Exhibit 99.1

Plains Exploration & Production Company 700 Milam, Suite 3100, Houston, TX 77002 www.pxp.com

NEWS RELEASE

FOR IMMEDIATE RELEASE

PXP Announces Strong First Quarter Financial & Operating Results,

Reports Substantial Progress in its Gulf of Mexico Business Expansion, and

Delivers Exceptional Eagle Ford Field Development Results

Houston, Texas, May 2, 2013 - Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) announces 2013 first-quarter financial and operating results.

2013 HIGHLIGHTS

• Total daily sales volumes averaged 170.4 thousand barrels of oil equivalent (“BOE”), a 92% increase per diluted share compared to first-quarter 2012.

• Oil daily sales volumes averaged 129.2 thousand barrels, a 158% increase per diluted share compared to first-quarter 2012.

• Phobos discovery well announced, encountering approximately 250 net feet of high-quality lower Tertiary oil pay in the Gulf of Mexico.

• Total revenues were $1,232 million compared to $524.3 million in the first-quarter of 2012.

• Net cash provided by operating activities was $818.7 million compared to $335.4 million in the first-quarter of 2012.

• Operating cash flow (a non-GAAP measure) was $789.6 million compared to $329.2 million in the first-quarter of 2012.

• Long-term debt, including current maturities, was reduced by $420 million to approximately $9.7 billion at quarter-end 2013 compared to approximately $10.1 billion at year-end 2012.

• Income from operations was $397.3 million compared to $171.3 million in the first-quarter of 2012.

• Net income attributable to common stockholders was $22.6 million, or $0.17 per diluted share compared to a first-quarter 2012 net loss attributable to common stockholders of $82.3 million, or $0.64 per diluted share.

• Adjusted net income attributable to common stockholders (a non-GAAP measure) was $139.6 million, or $1.05 per diluted share, compared to first-quarter 2012 adjusted net income attributable to common stockholders of $77.0 million, or $0.58 per diluted share.

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FINANCIAL SUMMARY

PXP reported first-quarter revenues of $1.2 billion and net income attributable to common stockholders of $22.6 million, or $0.17 per diluted share, compared to revenues of $524.3 million and a net loss attributable to common stockholders of $82.3 million, or $0.64 per diluted share, for the first-quarter of 2012.

The first-quarter 2013 net income attributable to common stockholders includes certain items affecting the comparability of operating results. Those items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts resulting in a net loss of $202.0 million due in large part to higher crude oil forward prices, a $15.5 million unrealized gain on investment in McMoRan Exploration Co. (“McMoRan”) common stock, debt extinguishment costs of $18.1 million, and other items. When considering these items, PXP reports adjusted net income attributable to common stockholders of $139.6 million, or $1.05 per diluted share (a non-GAAP measure), compared to $77.0 million, or $0.58 per diluted share, for the same period in 2012.

A reconciliation of non-GAAP financial measures used in this release to comparable GAAP financial measures is included with the financial tables.

OPERATIONAL UPDATE

PXP’s 2013 first-quarter daily sales volumes averaged 170.4 thousand BOE per day compared to 87.9 thousand BOE in the first-quarter of 2012.

Crude oil sales volumes averaged 118.9 thousand barrels per day, compared to first-quarter 2012 average volumes of 47.8 thousand barrels per day. Volume growth is driven primarily by the addition of the deepwater Gulf of Mexico assets acquired in November 2012 and strong Eagle Ford Field performance.

Natural gas liquids sales volumes averaged 10.3 thousand barrels per day, compared to first-quarter 2012 average volumes of 1.8 thousand barrels per day. The increase reflects the addition of the deepwater Gulf of Mexico assets and strong Eagle Ford Field performance.

Natural gas sales volumes averaged 246.9 million cubic feet (“MMcf”) per day compared to 229.3 MMcf per day in the first-quarter 2012. The increase reflects the addition of the deepwater Gulf of Mexico assets and increased production from the Eagle Ford Field, partially offset by decreased production from the Haynesville Field.

