715,353
Deferred Income Taxes		475,506		(52,161)		32,267		1,408,066		1,863,678
Equity
Stockholders’ equity		3,540,223		2,431,275		54,185		(2,485,460)		3,540,223
Noncontrolling interest Preferred stock of subsidiary		-		-		442,422		-		442,422
		3,540,223		2,431,275		496,607		(2,485,460)		3,982,645
	$	14,794,428	$	2,855,262	$	618,078	$	(1,077,394)	$	17,190,374

28

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2012

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	11,722	$	-	$	168,843	$	-	$	180,565
Accounts receivable and other current assets		1,349,806		305,702		3,657		-		1,659,165
		1,361,528		305,702		172,500		-		1,839,730
Property and Equipment, at cost
Oil and natural gas properties - full cost method		5,801,258		15,167,966		1,476,588		-		22,445,812
Other property and equipment		56,618		42,162		54,564		-		153,344
		5,857,876		15,210,128		1,531,152		-		22,599,156
Less allowance for depreciation, depletion, amortization and impairment		(2,757,630)		(7,803,206)		(999,711)		3,690,191		(7,870,356)
		3,100,246		7,406,922		531,441		3,690,191		14,728,800
Investment in and Advances to Affiliates		10,326,671		(5,503,149)		(99,206)		(4,724,316)		-
Other Assets		173,680		587,927		11,861		(43,715)		729,753
	$	14,962,125	$	2,797,402	$	616,596	$	(1,077,840)	$	17,298,283
LIABILITIES AND EQUITY
Current Liabilities	$	807,820	$	95,876	$	76,305	$	-	$	980,001
Long-Term Debt		9,979,369		-		-		-		9,979,369
Other Long-Term Liabilities		250,684		360,153		1,067		-		611,904
Deferred Income Taxes		407,774		(6,658)		32,992		1,336,460		1,770,568
Equity
Stockholders’ equity		3,516,478		2,348,031		66,269		(2,414,300)		3,516,478
Noncontrolling interest Preferred stock of subsidiary		-		-		439,963		-		439,963
		3,516,478		2,348,031		506,232		(2,414,300)		3,956,441
	$	14,962,125	$	2,797,402	$	616,596	$	(1,077,840)	$	17,298,283

29

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED MARCH 31, 2013

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	621,719	$	536,719	$	-	$	-	$	1,158,438
Gas sales		14,180		58,151		-		-		72,331
Other operating revenues		136		1,210		-		-		1,346
		636,035		596,080		-		-		1,232,115
Costs and Expenses
Production costs		138,649		107,937		557		-		247,143
General and administrative		27,690		16,260		2,014		-		45,964
Depreciation, depletion, amortization and accretion		172,319		264,692		140		103,324		540,475
Other operating expense		1,196		-		-		-		1,196
		339,854		388,889		2,711		103,324		834,778
Income (Loss) from Operations		296,181		207,191		(2,711)		(103,324)		397,337
Other Income (Expense)
Equity in earnings of subsidiaries		4,124		-		-		(4,124)		-
Interest expense		(62,595)		(76,632)		(1,771)		-		(140,998)
Debt extinguishment costs		(18,053)		-		-		-		(18,053)
Loss on mark-to-market derivative contracts		(202,023)		-		-		-		(202,023)
Gain on investment measured at fair value		15,544		-		-		-		15,544
Other income		336		54		5		-		395
Income (Loss) Before Income Taxes		33,514		130,613		(4,477)		(107,448)		52,202
Income tax (expense) benefit		(10,929)		(47,369)		1,602		36,288		(20,408)
Net Income (Loss)		22,585		83,244		(2,875)		(71,160)		31,794
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		-		-		(9,209)		-		(9,209)
Net Income (Loss) Attributable to Common Stockholders	$	22,585	$	83,244	$	(12,084)	$	(71,160)	$	22,585

30

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED MARCH 31, 2012

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	436,363	$	31,125	$	-	$	-	$	467,488
Gas sales		5,377		48,147		-		-		53,524
Other operating revenues		513		2,750		-		-		3,263
		442,253		82,022		-		-		524,275
Costs and Expenses
Production costs		99,929		34,267		211		-		134,407
General and administrative		25,796		10,593		1,993		-		38,382
Depreciation, depletion, amortization and accretion		76,032		44,223		133		61,062		181,450
Impairment of oil and gas properties		-		883,635		-		(883,635)		-
Other operating income		-		(1,261)		-		-		(1,261)
		201,757		971,457		2,337		(822,573)		352,978
Income (Loss) from Operations		240,496		(889,435)		(2,337)		822,573		171,297
Other (Expense) Income
Equity in earnings of subsidiaries		(80,069)		-		-		80,069		-
Interest expense		(25)		(44,021)		(1,207)		-		(45,253)
Loss on mark-to-market derivative contracts		(109,050)		-		-		-		(109,050)
Loss on investment measured at fair value		(135,930)		-		-		-		(135,930)
Other (expense) income		(550)		133		12		-		(405)
Loss Before Income Taxes		(85,128)		(933,323)		(3,532)		902,642		(119,341)
Income tax benefit		2,809		350,359		1,258		(308,388)		46,038
Net Loss		(82,319)		(582,964)		(2,274)		594,254		(73,303)
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		-		-		(9,016)		-		(9,016)
Net Loss Attributable to Common Stockholders	$	(82,319)	$	(582,964)	$	(11,290)	$	594,254	$	(82,319)

