Exhibit 99.1

 

 

 

NEWS RELEASE

FOR IMMEDIATE RELEASE

PXP Announces 2011 Full-Year Results:

Realizes Significant Net Income Growth Year-over-Year,

Achieves Record Sales Volumes,

Generates Double-Digit Cash Flow Growth, and

Delivers Solid Reserve Replacement and Substantially Higher Reserve Value

PXP Repurchased 12.8 Million Shares of Common Stock, Reducing Shares Outstanding to

128.2 Million as of January 31, 2012

PXP’s Board of Directors Authorizes $1 Billion in Share Repurchases and Extends

Program Until January 2016

Fourth-Quarter Statistical Highlights:

•

Revenues were $517.5 million and net income attributable to common stockholders was $97.7 million, or $0.69 per diluted share.

•

Adjusted net income attributable to common stockholders was $28.6 million, or $0.20 per diluted share (a non-GAAP measure).

•

Oil/liquids sales accounted for approximately 81% of total oil and gas revenue.

•

Average daily sales volumes increased 13%, or 26% pro forma for asset sales, compared to fourth-quarter 2010.

•

Oil/liquids average daily sales volumes increased 12%, or 16% pro forma for asset sales, compared to fourth-quarter 2010.

•

Net cash provided by operating activities was $188.1 million and operating cash flow was $284.7 million, a 12% increase over fourth-quarter 2010 (a non-GAAP measure).

•

Gross margin per barrel of oil equivalent (BOE) was $15.33 and cash margin per BOE was $35.71, a 9% increase over fourth-quarter 2010 (a non-GAAP measure).

Full-Year Statistical Highlights:

•

Revenues were $2.0 billion and net income attributable to common stockholders was $205.3 million, or $1.44 per diluted share.

•

Adjusted net income attributable to common stockholders was $223.0 million, or $1.56 per diluted share (a non-GAAP measure).

•

Oil/liquids sales accounted for approximately 78% of total oil and gas revenue.

•

Average daily sales volumes increased 12%, or 23% pro forma for asset sales, compared to 2010.

•

Oil/liquids average daily sales volumes increased 7%, or 8% pro forma for asset sales, compared to 2010.

•

Net cash provided by operating activities was $1.11 billion, a 22% increase year-over-year.

•

Operating cash flow was $1.13 billion, a 16% increase year-over-year (a non-GAAP measure).

•

Gross margin per BOE was $20.95 and cash margin per BOE was $37.29 (a non-GAAP measure), an increase of 17% and 14% over 2010, respectively.

2011 Proved Reserves:

•

Total proved reserves, pro forma for asset sales, increased 16% to 410.9 million BOE.

•

Standardized measure of discounted net cash flows increased 66% to $5.1 billion from $3.1 billion in 2010.

•

PV-10 value increased 58% to $7.9 billion from $5.0 billion in 2010 (a non-GAAP measure).

•

Reserve replacement is 222%, or 290% pro forma for asset sales (a non-GAAP measure).

•

All-in finding and development costs were $23.48 per BOE, or $18.01 per BOE pro forma for asset sales (a non-GAAP measure).

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2011 Oil/Liquids Proved Reserves:

•

Oil/liquids reserves, pro forma for asset sales, increased 18% to 244.0 million barrels.

•

Oil/liquids are 59% of total proved, up from 54% in 2010.

•

Oil/liquids reserve replacement is 280% (a non-GAAP measure).

•

Oil/liquids reserve-to-pro forma production ratio is 14 years.

Houston, Texas, February 23, 2012—Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) announces 2011 fourth-quarter and full-year financial and operating results.

PXP reported fourth-quarter revenues of $517.5 million and net income attributable to common stockholders of $97.7 million, or $0.69 per diluted share, compared to revenues of $408.1 million and a net loss of $19.5 million, or $0.14 per diluted share, for the fourth-quarter 2010. Quarterly income was reduced by approximately $0.07 per share due to higher stock-based compensation expense reflecting the impact of a 62% increase in PXP’s share price during the quarter and approximately $0.14 per share due to an increase in the depreciation, depletion and amortization rate.

Fourth-quarter 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, a $232.3 million unrealized gain on investment in McMoRan Exploration Co. (“McMoRan”) common stock, debt extinguishment costs, and other items. When considering these items, PXP reports net income attributable to common stockholders of $28.6 million, or $0.20 per diluted share (a non-GAAP measure).