In the Gulf of Mexico, first-quarter daily sales volumes averaged 60.7 thousand BOE per day net to PXP. The Company closed the acquisition of interests in certain deepwater Gulf of Mexico oil and gas properties in late 2012. In early 2013, PXP acquired lease blocks near its newly acquired infrastructure and secured drilling rig capacity to accelerate its top-tier deepwater Gulf of Mexico program beginning in the second half of 2014. There have been additional producer wells drilled at Lucius and a significant discovery was announced at Phobos.

At the Lucius development in Keathley Canyon, four of the six planned producer wells have been drilled with two producer wells remaining to drill this year. In December 2011, the operator and its working interest partners sanctioned development of Lucius, a subsea development consisting of a truss spar hull located in 7,200 feet of water with a topside capacity of 80 thousand barrels of oil per day and 450 MMcf of gas per day. First production is anticipated in 2014. Anadarko Petroleum Corporation is the operator. PXP has a 23.33% working interest.

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At the Phobos prospect, located in Sigsbee Escarpment block 39, the operator and its partners recently announced a discovery at the Phobos-1 well which encountered approximately 250 net feet of high-quality oil pay in Lower Tertiary-aged reservoirs. The Phobos discovery was drilled to a total depth of 28,675 feet in approximately 8,500 feet of water, approximately 11 miles south of the Lucius development. Anadarko Petroleum Corporation is the operator and is currently incorporating the data from the Phobos well to determine future activities. PXP has a 50% working interest.

In March 2013, PXP participated in the Gulf of Mexico Outer Continental Shelf Lease Sale 227 and was the apparent high bidder on 11 deepwater blocks. Of the 11 blocks, 7 blocks are located near PXP’s Holstein Hub and 3 blocks are located near PXP’s Horn Mountain Hub. The sum of PXP’s high bids was approximately $82.6 million. If all high bids are awarded, the Company’s deepwater Gulf of Mexico portfolio will include interests in 152 blocks containing 60 prospects or leads in the Pliocene, Miocene, Tertiary and Cretaceous reservoirs. PXP has also contracted for two latest-generation, ultra-deep capable drill ships to accelerate the expansion of the Company’s deepwater Gulf of Mexico program. The Noble Sam Croft drill ship and the Noble Tom Madden drill ship are currently under construction with delivery to PXP expected mid-year 2014 and early 2015, respectively.

PXP has 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 PXP. The PXP operated Horn Mountain platform and the PXP operated Marlin Hub will be impacted by the work at the gas processing plant. PXP holds 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. PXP’s net average daily sales volumes from these facilities were 44.0 thousand BOE per day in the first quarter of 2013.

Despite the second-quarter impact on sales volumes from the required plant shut down, PXP maintains its total company full-year 2013 oil and natural gas sales volume mid-point guidance of 156.3 thousand BOE per day.

In the Eagle Ford Field, first-quarter daily sales volumes averaged 44.7 thousand BOE per day net to PXP compared to first-quarter 2012 average daily sales volumes of 13.9 thousand BOE per day net to PXP. At the end of March, PXP had 7 drilling rigs operating and 31 wells drilled but waiting on completion or connection to pipelines.

In California, first-quarter daily sales volumes averaged 37.2 thousand BOE per day net to PXP compared to the first-quarter 2012 daily sales volume average of 38.6 thousand BOE per day net to PXP. At the end of March, PXP had 4 drilling rigs operating onshore.

In the Haynesville Field, first-quarter daily sales volumes averaged 134.2 MMcf per day net to PXP compared to first-quarter 2012 average daily sales volumes of 173.5 MMcf per day net to PXP. The sales volume decline reflects significantly lower drilling activity. At the end of March, there were 4 drilling rigs operating in which PXP had a working interest.