31

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

THREE MONTHS ENDED MARCH 31, 2013

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	22,585		$	83,244		$	(2,875	)	$	(71,160	)	$	31,794
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		172,319			264,692			140			103,324			540,475
Equity in earnings of subsidiaries		(4,124	)		-			-			4,124			-
Deferred income tax (benefit) expense		(9,485	)		(44,555	)		(725	)		70,383			15,618
Debt extinguishment costs		(4,903	)		-			-			-			(4,903	)
Loss on mark-to-market derivative contracts		202,023			-			-			-			202,023
Gain on investment measured at fair value		(15,544	)		-			-			-			(15,544	)
Non-cash compensation		9,632			3,864			-			-			13,496
Other non-cash items		2,706			-			-			-			2,706
Change in assets and liabilities from operating activities
Accounts receivable and other assets		86,875			(83,415	)		1,397			-			4,857
Accounts payable and other liabilities		17,701			10,753			(4,684	)		-			23,770
Income taxes receivable/payable		4,431			-			-			-			4,431
Net cash provided by (used in) operating activities		484,216			234,583			(6,747	)		106,671			818,723
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(334,359	)		(31,116	)		(102,262	)		-			(467,737	)
Acquisition of oil and gas properties		(14,206	)		(3,001	)		(14,541	)		-			(31,748	)
Derivative settlements		(13,516	)		-			-			-			(13,516	)
Other		(5,074	)		(2,294	)		(1,222	)		-			(8,590	)
Net cash used in investing activities		(367,155	)		(36,411	)		(118,025	)		-			(521,591	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		3,328,700			-			-			-			3,328,700
Repayments of revolving credit facilities		(3,573,500	)		-			-			-			(3,573,500	)
Principal payments of long-term debt		(171,180	)		-			-			-			(171,180	)
Costs incurred in connection with financing arrangements		(697	)		-			-			-			(697	)
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-			-			(6,750	)		-			(6,750	)
Investment in and advances to affiliates		287,956			(198,172	)		16,887			(106,671	)		-
Net cash (used in) provided by financing activities		(128,721	)		(198,172	)		10,137			(106,671	)		(423,427	)
Net decrease in cash and cash equivalents		(11,660	)		-			(114,635	)		-			(126,295	)
Cash and cash equivalents, beginning of period		11,722			-			168,843			-			180,565
Cash and cash equivalents, end of period	$	62		$	-		$	54,208		$	-		$	54,270

32

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

THREE MONTHS ENDED MARCH 31, 2012

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(82,319	)	$	(582,964	)	$	(2,274	)	$	594,254		$	(73,303	)
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		76,032			927,858			133			(822,573	)		181,450
Equity in earnings of subsidiaries		80,069			-			-			(80,069	)		-
Deferred income tax benefit		(2,586	)		(349,002	)		(1,258	)		306,789			(46,057	)
Loss on mark-to-market derivative contracts		109,050			-			-			-			109,050
Loss on investment measured at fair value		135,930			-			-			-			135,930
Non-cash compensation		14,738			3,494			-			-			18,232
Other non-cash items		1,039			382			-			-			1,421
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(43,705	)		54,072			(5,510	)		-			4,857
Accounts payable and other liabilities		22,265			(20,857	)		(6,746	)		-			(5,338	)
Income taxes receivable/payable		9,169			-			-			-			9,169
Net cash provided by (used in) operating activities		319,682			32,983			(15,655	)		(1,599	)		335,411
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(272,542	)		(102,074	)		(26,695	)		-			(401,311	)
Acquisition of oil and gas properties		(3,793	)		-			(12,780	)		-			(16,573	)
Proceeds from sales of oil and gas properties, net of costs and expenses		42,656			-			-			-			42,656
Derivative settlements		9,321			-			-			-			9,321
Additions to other property and equipment		(1,896	)		-			(1,008	)		-			(2,904	)
Net cash used in investing activities		(226,254	)		(102,074	)		(40,483	)		-			(368,811	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		2,515,500			-			-			-			2,515,500
Repayments of revolving credit facilities		(2,440,500	)		-			-			-			(2,440,500	)
Costs incurred in connection with financing arrangements		(125	)		-			-			-			(125	)
Purchase of treasury stock		(88,490	)		-			-			-			(88,490	)
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-			-			(6,750	)		-			(6,750	)
Investment in and advances to affiliates		(72,251	)		69,085			1,567			1,599			-
Net cash (used in) provided by financing activities		(85,866	)		69,085			(5,183	)		1,599			(20,365	)
Net increase (decrease) in cash and cash equivalents		7,562			(6	)		(61,321	)		-			(53,765	)
Cash and cash equivalents, beginning of period		3,189			6			415,903			-			419,098
Cash and cash equivalents, end of period	$	10,751		$	-		$	354,582		$	-		$	365,333

33

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, 2012.

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 primarily located in the United States. We own oil and gas properties with principal operations in:

• Onshore California;

• Offshore California;

• the Gulf of Mexico;

• the Gulf Coast Region; and

• the Rocky Mountains.

We have also entered into a definitive agreement to participate in an exploration program offshore the Kingdom of Morocco, which is subject to customary closing conditions, including the receipt of Moroccan government approvals.

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 the Eagle Ford Shale, Gulf of Mexico, California and the Haynesville Shale. Our primary sources of liquidity are cash generated from our operations, our revolving line of credit and periodic public offerings of debt and equity.

Our assets include 51.0 million shares of McMoRan common stock, approximately 31.3% 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 contracts and subjects us to the credit risk of the counterparties to such contracts. 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.

34

Recent Developments

Proposed Merger with Freeport-McMoRan

On December 5, 2012, we entered into the Freeport-McMoRan Merger Agreement with Freeport-McMoRan and the Merger Sub, pursuant to which Freeport-McMoRan will acquire PXP for approximately $6.9 billion in cash and stock, based on the closing price of Freeport-McMoRan stock on December 4, 2012.

The Freeport-McMoRan Merger Agreement provides that PXP will merge with and into the Merger Sub, with the Merger Sub continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. Subject to the terms and conditions of the Freeport-McMoRan Merger Agreement, PXP stockholders have the right to receive 0.6531 shares of Freeport-McMoRan common stock and $25.00 in cash, equivalent to total consideration of $50.00 per PXP share, based on the closing price of Freeport-McMoRan stock on December 4, 2012. PXP stockholders may elect to receive cash or stock consideration, subject to proration in the event of oversubscription, with the value of the cash and stock per share consideration to be equalized at closing.