PXP reported full-year revenues of $2.0 billion and net income attributable to common stockholders of $205.3 million, or $1.44 per diluted share, compared to revenues of $1.5 billion and net income of $103.3 million, or $0.73 per diluted share, for the full-year 2010.

Full-year 2011 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, debt extinguishment costs, an unrealized loss on investment in McMoRan, a 2010 impairment of PXP’s relinquished Vietnam oil and gas properties, and other items. When considering these items, PXP reports net income attributable to common stockholders of $223.0 million, or $1.56 per diluted share (a non-GAAP measure).

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 2011 fourth-quarter daily sales volumes averaged 105,396 BOE per day, a 13% increase over 92,994 BOE per day in the fourth quarter of 2010. Adjusting for the 2010 and 2011 asset divestments, the 13% sales volume increase would have been 26% and 2011 fourth-quarter daily sales volumes would have averaged 90,349 BOE per day.

PXP’s 2011 fourth-quarter oil/liquids daily sales volumes averaged 52,262 barrels per day, a 12% increase over 46,658 barrels per day in the fourth quarter of 2010. Adjusting for the 2010 and 2011 asset divestments, the 12% sales volume increase would have been 16% and 2011 fourth-quarter daily sales volumes would have averaged 47,464 barrels per day.

PXP’s 2011 full-year daily sales volumes averaged approximately 98,950 BOE per day, a 12% increase over full-year 2010 volumes of 88,451 BOE per day. Adjusting for the 2010 and 2011 asset divestments, the 12% sales volume increase would have been 23% and 2011 full-year daily sales volumes would have averaged 82,197 BOE per day.

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PXP’s 2011 full-year oil/liquids daily sales volumes averaged 48,964 barrels per day, a 7% increase over 45,943 barrels per day in 2010. Adjusting for the 2010 and 2011 asset divestments, the 7% sales volume increase would have been 8% and 2011 daily sales volumes would have averaged 43,858 barrels per day.

The robust volume growth is driven primarily by strong performance in the Eagle Ford Shale and Haynesville Shale asset areas combined with steady, consistent performance in California.

In the Eagle Ford Shale, fourth-quarter daily sales volumes averaged approximately 9,123 BOE per day net to PXP, compared to approximately 1,500 BOE per day net to PXP from the November acquisition to the end of fourth-quarter 2010. January 2012 volumes averaged approximately 13,700 BOE per day compared to approximately 1,970 BOE per day net to PXP in January 2011. The Company had 6.9 net rigs operating on its acreage at the end of January. In California, fourth-quarter average daily sales volumes were 40,003 BOE per day, essentially flat compared to the fourth-quarter 2010; and in the Haynesville Shale, fourth-quarter average daily sales volumes were approximately 200 million cubic feet equivalent (MMcfe) net to PXP compared to approximately 146 MMcfe in the fourth-quarter 2010.

In the Gulf of Mexico, the operator of the Lucius discovery, Anadarko Petroleum Corporation, announced in December that it, along with its co-venturers, have sanctioned the development of the Lucius project, located in the Keathley Canyon area of the deepwater Gulf of Mexico. Lucius will be developed with a truss spar floating production facility with the capacity to produce in excess of 80,000 barrels of oil per day and 450 million cubic feet of natural gas per day. The spar is currently under construction at Technip’s facility in Pori, Finland and first production is anticipated in 2014.

MARKETING UPDATE

PXP’s crude oil realized price was 96% of NYMEX for the fourth-quarter of 2011 and 94% for full-year 2011. In January 2012 PXP’s crude oil realized price was 92% of Brent or 102% of NYMEX. This significant increase from 2011 is expected to strengthen crude oil revenue by over 40% compared to 2011 crude oil revenue using current commodity price forecasts. This positive result reflects the impact of higher estimated crude oil volumes and stronger pricing associated with the Company’s marketing contracts in California and the Eagle Ford Shale which became effective January 1, 2012.

PROVED RESERVES

Year-end estimated proved reserves of 410.9 million BOE, net of asset sales, were 59% oil, 55% developed and had a pre-tax PV-10 value of $7.9 billion, a 58% increase over 2010 PV-10 value. The robust increase in the PV-10 value is primarily attributable to a greater concentration of oil/liquids reserves, higher oil/liquids reference prices and stronger marketing contract terms for oil sales. Pro forma for asset sales, proved reserves increased 16% over 2010 proved reserves.