CAPITAL SPENDING

For the first-quarter of 2013, PXP had cash expenditures of approximately $499.5 million for additions to oil and gas properties and leasehold acquisitions of which $106.1 million was funded by Plains Offshore Operations Inc., PXP’s consolidated subsidiary.

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COMMODITY PRICES

During the first-quarter of 2013, Brent crude oil price averaged $112.60 per barrel compared to $118.42 per barrel in the first-quarter 2012. PXP’s 2013 first-quarter crude oil average realized price per barrel before derivative transactions was $105.16 per barrel, or approximately 93% of Brent, compared to $105.87 per barrel in the first-quarter 2012, or approximately 89% of Brent. Including the impact of derivative transactions, the first-quarter 2013 crude oil average realized price was $102.45 per barrel, or approximately 91% of Brent, compared to $104.38 per barrel in the first-quarter 2012, or 88% of Brent.

During the first-quarter of 2013, the oil average realized price per barrel before derivative transactions, which includes 10.3 thousand barrels per day net to PXP of natural gas liquids, was $99.60 per barrel, or approximately 88% of Brent, compared to $103.45 per barrel in the first-quarter 2012, or 87% of Brent. Including the impact of derivative transactions, the average realized price in the first-quarter 2013 was $97.10 per barrel, or 86% of Brent, compared to $102.01 per barrel in the first-quarter 2012, or 86% of Brent.

During the first-quarter of 2013, NYMEX gas price averaged $3.34 per million British thermal units (“MMBtu”) compared to $2.73 per MMBtu in the first-quarter 2012. PXP’s 2013 first-quarter natural gas average realized price before derivative transactions was $3.25 per MMBtu, or approximately 97% of NYMEX, compared to $2.56 per MMBtu in the first-quarter 2012, or 94% of NYMEX. Including the impact of derivative transactions, the average realized price in the first-quarter 2013 was $3.67 per MMBtu, or approximately 110% of NYMEX, compared to $3.29 per MMBtu in the first-quarter 2012, or 121% of NYMEX.

MANAGEMENT COMMENT

James C. Flores, Chairman, President and CEO of PXP commented, “The first quarter results confirm the strong growth we have been projecting. Production, revenues, net cash provided by operating activities and earnings saw significant increases during the quarter led by the high rate-of-return crude oil production in the deepwater Gulf of Mexico, the Eagle Ford Field, and California. Our diversified growth strategy, underpinned by a unique combination of oil and natural gas assets and our on-going risk management program, remains our competitive advantage. The Company is centered on executing its highly profitable, lower-risk, long-term, oil-focused growth plan which is complementary to the growth profile and cash margins of the large, low-cost, expandable asset base characteristics of Freeport-McMoRan Copper & Gold Inc. with whom we have entered into a merger transaction.”

CONFERENCE CALL

PXP will host a conference call today, Thursday, May 2, at 8:00 a.m. Central time. Investors wishing to participate in the conference call may dial 1-800-567-9836 or 1-973-935-8460. The conference call and replay ID is: 36577090. The replay can be accessed by dialing 1-855-859-2056 or 1-404-537-3406. A live webcast of the conference call will be available in the Investor Information section of PXP’s website at www.pxp.com.

PXP is an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas in California, Texas, Louisiana, and the Gulf of Mexico. PXP is headquartered in Houston, Texas.

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ADDITIONAL INFORMATION & FORWARD-LOOKING STATEMENTS

This press release contains forward-looking information regarding PXP that is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995. All statements included in this press release that address activities, events or developments that PXP expects, believes or anticipates will or may occur in the future are forward-looking statements.

These include statements regarding:

* completion of the proposed merger,

* reserve and production estimates,

* oil and gas prices,

* the impact of derivative positions,

* production expense estimates,

* cash flow estimates,

* future financial performance,

* capital and credit market conditions,

* planned capital expenditures, and

* other matters that are discussed in PXP’s filings with the SEC.