The Freeport-McMoRan Merger Agreement provides that each share of restricted stock and each stock-settled RSU that has been granted or contractually promised by PXP as of the date of the Freeport-McMoRan Merger Agreement and that is outstanding immediately prior to or upon the effective time of the merger, including each stock-settled RSU that will become issuable or creditable in connection with the consummation of the merger pursuant to any employment agreement, RSU agreement or other written agreement, will become fully vested and be converted into the right to receive, at the election of the holder, cash consideration or stock consideration, except for certain stock-settled RSUs held by PXP’s named executive vice presidents that will convert into stock consideration (with right to elect up to 25% as cash consideration), and certain stock-settled RSUs held by Mr. Flores that will automatically convert into stock consideration, in each case pursuant to the terms of the executive’s respective letter agreement among each named executive officer, Freeport-McMoRan and PXP. Each cash-settled RSU that has been granted or contractually promised by PXP as of the date of the Freeport-McMoRan Merger Agreement and that is outstanding immediately prior to or upon the effective time of the merger will become fully vested in accordance with the terms of the applicable award agreement and be converted into the right to receive cash consideration, payable at such time as the cash per-share consideration is payable generally to PXP stockholders who elect to receive cash consideration. SARs relating to shares of PXP common stock outstanding and unexercised that have been granted or contractually promised by PXP as of the date of the Freeport-McMoRan Merger Agreement and that are outstanding immediately prior to or upon the effective time of the merger will become fully vested and be converted into SARs relating to shares of Freeport-McMoRan common stock. All restricted stock, stock-settled RSUs, cash-settled RSUs and SARs granted or issued by PXP after the date of the Freeport-McMoRan Merger Agreement and prior to the merger will be converted into the same type of award covering shares of Freeport-McMoRan pursuant to the formula set forth in the Freeport-McMoRan Merger Agreement, with the same terms and conditions as prior to the completion of the merger.

The Freeport-McMoRan Merger Agreement provides that, upon termination of the Freeport-McMoRan Merger Agreement under certain circumstances, PXP may be required to reimburse Freeport-McMoRan for its expenses in an amount up to $69.0 million and/or pay Freeport-McMoRan a termination fee in an amount equal to $207.0 million less any expenses reimbursed by PXP.

35

Completion of the merger is subject to customary conditions, including approval by PXP stockholders and receipt of required regulatory approvals. PXP will hold a special meeting of its stockholders on May 20, 2013 to vote on the merger. The merger is expected to close in the second quarter of 2013.

On December 5, 2012, Freeport-McMoRan entered into the MMR Merger Agreement with McMoRan and the MMR Merger Sub, pursuant to the MMR Merger, with McMoRan continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. The per share consideration consists of $14.75 in cash and 1.15 units of a royalty trust, which will hold a 5% overriding royalty interest in future production from McMoRan’s existing ultra-deep exploration properties. In connection with the MMR Merger, on December 5, 2012, PXP and Freeport-McMoRan entered into the Support Agreement. The Support Agreement generally requires that PXP, in its capacity as a stockholder of 31.3% of McMoRan, vote all of its shares of McMoRan common stock in favor of the MMR Merger and against alternative transactions and generally prohibits us from transferring our shares of McMoRan common stock prior to the consummation of the MMR Merger. The Support Agreement will terminate upon the earlier of (i) the Expiration Date (defined as the earlier of (A) the consummation of the MMR Merger and (B) the termination of the MMR Merger Agreement) and (ii) any breach by Freeport-McMoRan of its obligation under the Freeport-McMoRan Merger Agreement not to change the merger consideration in the MMR Merger Agreement, amend the covenant relating to standstill waivers in the MMR Merger Agreement or otherwise materially amend any material provision of the MMR Merger Agreement, or terminate the MMR Merger Agreement, without PXP’s prior written consent. The MMR Merger is subject to the approval of the shareholders of McMoRan, including the approval of an amendment to McMoRan’s certificate of incorporation, receipt of regulatory approvals and customary closing conditions.

Offshore Morocco Exploration

In January 2013, we announced we entered into a definitive agreement to participate in an exploration program offshore the Kingdom of Morocco. Subject to customary closing conditions, including the receipt of Moroccan governmental approvals (expected in 2013), we will make a cash payment of $15.0 million to farm-in to Pura Vida Energy’s 75% working interest in the approximate 2.7 million acre Mazagan permit area in the Essaouira Basin offshore Morocco. We will earn a 52% working interest and act as operator in exchange for funding 100% of the costs of certain specified exploration activities that will include a commitment to fund and drill two wells, and if agreed, various additional exploration operations subject to a maximum of $215.0 million. The first exploration well is expected to be drilled in 2014.

Gulf of Mexico Lease Sale

In March 2013, we participated in the Gulf of Mexico Outer Continental Shelf Lease Sale 227 held by the Bureau of Ocean Energy Management and were the apparent high bidder on 11 deepwater blocks. The sum of our high bids was approximately $82.6 million.

Drillship Commitments

In April 2013, we executed two drilling contracts with an affiliate of Noble Corporation for the Noble Sam Croft and Noble Tom Madden, both of which are new-build drillships that will support our deepwater Gulf of Mexico drilling activity. The drilling contracts for the Noble Sam Croft and the Noble Tom Madden each provide for a firm three-year commitment, expected to begin in the fourth quarter of 2014 and first quarter of 2015, respectively, at rates of approximately $0.6 million per day. Such rates are subject to standard reimbursement and contractual escalation provisions. The drilling contracts each further require us to pay approximately $24.0 million for mobilization.

36

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 March 31, 2013, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 21%.