In 2011, PXP added total proved reserves of 81.0 million BOE. The Company reported a total of 75.2 million BOE of extensions and discoveries, including 22.5 million BOE in the Eagle Ford Shale, 19.3 million BOE in the Gulf of Mexico, and 25.5 million BOE in the Haynesville Shale. In addition, PXP reported 4.3 million BOE of acquisitions and 1.5 million BOE of revisions. These reserve additions replaced 222% of 2011 production at a cost of $23.48 per BOE. Pro forma for asset sales, PXP replaced 290% of 2011 production at a cost of $18.01 per BOE.

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Oil/liquids proved reserves increased 9%, or 18% pro forma for asset sales, due primarily to the rapidly expanding Eagle Ford Shale asset area, project sanctioning of the Lucius development located in the Gulf of Mexico, and a higher oil reference price compared to 2010 resulting in positive price-related revisions in California.

Natural gas proved reserves decreased 13% due primarily to the 2011 asset sales. With persistent low natural gas prices and a corresponding assumed reduction in the pace of development in the Haynesville Shale, PXP classified 44 million BOE of its Haynesville undeveloped reserves as probable undeveloped. These reserves meet the reasonable certainty, economic and other conditions needed to be classified as proved undeveloped reserves but the slower pace of drilling extends the development of these reserves past five years.

PXP’s reserve estimate, the Standardized Measure and PV-10 calculations are based on the twelve-month average of first-day-of-the-month West Texas Intermediate spot oil price of $95.99 per barrel and Henry Hub spot natural gas price of $4.12 per million British thermal unit. All prices were adjusted for energy content, quality and basis differentials by area and were held constant throughout the lives of the properties, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A summary of the Company’s proved reserve reconciliation and costs incurred for 2011 is included with the financial tables.

SHARE REPURCHASE

Pursuant to its share repurchase program, during the fourth quarter of 2011 and the first quarter of 2012, PXP repurchased 12.8 million common shares at an average price of $35.16 per share for a total cost of approximately $450 million. In January 2012, PXP’s Board of Directors increased the approval for purchases to $1.0 billion of PXP common stock and extended the program until January 2016.

SENIOR REVOLVING CREDIT FACILITY

The Company’s borrowing base was recently increased from $1.8 billion to $2.3 billion until the next redetermination date currently scheduled for May 1, 2013. The commitments remained unchanged at $1.4 billion.

MANAGEMENT COMMENT

James C. Flores, Chairman, President and CEO of PXP commented, “PXP finished the year strong as sales volumes, net income attributable to common stockholders and operating cash flow each recorded significant gains compared to fourth-quarter 2010. For the full year, the Company’s 2011 net income attributable to common stockholders was up nearly 100% compared to 2010 and PXP achieved record sales volumes. Oil/liquids sales revenue as a percentage of total revenue was 78% in 2011 and is expected to be approximately 90% in 2012. Along with double-digit growth in average daily sales volumes, PXP delivered stronger operating cash flow, improved cash margins, solid reserve replacement and substantially higher proved reserve value. These attributes are the building blocks for sustained value creation and align with our fundamental asset intensity philosophy. In late December and early January, PXP repurchased a sizeable number of its outstanding shares thereby compressing the share count exposed to the forecasted increase in oil volumes and corresponding cash flow. PXP’s focus remains on increasing its margins while targeting a strong organic oil/liquids growth rate, balancing its natural gas focused capital spending with natural gas generated operating cash flow, and preserving commodity price upside while protecting the downside risk for its shareholders.”

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2012 FULL-YEAR GUIDANCE

PXP updated its 2012 full-year operational and financial guidance. Due to curtailment in drilling activity by operators in the Haynesville Shale, PXP plans to re-direct capital from the Haynesville Shale to the Eagle Ford Shale development. Total capital expenditures and the full-year total production sales volume range of 92 – 96 thousand BOE per day remain unchanged.

However, due to the shift in capital allocation, oil/liquids sales volumes, as a percentage of total volumes, are now expected to account for 58% to 61% of total volumes up from 55% estimated in previous guidance. PXP has revised its production costs per BOE to reflect higher forecasted oil/liquids volumes and lower forecasted natural gas prices. The new cost estimates are incorporated in the updated 2012 full-year operational and financial guidance included at the end of this release.