These statements are based on our current expectations and projections about future events and involve known and unknown risks, uncertainties, and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to our filings with the SEC, including our Form 10-K and Forms 10-Q, for a discussion of these risks.

References to quantities of oil or natural gas may include amounts that the Company believes will ultimately be produced, but that are not yet classified as “proved reserves” under SEC definitions. In this press release, the Company uses the terms “possible reserves” and “resource potential” to describe the Company’s internal estimates of volumes of oil and gas that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. Resource potential is a broader description of potentially recoverable volumes than probable and possible reserves, as defined by the SEC regulations. SEC guidelines prohibit us from including resource potential in filings with the SEC. References in this press release to oil include crude oil, condensate, and natural gas liquid volumes.

All forward-looking statements in this press release 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 press release and our other filings with the SEC. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except as required by law, we do not intend to update these forward-looking statements and information.

IMPORTANT ADDITIONAL INFORMATION ABOUT THE PROPOSED MERGER AND WHERE TO FIND IT:

In connection with the proposed business combination transaction between PXP and FCX, FCX has filed with the SEC a registration statement on Form S-4 that contains a definitive proxy statement of PXP that also constitutes a prospectus of FCX. THE REGISTRATION STATEMENT AND THE PROXY STATEMENT/PROSPECTUS CONTAIN IMPORTANT INFORMATION ABOUT PXP, FCX, THE PROPOSED TRANSACTION AND RELATED MATTERS. INVESTORS AND SECURITY HOLDERS ARE URGED TO READ THE REGISTRATION STATEMENT AND THE PROXY STATEMENT/PROSPECTUS CAREFULLY. Investors and security holders may obtain free copies of the registration statement and the proxy statement/prospectus and other documents filed with the SEC by PXP and FCX through the web site maintained by the SEC at www.sec.gov. In addition, investors and security holders may obtain free copies of the registration statement and the proxy statement/prospectus by phone, e-mail or written request by contacting the investor relations department of PXP or FCX at the following:

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Plains Exploration & Production Company

700 Milam, Suite 3100

Houston, TX 77002

Attention: Investor Relations

Phone: (713) 579-6000

Email: investor@pxp.com

Freeport-McMoRan Copper & Gold Inc.

333 N. Central Ave.

Phoenix, AZ 85004

Attention: Investor Relations

Phone: (602) 366-8400

Email: ir@fmi.com

PARTICIPANTS IN THE SOLICITATION

PXP and FCX, and their respective directors and executive officers, may be deemed to be participants in the solicitation of proxies in respect of the proposed transactions contemplated by the merger agreement. Information regarding directors and executive officers of PXP is contained in the proxy statement/prospectus dated April 18, 2013, which is filed with the SEC. Information regarding FCX’s directors and executive officers is contained in FCX’s definitive proxy statement dated April 27, 2012, which is filed with the SEC.

This document shall not constitute an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the U.S. Securities Act of 1933, as amended.

Contact: Hance Myers, hmyers@pxp.com or 713.579.6291.

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Plains Exploration & Production Company

Consolidated Statements of Income

(in thousands, except per share data)

	Three Months Ended March 31,
	2013			2012
	(Unaudited)
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

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Plains Exploration & Production Company

Operating Data

	Three Months Ended March 31,
	2013			2012
	(Unaudited)
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
Cash Margin per BOE (1)
Oil and gas revenues	$	80.26		$	65.16
Costs and expenses
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	)
Oil and gas related DD&A		(33.81	)		(21.64	)
Gross margin (GAAP)		30.34			26.72
Oil and gas related DD&A		33.81			21.64
Realized (loss) gain on derivative instruments		(1.29	)		1.08
Cash margin (non-GAAP)	$	62.86		$	49.44
Oil and gas capital expenditures accrued ($ in thousands) (2)	$	472,711		$	439,939

⁽¹⁾  Cash margin per BOE (a non-GAAP measure) is calculated by adjusting gross margin per BOE (a GAAP measure) to include the realized gain and loss on derivative instruments and to exclude DD&A. Management believes this presentation may be helpful to investors as it represents the cash generated by our oil and gas production that is available for, among other things, capital expenditures and debt service. PXP management uses this information to analyze operating trends for comparative purposes within the industry. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating trends and performance.