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

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities (including stock-based compensation), steam gas costs, electricity costs, maintenance costs, production, ad valorem and severance taxes, gathering and transportation costs and other costs necessary to operate our producing properties. Depreciation, depletion and amortization, or 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 three months ended March 31, 2013, we reported net income attributable to common stockholders of $22.6 million, or $0.17 per diluted share, compared to net loss attributable to common stockholders of $82.3 million, or $0.64 per diluted share, for the three months ended March 31, 2012. The increase primarily reflects higher oil revenues and a gain on our investment in McMoRan measured at fair value in 2013 compared to a loss in 2012, partially offset by increased DD&A. Significant transactions that affect comparisons between the periods include the Gulf of Mexico Acquisition in the fourth quarter of 2012.

37

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
	March 31,
	2013		2012
Sales Volumes
Oil and liquids sales (MBbls)		11,631		4,519
Gas (MMcf)
Production		22,504		21,294
Used as fuel		283		428
Sales		22,221		20,866
MBOE
Production		15,382		8,068
Sales		15,335		7,996
Daily Average Volumes
Oil and liquids sales (Bbls)		129,233		49,657
Gas (Mcf)
Production		250,044		234,001
Used as fuel		3,140		4,705
Sales		246,904		229,296
BOE
Production		170,907		88,657
Sales		170,384		87,873
Unit Economics (in dollars)
Average Index Prices
ICE Brent Price per Bbl	$	112.60	$	118.42
NYMEX Price per Bbl		94.36		103.03
NYMEX Price per Mcf		3.34		2.73
Average Realized Sales Price
Before Derivative Transactions
Oil (per Bbl)	$	99.60	$	103.45
Gas (per Mcf)		3.25		2.56
Per BOE		80.26		65.16
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	11.10	$	10.38
Steam gas costs		0.95		1.39
Electricity		0.72		1.42
Production and ad valorem taxes		1.87		1.58
Gathering and transportation		1.47		2.03
DD&A (oil and gas properties)		33.81		21.64

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

	Three Months Ended
	March 31,
	2013		2012
Oil derivatives	$	(22,741)	$	(5,856)
Natural gas derivatives		9,225		15,177
	$	(13,516)	$	9,321

38

Comparison of Three Months Ended March 31, 2013 to Three Months Ended March 31, 2012

Oil and gas revenues.     Oil and gas revenues increased $709.8 million, to $1,230.8 million for 2013 from $521.0 million for 2012, primarily due to higher oil sales volumes and average realized gas prices partially offset by lower average realized oil prices.

Oil revenues increased $690.9 million, to $1,158.4 million for 2013 from $467.5 million for 2012, reflecting higher sales volumes ($708.3 million) partially offset by lower average realized prices ($17.4 million). Oil sales volumes increased 79.5 MBbls per day to 129.2 MBbls per day in 2013 from 49.7 MBbls per day in 2012, primarily reflecting increased production from our Gulf of Mexico Acquisition and our Eagle Ford Shale properties. Our average realized price for oil decreased $3.85 per Bbl to $99.60 per Bbl for 2013 from $103.45 per Bbl for 2012. The decrease was primarily attributable to a decrease in the oil price indices; as an example, ICE Brent averaged $112.60 per Bbl in 2013 versus $118.42 per Bbl in 2012.

Gas revenues increased $18.8 million, to $72.3 million in 2013 from $53.5 million in 2012, primarily reflecting higher average realized prices ($14.4 million) and sales volumes ($4.4 million). Our average realized price for gas was $3.25 per Mcf in 2013 compared to $2.56 per Mcf in 2012. The increase was primarily attributable to an increase in the NYMEX gas price, which averaged $3.34 per Mcf in 2013 versus $2.73 per Mcf in 2012. Gas sales volumes increased 17.6 MMcf per day to 246.9 MMcf per day in 2013 from 229.3 MMcf per day in 2012, primarily reflecting increased production from our Gulf of Mexico Acquisition and our Eagle Ford Shale properties, partially offset by decreased production from our Haynesville Shale properties.

We have been notified that the Pascagoula Gas Processing Plant, located in Pascagoula, Mississippi, operated by BP America Corporation and responsible for processing production from wells in the eastern corridor of the deepwater Gulf of Mexico, will shut down for approximately 36 days starting on or about May 3, 2013 during which time required maintenance will be performed. This activity will disrupt processing system-wide from several operators, including us. The Horn Mountain platform and Marlin Hub, both operated by us, will be impacted by the work at the gas processing plant. We hold a 100% working interest in the Horn Mountain and Marlin Fields. Oil and gas production could be shut-in while the gas processing plant undergoes its required maintenance. Our net average daily sales volumes from these fields were 44.0 MBOE per day in the first quarter of 2013.

Lease operating expenses.     Lease operating expenses increased $87.2 million, to $170.2 million in 2013 from $83.0 million in 2012, reflecting increased production from our Gulf of Mexico Acquisition and our Eagle Ford Shale properties.

Steam gas costs.     Steam gas costs increased $3.5 million, to $14.6 million in 2013 from $11.1 million in 2012, primarily reflecting higher cost of gas and volumes used in steam generation. In 2013, we burned approximately 4.2 Bcf of natural gas at a cost of approximately $3.48 per MMBtu compared to 4.0 Bcf at a cost of approximately $2.77 per MMBtu in 2012.

Production and ad valorem taxes.     Production and ad valorem taxes increased $16.0 million, to $28.6 million in 2013 from $12.6 million in 2012, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties.

Gathering and transportation expenses.     Gathering and transportation expenses increased $6.3 million, to $22.6 million in 2013 from $16.3 million in 2012, primarily reflecting increased production from our Gulf of Mexico Acquisition.

39

General and administrative expense.    G&A expense increased $7.6 million, to $46.0 million in 2013 from $38.4 million in 2012, primarily due to increased headcount and related personnel costs and costs associated with the proposed merger with Freeport-McMoRan.