Full year guidance also reflects the following new information: depreciation, depletion and amortization expense per BOE, general and administrative expense, the current interest rate schedule for long-term debt, an effective tax rate and the weighted average equivalent shares outstanding.

CONFERENCE CALL

PXP will host a conference call today, Thursday, February 23, 2012 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: 42174570. The replay can be accessed by dialing 1-855-859-2056 or 1-404-537-3406. A live webcast of the conference call and a slide presentation 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.

ADDITIONAL INFORMATION & FORWARD-LOOKING STATEMENTS

This press release contains forward-looking information regarding PXP that is intended to be covered by the safe harbor “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:

* 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, 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.

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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.

Contact: Hance Myers: hmyers@pxp.com; 713.579.6291

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Plains Exploration & Production Company

Consolidated Statements of Income

(in thousands, except per share data)

 

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
		2011				2010				2011				2010
		(Unaudited)
Revenues
Oil sales		$	418,428			$	314,070			$	1,528,656			$	1,142,760
Gas sales			96,734				93,680				428,220				399,607
Other operating revenues			2,379				379				7,612				2,228
			517,541				408,129				1,964,488				1,544,595
Costs and Expenses
Lease operating expenses			100,543				74,826				334,923				262,533
Steam gas costs			15,841				14,283				65,482				66,449
Electricity			11,039				11,552				41,242				42,794
Production and ad valorem taxes			16,141				8,089				55,225				29,446
Gathering and transportation expenses			17,278				13,038				62,103				50,680
General and administrative			39,080				34,468				134,044				136,437
Depreciation, depletion and amortization			211,284				154,006				664,478				533,416
Impairment of oil and gas properties			—				—				—				59,475
Accretion			4,299				4,464				17,177				17,702
Legal recovery			—				—				—				(8,423	)
Other operating (income) expense			(78	)			851				(735	)			(4,130	)
			415,427				315,577				1,373,939				1,186,379
Income from Operations			102,114				92,552				590,549				358,216
Other (Expense) Income
Interest expense			(48,175	)			(31,107	)			(161,316	)			(106,713	)
Debt extinguishment costs			(120,954	)			—				(120,954	)			(1,189	)
(Loss) gain on mark-to-market derivative contracts			(11,486	)			(83,935	)			81,981				(60,695	)
Gain (loss) on investment measured at fair value			232,254				(1,551	)			(52,675	)			(1,551	)
Other income			407				1,697				3,356				15,942
Income (Loss) Before Income Taxes			154,160				(22,344	)			340,941				204,010
Income tax (expense) benefit
Current			(7	)			25,331				25,952				93,090
Deferred			(55,049	)			(22,473	)			(160,214	)			(193,835	)
Net Income (Loss)		$	99,104			$	(19,486	)		$	206,679			$	103,265
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary			(1,400	)							(1,400	)
Net Income Attributable to Common Stockholders		$	97,704							$	205,279
Earnings (Loss) per Common Share
Basic		$	0.70			$	(0.14	)		$	1.45			$	0.74
Diluted		$	0.69			$	(0.14	)		$	1.44			$	0.73
Weighted Average Common Shares Outstanding
Basic			140,414				140,836				141,227				140,438
Diluted			141,951				140,836				142,999				141,897

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Plains Exploration & Production Company

Operating Data

 

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
		2011				2010				2011				2010
						(Unaudited)
Daily Average Volumes
Oil and liquids sales (Bbls)			52,262				46,658				48,964				45,943
Gas (Mcf)
Production			324,288				283,447				305,691				260,402
Used as fuel			5,481				5,428				5,776				5,353
Sales			318,807				278,019				299,915				255,049
BOE
Production			106,310				93,899				99,912				89,343
Sales			105,396				92,994				98,950				88,451
Unit Economics (in dollars)
Average NYMEX Prices
Oil		$	94.06			$	85.24			$	95.11			$	79.61
Gas			3.57				3.81				4.04				4.38
Average Realized Sales Price Before Derivative Transactions
Oil (per Bbl)		$	87.02			$	73.17			$	85.53			$	68.14
Gas (per Mcf)			3.30				3.66				3.91				4.29
Per BOE			53.13				47.66				54.18				47.77
Cash Margin per BOE(1)
Oil and gas revenues		$	53.13			$	47.66			$	54.18			$	47.77
Costs and expenses
Lease operating expenses			(10.37	)			(8.75	)			(9.27	)			(8.13	)
Steam gas costs			(1.63	)			(1.67	)			(1.81	)			(2.06	)
Electricity			(1.14	)			(1.35	)			(1.14	)			(1.33	)
Production and ad valorem taxes			(1.66	)			(0.95	)			(1.53	)			(0.91	)
Gathering and transportation			(1.78	)			(1.52	)			(1.72	)			(1.57	)
Oil and gas related DD&A			(21.22	)			(17.37	)			(17.76	)			(15.87	)
Gross margin (GAAP)			15.33				16.05				20.95				17.90
Oil and gas related DD&A			21.22				17.37				17.76				15.87
Realized loss on derivative instruments			(0.84	)			(0.77	)			(1.42	)			(1.02	)
Cash margin (non-GAAP)		$	35.71			$	32.65			$	37.29			$	32.75
Oil and gas capital expenditures accrued ($ in thousands)(2)		$	492,235			$	300,895			$	1,856,377			$	1,082,246