⁽²⁾  Additions to oil and gas properties reported in our consolidated statement of cash flows differ from the accrual basis amounts reflected above due to the timing of cash payments. Excludes acquisitions.

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Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure

	Three Months Ended March 31, 2013
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price
Average realized price before derivative instruments (GAAP) (1)	$	99.60		$	3.25	$	80.26
Realized (loss) gain on derivative instruments		(2.50	)		0.42		(1.29	)
Realized cash price including derivative settlements (non-GAAP)	$	97.10		$	3.67	$	78.97
	Three Months Ended March 31, 2012
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price
Average realized price before derivative instruments (GAAP) (1)	$	103.45		$	2.56	$	65.16
Realized (loss) gain on derivative instruments		(1.44	)		0.73		1.08
Realized cash price including derivative settlements (non-GAAP)	$	102.01		$	3.29	$	66.24

⁽¹⁾  Excludes the impact of production costs and expenses and DD&A.

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Plains Exploration & Production Company

Consolidated Statements of Cash Flows

(in thousands of dollars)

	Three Months Ended March 31,
	2013			2012
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	31,794		$	(73,303	)
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		540,475			181,450
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		33,058			8,688
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

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Plains Exploration & Production Company

Consolidated Balance Sheets

(in thousands of dollars)

	March 31, 2013			December 31, 2012
	(Unaudited)
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
Equity
Stockholders’ equity
Common stock		1,439			1,439
Additional paid-in capital		3,413,932			3,437,826
Retained earnings		658,772			637,411
Treasury stock, at cost		(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

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Plains Exploration & Production Company

Summary of Open Derivative Positions

At May 1, 2013

Period (1)	Instrument Type	Daily Volumes	Average Price (2)	Average Deferred Premium	Index
Sales of Crude Oil Production
2013
May - Dec	Swap contracts  (3)	40,000 Bbls	$109.23	—	Brent
May - Dec	Put options (4)	13,000 Bbls	$100.00 Floor with an $80.00 Limit	$6.800 per Bbl	Brent
May - Dec	Three-way collars  (5)	25,000 Bbls	$100.00 Floor with an $80.00 Limit $124.29 Ceiling	—	Brent
May - Dec	Three-way collars  (5)	5,000 Bbls	$90.00 Floor with a $70.00 Limit $126.08 Ceiling	—	Brent
May - Dec	Put options (4)	17,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.253 per Bbl	Brent
2014
Jan - Dec	Put options (4)	5,000 Bbls	$100.00 Floor with an $80.00 Limit	$7.110 per Bbl	Brent
Jan - Dec	Put options (4)	30,000 Bbls	$95.00 Floor with a $75.00 Limit	$6.091 per Bbl	Brent
Jan - Dec	Put options (4)	75,000 Bbls	$90.00 Floor with a $70.00 Limit	$5.739 per Bbl	Brent
2015
Jan - Dec	Put options (4)	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  (3)	110,000 MMBtu	$4.27	—	Henry Hub
2014
Jan - Dec	Swap contracts  (3)	100,000 MMBtu	$4.09	—	Henry Hub

⁽¹⁾  All of our derivatives are settled monthly.

⁽²⁾ The average strike prices do not reflect any premiums to purchase the put options.

⁽³⁾ 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.

⁽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 less the option premium. If the index price is at or above the per barrel floor, we pay only the option premium.

⁽⁵⁾ 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.

Derivative Settlements

(in thousands of dollars)

The following table reflects cash (payments) receipts for derivatives attributable to the stated production periods.