Depreciation, depletion and amortization.     DD&A expense increased $352.8 million, to $530.5 million in 2013 from $177.7 million in 2012. The increase is attributable to our oil and gas depletion, primarily due to increased production ($247.3 million) and a higher per unit rate ($98.2 million). Our oil and gas unit of production rate was $33.81 per BOE in 2013 compared to $21.64 per BOE in 2012.

Interest expense.     Interest expense increased $95.7 million, to $141.0 million in 2013 from $45.3 million in 2012, primarily due to greater average debt outstanding and a decrease in interest capitalized, 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 $7.0 million and $17.1 million of interest in 2013 and 2012, respectively. The decreased capitalized interest is primarily attributable to reduced exploration activity associated with certain unevaluated oil and gas properties in 2013.

Debt extinguishment costs.We recognized $18.1 million of debt extinguishment costs in connection with the redemption of the remaining aggregate principal amount of our 10% Senior Notes in the three months ended March 31, 2013.

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 $202.0 million loss related to mark-to-market derivative contracts in the three months ended March 31, 2013, which was primarily associated with decreases in the fair value of our crude oil and natural gas derivative contracts due to increases in forward prices and decreases in volatilities. In the three months ended March 31, 2012, we recognized a $109.1 million loss related to mark-to-market derivative contracts.

Gain (loss) on investment measured at fair value.     At March 31, 2013, 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 $15.5 million gain in the three months ended March 31, 2013 related to our McMoRan investment, which was primarily associated with an increase in McMoRan’s stock price. In the three months ended March 31, 2012, we recognized a $135.9 million loss related to our McMoRan investment.

Income taxes.    For the three months ended March 31, 2013, our income tax expense was approximately 39% of pre-tax income. For the three months ended March 31, 2012, our income tax benefit was approximately 39% of pre-tax loss. The variance between these effective tax rates and the 35% federal statutory rate primarily 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. In addition, specific items affecting our income tax benefit for the first quarter of 2012 included changes to our balance of unrecognized tax benefits.

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 capital and credit markets may adversely affect the financial condition of lenders in our revolving line of credit, 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. In addition, new proposed regulations may require us to comply with certain margin requirements for our derivative contracts that could require us to enter into credit support documentation or post significant amounts of cash collateral. These market and regulatory 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 revolving line of credit and periodic public offerings of debt and equity. At March 31, 2013, we had approximately $1.5 billion available for future secured borrowings under our revolving line of credit. At March 31, 2013, Plains Offshore had $300 million available for future secured borrowings under its senior credit facility.

Under the terms of our Amended Credit Facility, the borrowing base is redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Declines in oil and gas prices may adversely affect our liquidity by lowering the amount of the borrowing base that lenders are willing to extend.

The commitments of each lender to make loans to us are several and not joint under our revolving line of credit. 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 revolving line of credit. At March 31, 2013, the commitments under our revolving line of credit are from a diverse syndicate of 24 lenders and no single lender’s commitment represented more than 7% of the total commitments.

Our cash flows depend on many factors, including the price of oil and gas, the success of our 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 contracts and subjects us to the credit risk of the counterparties to such contracts. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. We plan to enter into derivative instruments for up to 90% of our crude oil production through 2015 to lock in cash flows and to provide downside commodity price protection through the use of swap contracts, three-way collars and put option spread contracts. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.

Production from our Gulf of Mexico Acquisition, continued growth from our onshore oil assets and volumes from the Lucius oil field in the deepwater Gulf of Mexico forecasted to come online in 2014 are expected to generate cash flow in excess of our capital expenditures and such excess cash flow may be applied to reduce debt over the next several years.

41

Our 2013 capital budget is expected to be approximately $2.1 billion, including capitalized interest and general and administrative expenses. We intend to fund our 2013 capital budget from internally generated funds and borrowings under our revolving line of credit, with the portion of our 2013 budget related to Plains Offshore being funded with cash on hand and the Plains Offshore senior credit facility. 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 revolving line of credit, 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.

Working Capital

At March 31, 2013, we had working capital of approximately $690.7 million, primarily due to the current asset classification of our investment in the McMoRan common shares. 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

Amended Credit Facility.    In November 2012, we entered into the Amended Credit Agreement, which amended and restated our senior revolving credit facility. The Amended Credit Agreement provided for (i) a five-year revolving line of credit, a five-year term loan and a seven-year term loan and (ii) an initial borrowing base of $5.175 billion, which will be redetermined on an annual basis, with us and the lenders of the revolving line of credit each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness (including the outstanding commitments under the credit agreement dated November 18, 2011 among Plains Offshore, JPMorgan Chase Bank, N.A. as administrative agent and the lenders party thereto from time to time) and other factors. Our next redetermination will occur on or before September 5, 2013.

Revolving Line of Credit.    The aggregate commitments of the lenders under the revolving line of credit are $3.0 billion and can be increased to $3.6 billion if certain conditions are met. We are required, among other things, to make a mandatory prepayment if the combined total borrowings under our Amended Credit Facility and the Plains Offshore senior credit facility exceed the borrowing base. Additionally, our revolving line of credit contains a $750 million sub limit on letters of credit and a $100 million sub limit for swingline loans and matures on November 30, 2017. At March 31, 2013, we had $2.9 million in letters of credit outstanding under our revolving line of credit. The daily average outstanding balance of our revolving line of credit for the three months ended March 31, 2013 was $1.4 billion.

Amounts borrowed under our revolving line of credit 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 ABR, which is the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, N.A., (2) the federal funds rate, plus0.50%, and (3) the adjusted one-month 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 Eurodollar rate and the ABR will be increased 0.25% while any term loans are outstanding. The additional variable amount of interest payable is based on the utilization rate as a percentage of the total amount of funds borrowed under our Amended Credit Facility and the Plains Offshore senior credit facility to the borrowing base. Letter of credit fees under our revolving line of credit are based on the utilization rate and range from 1.50% to 2.50% and will be increased by 0.25% while any term loans are outstanding. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing.