 

(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 December 31, 2011
		Oil				Gas				BOE
		(per Bbl)				(per Mcf)
Average Realized Sales Price
Average realized price before derivative instruments (GAAP) (1)		$	87.02			$	3.30			$	53.13
Realized (loss) gain on derivative instruments			(3.12	)			0.23				(0.84	)
Realized cash price including derivative settlements (non-GAAP)		$	83.90			$	3.53			$	52.29
		Three Months Ended December 31, 2010
		Oil				Gas				BOE
		(per Bbl)				(per Mcf)
Average Realized Sales Price
Average realized price before derivative instruments (GAAP) (1)		$	73.17			$	3.66			$	47.66
Realized (loss) gain on derivative instruments			(4.16	)			0.44				(0.77	)
Realized cash price including derivative settlements (non-GAAP)		$	69.01			$	4.10			$	46.89
		Twelve Months Ended December 31, 2011
		Oil				Gas				BOE
		(per Bbl)				(per Mcf)
Average Realized Sales Price
Average realized price before derivative instruments (GAAP) (1)		$	85.53			$	3.91			$	54.18
Realized (loss) gain on derivative instruments			(3.31	)			0.07				(1.42	)
Realized cash price including derivative settlements (non-GAAP)		$	82.22			$	3.98			$	52.76
		Twelve Months Ended December 31, 2010
		Oil				Gas				BOE
		(per Bbl)				(per Mcf)
Average Realized Sales Price
Average realized price before derivative instruments (GAAP) (1)		$	68.14			$	4.29			$	47.77
Realized (loss) gain on derivative instruments			(4.22	)			0.41				(1.02	)
Realized cash price including derivative settlements (non-GAAP)		$	63.92			$	4.70			$	46.75

 

(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)

 

		Twelve Months Ended
		December 31,
		2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	206,679			$	103,265
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion			681,655				551,118
Impairment of oil and gas properties			—				59,475
Deferred income tax expense			160,214				193,835
Debt extinguishment costs			2,844				1,189
(Gain) loss on mark-to-market derivative contracts			(81,981	)			60,695
Loss on investment measured at fair value			52,675				1,551
Non-cash compensation			49,193				50,875
Other non-cash items			(5,559	)			1,043
Change in assets and liabilities from operating activities			45,035				(110,576	)
Net cash provided by operating activities			1,110,755				912,470
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties			(1,783,304	)			(1,048,858	)
Acquisition of oil and gas properties			(40,515	)			(554,685	)
Proceeds from sales of oil and gas properties and related assets, net of costs and expenses			736,228				73,965
Derivative settlements			(55,412	)			(29,921	)
Additions to other property and equipment			(13,140	)			(15,809	)
Other			1,552				—
Net cash used in investing activities			(1,154,591	)			(1,575,308	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities			6,305,300				3,332,610
Repayments of revolving credit facilities			(6,190,300	)			(2,942,610	)
Principal payments of long-term debt			(1,295,737	)			—
Proceeds from issuance of Senior Notes			1,600,000				300,000
Costs incurred in connection with financing arrangements			(30,239	)			(22,771	)
Purchase of treasury stock			(361,729	)			—
Net proceeds from issuance of noncontrolling interest in the form of preferred stock of subsidiary			430,246				—
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary			(1,050	)			—
Other			9				184
Net cash provided by financing activities			456,500				667,413
Net increase in cash and cash equivalents			412,664				4,575
Cash and cash equivalents, beginning of period			6,434				1,859
Cash and cash equivalents, end of period		$	419,098			$	6,434