	Three Months Ended March 31,
	2013			2012
Oil sales	$	(29,086	)	$	(6,509	)
Natural gas sales		9,225			15,177
	$	(19,861	)	$	8,668

Page 13

Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure

The following table reconciles net income (loss) (GAAP) to adjusted net income and adjusted net income attributable to common stockholders (non-GAAP) for the three months ended March 31, 2013 and 2012. Adjusted net income and adjusted net income attributable to common stockholders exclude certain items affecting the comparability of operating results and the related tax effects. Management believes this presentation may be helpful to investors. PXP management uses this information to analyze operating trends and for comparative purposes within the industry. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating the Company’s operational trends and performance.

	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Net income (loss) (GAAP)	$	31.8		$	(73.3	)
Unrealized loss on mark-to-market derivative contracts		202.0			109.1
Realized (loss) gain on mark-to-market derivative contracts (1)		(19.9	)		8.7
Unrealized (gain) loss on investment measured at fair value		(15.5	)		135.9
Debt extinguishment costs		18.1			—
Acquisition and merger related costs		1.2			—
Adjust income taxes (2)		(68.9	)		(94.4	)
Adjusted net income (non-GAAP)	$	148.8		$	86.0
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		(9.2	)		(9.0	)
Adjusted net income attributable to common stockholders (non-GAAP)	$	139.6		$	77.0

⁽¹⁾  The amounts presented in the above table differ from the adjustments reflected in the calculation of operating cash flow on the following page due to the accrued amounts reflected in the income statement versus the actual cash received or paid reflected in the consolidated statement of cash flows.

⁽²⁾  Tax rates assumed based upon adjusted earnings are 38% and 36% for the three months ended March 31, 2013 and 2012, respectively. Tax rates exclude the effects of nonrecurring tax related expenses and benefits.

Page 14

Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure

The following table reconciles Net Cash Provided by Operating Activities (GAAP) to Operating Cash Flow (non-GAAP) for the three months ended March 31, 2013 and 2012. Management believes this presentation may be useful to investors. PXP management uses this information for comparative purposes within the industry and as a means of measuring the Company’s ability to fund capital expenditures and service debt. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating the Company’s operational trends and performance.

Operating cash flow is calculated by adjusting net income to add back certain non-cash and non-operating items, including debt extinguishment costs, the unrealized gain and loss on mark-to-market derivative contracts, to include derivative cash settlements for the realized gain and loss on mark-to-market derivative contracts that are classified as investing activities for GAAP purposes, to exclude the unrealized gain and loss on the investment measured at fair value, to include distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary that are classified as financing activities for GAAP purposes and to exclude certain other items.

	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Net income (loss)	$	31.8		$	(73.3	)
Items not affecting operating cash flows
Depreciation, depletion, amortization and accretion		540.5			181.4
Deferred income tax expense (benefit)		15.6			(46.0	)
Debt extinguishment costs		18.1			—
Unrealized loss on mark-to-market derivative contracts		202.0			109.1
Unrealized (gain) loss on investment measured at fair value		(15.5	)		135.9
Acquisition and merger related costs		1.2			—
Non-cash compensation		13.5			18.2
Other non-cash items		2.7			1.4
Realized (loss) gain on mark-to-market derivative contracts		(13.5	)		9.3
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		(6.8	)		(6.8	)
Operating cash flow (non-GAAP)	$	789.6		$	329.2
Reconciliation of non-GAAP to GAAP measure
Operating cash flow (non-GAAP)	$	789.6		$	329.2
Changes in assets and liabilities from operating activities		33.0			8.7
Realized loss (gain) on mark-to-market derivative contracts		13.5			(9.3	)
Acquisition and merger related costs		(1.2	)		—
Cash portion of debt extinguishment costs		(23.0	)		—
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		6.8			6.8
Net cash provided by operating activities (GAAP)	$	818.7		$	335.4

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