42

Five-Year Term Loan and Seven-Year Term Loan.    The Amended Credit Agreement provided for the $750.0 million five-year term loan due 2017 and the $1.25 billion seven-year term loan due 2019. The term loans bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus 3.00% or (ii) 2.00% plus the ABR, which is the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, N.A., (2) the federal funds rate, plus 0.50%, and (3) the adjusted one-month LIBOR plus 1.00%. In no event can LIBOR for the seven-year term loan be less than 1.00% per year. The five-year term loan is payable in four annual installments each equal to 10% of the original principal balance due and payable on the last business day of December beginning on December 31, 2013 and the remaining balance due on its five-year maturity on November 30, 2017. The seven-year term loan is payable in six annual installments each equal to 7.143% of the original principal balance due and payable on the last business day of December beginning on December 31, 2013 and the remaining balance due on its seven-year maturity on November 30, 2019. The current portion of the five-year term loan and seven-year term loan is $75.0 million and $89.3 million, respectively, at March 31, 2013.

Our Amended 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 Amended 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 or guarantee other indebtedness, 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, sell certain assets including capital stock of subsidiaries, 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 March 31, 2013, Plains Offshore had no borrowings or letters of credit outstanding under its senior credit facility. We anticipate that Plains Offshore will begin to borrow under its senior credit facility during the second quarter of 2013.

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, N.A., (2) the federal funds rate, plus 0.50%, and (3) the adjusted LIBOR plus 1.00%. The additional variable amount of interest payable is based on the utilization rate as a percentage of the total amount of funds borrowed under both our revolving line of credit and the Plains Offshore senior credit facility and the borrowing base under our Amended 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.

43

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 apari passu basis by liens on the same collateral that secures PXP’s Amended 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 Amended Credit Facility. If an event of default (as defined in our Amended Credit Facility) has occurred and is continuing under our Amended 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 a 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 revolving line of credit. At March 31, 2013, we had $0.2 million outstanding under the short-term facility which we have included in long-term borrowings as we intend and have the ability to pay this balance with borrowings under the revolving line of credit. The daily average outstanding balance for the three months ended March 31, 2013 was $44.5 million.

Redemption of 10% Senior Notes.    During the first quarter of 2013, we redeemed the remaining $184.9 million aggregate principal amount of our 10% Senior Notes at 105% of the principal amount. We made payments totaling $194.1 million to retire the 10% Senior Notes. During the three months ended March 31, 2013, we recognized $18.1 million of debt extinguishment costs, including $8.8 million of unamortized original issue discount and debt issue costs in connection with the retirement of these Senior Notes.

Redemption of 7 ⁵/₈% Senior Notes due 2018.    On May 1, 2013, our Board of Directors approved the call for redemption of the $400 million aggregate principal amount of our outstanding 7 ⁵/₈% Senior Notes due 2018 at 103.813% of the principal amount. We expect to make payments totaling $415.3 million to retire the 7 ⁵/₈% Senior Notes due 2018 in June 2013. We expect to recognize approximately $18.1 million of debt extinguishment costs, including $2.8 million of unamortized debt issue costs upon retirement of these Senior Notes.

44

Cash Flows

	Three Months Ended March 31,
	2013		2012
	(in millions)
Cash provided by (used in):
Operating activities	$	818.7	$	335.4
Investing activities		(521.6)		(368.8)
Financing activities		(423.4)		(20.4)

Net cash provided by operating activities was $818.7 million for the first quarter of 2013 compared to $335.4 million for the first quarter of 2012. The increase primarily reflects higher oil sales volumes from our Gulf of Mexico Acquisition and Eagle Ford Shale properties.

Net cash used in investing activities of $521.6 million in 2013 primarily reflects additions to oil and gas properties of approximately $467.7 million. Net cash used in investing activities of $368.8 million in 2012 primarily reflects additions to oil and gas properties of approximately $401.3 million, partially offset by the proceeds from the sale of our Panhandle properties of approximately $43.4 million.

Net cash used in financing activities of $423.4 million in 2013 primarily reflects the $244.8 million net decrease in borrowings under our revolving line of credit and the $171.2 million redemption of our 10% Senior Notes. Net cash used in financing activities of $20.4 million in 2012 primarily reflects $88.5 million of treasury stock repurchases, partially offset by the $75.0 million net increase in borrowings under our revolving line of credit.

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. We currently have $1.0 billion in authorized repurchases remaining under the program.

Critical Accounting Policies and Estimates

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, oil and natural gas properties not subject to amortization, DD&A, commodity pricing and risk management activities, investment, stock-based compensation, business combinations, goodwill and income taxes are discussed in our Annual Report on Form 10-K for the year ended December 31, 2012.

45

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:

• a condition to the closing of our merger with a subsidiary of Freeport-McMoRan may not be satisfied;

• a regulatory approval required for the merger may not be obtained or may be obtained subject to conditions that are not anticipated;

• the integration of our business and operations with those of Freeport-McMoRan may take longer than anticipated, may be more costly than anticipated and may have unanticipated adverse results relating to our existing business or the combined company’s business;

• 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, including our recent acquisition of certain deepwater Gulf of Mexico properties, which we refer to as the Gulf of Mexico Acquisition;

• the impact of hurricanes and other weather conditions on our offshore operations;

• the impact of the lack of physical and oilfield service infrastructure in deeper waters on our ability to bring production online;

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

• the 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;

46

• the effects of future laws and governmental regulations 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 if the merger between Freeport-McMoRan and McMoRan doesn’t occur;

• 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, 2012.

47

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 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 and ICE price quotations, 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 93% 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. During the three months ended March 31, 2013, the inputs used to value our 2013 crude oil puts, certain of our 2014 crude oil puts and our 2015 crude oil puts were significantly unobservable and those contracts totaling $428.4 million were transferred from Level 2 to Level 3.