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Plains Exploration & Production Company

Consolidated Balance Sheets

(in thousands of dollars)

 

		December 31,				December 31,
		2011				2010
ASSETS
Current Assets
Cash and cash equivalents		$	419,098			$	6,434
Accounts receivable			302,675				269,024
Commodity derivative contracts			50,964				—
Inventories			20,173				24,406
Investment			611,671				—
Deferred income taxes			20,723				74,086
Prepaid expenses and other current assets			16,073				28,937
			1,441,377				402,887
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization			12,016,252				9,975,056
Not subject to amortization			2,409,449				3,304,554
Other property and equipment			145,959				137,150
			14,571,660				13,416,760
Less allowance for depreciation, depletion, amortization and impairment			(6,846,365	)			(6,196,008	)
			7,725,295				7,220,752
Goodwill			535,140				535,144
Commodity Derivative Contracts			12,678				—
Investment			—				664,346
Other Assets			76,982				71,808
		$	9,791,472			$	8,894,937
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable		$	385,231			$	284,628
Commodity derivative contracts			3,761				52,971
Royalties and revenues payable			97,095				70,990
Interest payable			39,342				49,127
Other current liabilities			100,757				75,973
			626,186				533,689
Long-Term Debt			3,760,952				3,344,717
Other Long-Term Liabilities
Asset retirement obligation			230,633				225,571
Commodity derivative contracts			823				24,740
Other			15,749				28,205
			247,205				278,516
Deferred Income Taxes			1,461,897				1,355,050
Equity
Stockholders’ equity
Common stock			1,439				1,439
Additional paid-in capital			3,434,928				3,427,869
Retained earnings			337,991				148,620
Treasury stock, at cost			(509,722	)			(194,963	)
			3,264,636				3,382,965
Noncontrolling interest
Preferred stock of subsidiary			430,596				—
			3,695,232				3,382,965
		$	9,791,472			$	8,894,937

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Page 12

 

Plains Exploration & Production Company

Summary of Open Derivative Positions

At February 22, 2012

 

								Average
		Instrument		Daily		Average		Deferred
Period(1)		Type		Volumes		Price(2)		Premium		Index
Sales of Crude Oil Production
2012
Feb - Dec		Three-way  collars(3)		40,000 Bbls		$100.00 Floor with an $80.00 Limit		—		Brent
						$120.00 Ceiling
2013
Jan - Dec		Put options(4)		17,000 Bbls		$90.00 Floor with a $70.00 Limit		$6.253 per Bbl		Brent
Jan - Dec		Put options(5)		13,000 Bbls		$100.00 Floor with an $80.00 Limit		$6.800 per Bbl		Brent
Jan - Dec		Three-way  collars(6)		25,000 Bbls		$100.00 Floor with an $80.00 Limit		—		Brent
						$124.29 Ceiling
Jan - Dec		Three-way  collars(7)		5,000 Bbls		$90.00 Floor with a $70.00 Limit		—		Brent
						$126.08 Ceiling
2014
Jan - Dec		Put options(4)		20,000 Bbls		$90.00 Floor with a $70.00 Limit		$6.555 per Bbl		Brent
Sales of Natural Gas Production
2012
Feb - Dec		Put options(8)		120,000 MMBtu		$4.30 Floor with a $3.00 Limit		$0.298 per MMBtu		Henry Hub
Feb - Dec		Three-way  collars(9)		40,000 MMBtu		$4.30 Floor with a $3.00 Limit		—		Henry Hub
						$4.86 Ceiling
2013
Jan - Dec		Swap  contracts(10)		110,000 MMBtu		$4.27		—		Henry Hub
2014
Jan - Dec		Swap  contracts(10)		70,000 MMBtu		$4.16		—		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 $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $120 per barrel if the index price is greater than the $120 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $120 per barrel, no cash settlement is required.

(4)	If the index price is less than the $90 per barrel floor, we receive the difference between the $90 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 $90 per barrel, we pay only the option premium.

(5)	If the index price is less than the $100 per barrel floor, we receive the difference between the $100 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 $100 per barrel, we pay only the option premium.

(6)

If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $124.29 per barrel if the index price is greater than the $124.29 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $124.29 per barrel, no cash settlement is required.