See Note 5 – Commodity Derivative Contracts and Note 7 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our derivative activities and fair value measurements.

48

As of May 1, 2013, 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
2013
May - Dec	Swap contracts (2)	40,000 Bbls	$109.23	-	Brent
May - Dec	Put options(3)	13,000 Bbls	$100.00 Floor with an $80.00 Limit	$6.800 per Bbl	Brent
May - Dec	Three-way collars (4)	25,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$124.29 Ceiling
May - Dec	Three-way collars (4)	5,000 Bbls	$90.00 Floor with a $70.00 Limit	-	Brent
			$126.08 Ceiling
May - Dec	Put options(3)	17,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.253 per Bbl	Brent
2014
Jan - Dec	Put options(3)	5,000 Bbls	$100.00 Floor with an $80.00 Limit	$7.110 per Bbl	Brent
Jan - Dec	Put options (3)	30,000 Bbls	$95.00 Floor with a $75.00 Limit	$6.091 per Bbl	Brent
Jan - Dec	Put options (3)	75,000 Bbls	$90.00 Floor with a $70.00 Limit	$5.739 per Bbl	Brent
2015
Jan - Dec	Put options (3)	84,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.889 per Bbl	Brent
Sales of Natural Gas Production
2013
May - Dec	Swap contracts (2)	110,000 MMBtu	$4.27	-	Henry Hub
2014
Jan - Dec	Swap contracts (2)	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 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.

(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 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.

49

The fair value of outstanding crude oil and natural gas commodity derivative instruments at March 31, 2013 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	$	301	$	(125)	$	196
Crude oil collars		9		(25)		29
Crude oil swaps		14		(119)		118
Natural gas swaps		(1)		(26)		27
	$	323	$	(295)	$	370

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 6 – Investment and Note 7 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our equity investment. At March 31, 2013, the investment, comprised of 51.0 million shares of McMoRan common stock, was valued at approximately $833.8 million. A 10% change in the underlying equity market price per share would result in a $83.4 million increase or decrease in the fair value of our investment, recognized in the income statement.

In connection with the MMR Merger, on December 5, 2012, we entered into the Support Agreement with Freeport-McMoRan, pursuant to which we, in our capacity as a stockholder of McMoRan, are generally prohibited from transferring our shares of McMoRan common stock prior to the consummation of the merger. On March 31, 2013, we determined the fair value of our investment using McMoRan’s closing stock price of $16.35, which we believe is consistent with the exit price notion and is representative of what a market participant would pay for McMoRan’s common stock in an arm’s length transaction. Additionally, we utilized a time value of money analysis to determine an implied discount rate. The implied discount is determined by utilizing a risk-free interest rate based on the U.S. Treasury Strip rate with a maturity date corresponding to the expected close of the merger. Failure to complete the merger could result in changes to the method we use to determine fair value of our investment, which may result in the use of other significant unobservable inputs.

As of March 31, 2013, our investment in McMoRan has been classified as Level 3 since the fair value is determined by utilizing significant inputs that are unobservable.

50

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 March 31, 2013 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

Except for the potential changes noted in the following paragraph related to PXP Offshore LLC, there were no changes in our internal control over financial reporting during the quarter ended March 31, 2013 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On November 30, 2012, PXP Offshore LLC was formed in connection with the Gulf of Mexico Acquisition. Management continues to integrate PXP Offshore LLC’s internal control over financial reporting with PXP’s internal control over financial reporting. This integration may lead to changes in these controls in future fiscal periods, but management does not yet know whether these changes will materially affect our internal control over financial reporting. Management expects the integration process to be completed during 2013.

51

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

On December 5, 2012, PXP entered into the Freeport-McMoRan Merger Agreement with Freeport-McMoRan and the Merger Sub, pursuant to which Freeport-McMoRan will acquire PXP. On December 5, 2012, Freeport-McMoRan agreed to acquire McMoRan. Between December 11, 2012 and December 20, 2012, three putative class actions challenging the merger were filed on behalf of PXP stockholders in the Court of Chancery of the State of Delaware:Rice v. Plains Exploration & Production Co. et al., No. 8090-VCN, filed on December 11, 2012;MARTA/ATU Local 732 Employees Retirement Plan v. Plains Exploration & Production Co. et al., No. 8135-VCN, filed on December 20, 2012; andLouisiana Municipal Police Employees’ Retirement System v. Arnold et al., No. 8141-VCN, also filed on December 20, 2012. The actions name as defendants PXP, the directors of PXP, Freeport-McMoRan, and a Freeport-McMoRan subsidiary. The actions allege that PXP’s directors breached their fiduciary duties because they, among other things, pursued their own interests at the expense of stockholders, failed to maximize stockholder value with respect to the merger and failed to disclose material facts regarding the merger, and that Freeport-McMoRan and a Freeport-McMoRan subsidiary aided and abetted the breach of fiduciary duties by PXP’s directors. The actions seek as relief an injunction barring or rescinding the merger, damages, and attorneys’ fees and costs. On January 7, 2013, theMARTA/ATU Local 732 Employees Retirement Planaction was voluntarily dismissed by the plaintiff. On January 15, 2013, the Court of Chancery of the State of Delaware entered an order consolidating the two remaining actions under the captionIn re Plains Exploration & Production Company Stockholder Litigation, No. 8090-VCN, and appointing co-lead counsel for the plaintiffs.

52

In addition, fourteen derivative actions challenging both the merger and/or the MMR Merger have been filed on behalf of Freeport-McMoRan by purported Freeport-McMoRan stockholders. Eleven of these actions were filed in the Court of Chancery of the State of Delaware:Jacksonville Police & Fire Pension Fund v. Moffett et al., No. 8110-VCN, filed on December 14, 2012;Sklar v. Moffett et al., No. 8126-VCN, filed on December 19, 2012;Gaines v. Adkerson et al., No. 8139-VCN, filed on December 20, 2012;Rosenzweig v. Adkerson et al., No. 8140-VCN, filed on December 20, 2012;Lang v. Moffett et al., No. 8142-VCN, filed on December 21, 2012;Dauphin County Employee Retirement Fund v. Moffett et al., No. 8145-VCN, filed on December 21, 2012;Anthony Newman v. James R. Moffett, et al., No. 8156-VCN, filed on December 28, 2012;State-Boston Retirement System v. Moffett, et al., C.A. No. 8206-VCN, filed on January 11, 2013;Inter-Local Pension Fund of the Graphic Communications Conference of the International Brotherhood of Teamsters v. Moffett, et al., C.A. No. 8207-VCN, filed on January 11, 2013; andUnited Wire Metal and Machine Pension Fund v. Moffett, et al., C.A. No. 8208-VCN, filed on January 11, 2013; andStephen Blau MD Money Purchase Pension Plan Trust v. Moffett et al., No. 8384-VCN, filed on March 5, 2013. Three were filed in the Superior Court of the State of Arizona, County of Maricopa:Liberatore v. Moffett et al., No. CV2012-018351, filed on December 14, 2012;Teich et al. v. Moffett et al., No. CV2012-018403, filed on December 17, 2012; andJeffery Harris v. Richard C. Adkerson, et al., CV2013-004163, filed on January 16, 2013. The actions name some or all of the following as defendants: the directors and certain officers of Freeport-McMoran, two Freeport-McMoRan subsidiaries, PXP and certain of its directors and McMoRan and certain of its directors. The actions allege that the Freeport-McMoran directors breached their fiduciary duties because they, among other things, pursued their own interests at the expense of Freeport-McMoran stockholders in approving the merger and the MMR Merger, and further allege that some or all of the other defendants aided and abetted such breaches of fiduciary duties. On January 25, 2013, the Court of Chancery of the State of Delaware entered an order consolidating ten of the eleven actions pending in that court under the captionIn re Freeport-McMoRan Copper & Gold Inc. Derivative Litigation, No. 8145-VCN, and appointing co-lead counsel for the plaintiffs. The Arizona Superior Court consolidated the Arizona actions intoIn re Freeport-McMoRan Copper & Gold Inc. Derivative Litigation,No. CV2012-018351. The parties to the consolidated Delaware action have stipulated to allow the Arizona plaintiffs to intervene in the consolidated Delaware action, and the court granted that stipulation on March 18, 2013. The Arizona plaintiffs have agreed to seek a permanent stay of the Arizona actions. The actions seek as relief, among other things, an injunction barring or rescinding both the merger and the MMR Merger and requiring submission of the proposed merger and MMR Merger to a vote of Freeport-McMoRan stockholders, damages and attorneys’ fees and costs. The plaintiffs in the consolidated Delaware action informed the Court on March 21, 2013 that they will not seek a preliminary injunction barring either the merger or the MMR Merger.

53

In addition, ten putative class actions challenging the MMR Merger have been filed on behalf of McMoRan stockholders. Nine of these actions were filed in the Court of Chancery of the State of Delaware: Krieger v. McMoRan Exploration Co. et al., No. 8091-VCN, filed December 11, 2012;Steven Kosoff IRA v. McMoRan Exploration Co. et al., No. 8100-VCN, filed December 12, 2012;Barasch v. McMoRan Exploration Co. et al., No. 8106-VCN, filed December 13, 2012;Berstein v. Moffett et al., No. 8107-VCN, filed December 13, 2012;Curalov v. McMoRan Exploration Co. et al., No. 8115-VCN, filed December 17, 2012;Purnell et al. v. Adkerson et al., No. 8117-VCN, filed December 17, 2012;Yagoobian v. McMoRan Exploration Co. et al., No. 8128-VCN, filed December 19, 2012;Davis v. McMoRan Exploration Co. et al., No. 8132-VCN, filed December 20, 2012; andSeidlitz v. Adkerson et al., No. 8151-VCN, filed December 26, 2012. One was filed in the Civil District Court for the Parish of Orleans of the State of Louisiana:Langley v. Moffett et al., No. 2012-11904, filed December 19, 2012. Each of the actions names the McMoRan directors as defendants, as well as some or all of the following: Freeport-McMoRan, subsidiaries of Freeport-McMoRan, and PXP. The actions allege that McMoRan’s directors breached their fiduciary duties because they, among other things, pursued their own interests at the expense of the stockholders, failed to maximize stockholder value with respect to the MMR Merger and failed to disclose material facts with regard to the MMR Merger, and further allege that some or all of the other defendants aided and abetted such breaches of fiduciary duties. One of the lawsuits also asserts breach of contract claims against Freeport-McMoRan and PXP derivatively on behalf of McMoRan. The actions seek, among other things, injunctive relief barring or rescinding the MMR Merger, damages, and attorneys’ fees and costs. On January 9, 2013, theKriegeraction was voluntarily dismissed by the plaintiff. On January 25, 2013, the Court of Chancery of the State of Delaware entered an order consolidating the remaining eight actions pending in that court under the captionIn re McMoRan Exploration Co. Stockholder Litigation, No. 8132-VCN, and appointing co-lead counsel for the plaintiffs. On March 28, 2013, Defendants moved to stay the Louisiana action.

On May 1, 2013, the Court of Chancery of the State of Delaware heard oral arguments on the injunctive relief requested by the plaintiffs in the consolidated PXP action described above, but no decision was entered by the court at such hearing. The hearing in the MMR Merger consolidated action was postponed per agreement of the parties.

The PXP defendants believe the lawsuits are without merit and intend to defend vigorously against them.

54

ITEM 6. Exhibits

Exhibit No.	Description
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 1A, 2, 3, 4 and 5 are not applicable and have been omitted.

55

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: May 6, 2013	By:	/s/ Winston M. Talbert
		Winston M. Talbert
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

56

EXHIBIT INDEX

Exhibit No.	Description
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

57