(7)

If the index price is less than the $90 per barrel floor, we receive the difference between the $90 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $126.08 per barrel if the index price is greater than the $126.08 per barrel ceiling. If the index price is at or above $90 per barrel but at or below $126.08 per barrel, no cash settlement is required.

(8)	If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above $4.30 per MMBtu, we pay only the option premium.

(9)

If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and $4.86 per MMBtu if the index price is greater than the $4.86 per MMBtu ceiling. If the index price is at or above $4.30 per MMBtu but at or below $4.86 per MMBtu, no cash settlement is required.

(10)

If the index price is less than the fixed price ($4.27 per MMBtu for the 2013 contracts and $4.16 per MMBtu for the 2014 contracts), 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.

Derivative Settlements

(in thousands of dollars)

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

 

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
		2011				2010				2011				2010
Oil sales		$	(15,008	)		$	(17,854	)		$	(59,217	)		$	(70,834	)
Natural gas sales			6,881				11,285				7,915				37,996
		$	(8,127	)		$	(6,569	)		$	(51,302	)		$	(32,838	)

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Page 13

 

Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure

The following tables reconcile net income (GAAP) to adjusted net income and adjusted net income attributable to common stockholders (non-GAAP) for the three and twelve months ended December 31, 2011 and 2010. 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
		December 31,
		2011				2010
		(millions of dollars)
Net income (loss) (GAAP)		$	99.1			$	(19.5	)
Unrealized loss on mark-to-market derivative contracts			11.5				83.9
Realized loss on mark-to-market derivative contracts (1)			(8.0	)			(6.6	)
Unrealized (gain) loss on investment measured at fair value			(232.3	)			1.6
Debt extinguishment costs			121.0				—
Adjust income taxes (2)			38.7				(31.1	)
Adjusted net income (non-GAAP)		$	30.0			$	28.3
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary			(1.4	)
Adjusted net income attributable to common stockholders (non-GAAP)		$	28.6
		Twelve Months Ended
		December 31,
		2011				2010
		(millions of dollars)
Net income (GAAP)		$	206.7			$	103.3
Unrealized (gain) loss on mark-to-market derivative contracts			(82.0	)			60.7
Realized loss on mark-to-market derivative contracts (1)			(51.3	)			(32.8	)
Unrealized loss on investment measured at fair value			52.7				1.6
Impairment of oil and gas properties			—				59.5
Debt extinguishment costs			121.0				1.2
Legal recovery			—				(8.4	)
Other non-operating income			—				(9.3	)
Adjust income taxes (2)			(22.7	)			(25.6	)
Adjusted net income (non-GAAP)		$	224.4			$	150.2
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary			(1.4	)
Adjusted net income attributable to common stockholders (non-GAAP)		$	223.0

 

(1)	The amounts presented in the above tables 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 36% and 50% for the three months ended December 31, 2011 and 2010, respectively. Tax rates assumed based upon adjusted earnings are 41% and 46% for the twelve months ended December 31, 2011 and 2010. Tax rates exclude the effects of nonrecurring tax related expenses and benefits.

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Page 14

 

Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure

The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Operating Cash Flow (non-GAAP) for the three and twelve months ended December 31, 2011 and 2010. 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 and to exclude certain other items.

 

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
		2011				2010				2011				2010
		(millions of dollars)
Net income (loss)		$	99.1			$	(19.5	)		$	206.7			$	103.3
Items not affecting operating cash flows
Depreciation, depletion, amortization and accretion			215.6				158.5				681.7				551.1
Impairment of oil and gas properties			—				—				—				59.5
Deferred income tax expense			55.0				22.5				160.2				193.8
Debt extinguishment costs			121.0				—				121.0				1.2
Unrealized loss (gain) on mark-to-market derivative contracts			11.5				83.9				(82.0	)			60.7
Unrealized (gain) loss on investment measured at fair value			(232.3	)			1.6				52.7				1.6
Non-cash compensation			22.0				14.5				49.2				50.9
Other non-cash items			0.8				(1.5	)			(5.6	)			1.0
Realized loss on mark-to-market derivative contracts			(8.0	)			(6.4	)			(55.4	)			(29.9	)
Legal recovery and other			—				—				—				(16.5	)
Operating cash flow (non-GAAP)		$	284.7			$	253.6			$	1,128.5			$	976.7
Reconciliation of non-GAAP to GAAP measure
Operating cash flow (non-GAAP)		$	284.7			$	253.6			$	1,128.5			$	976.7
Cash portion of debt extinguishment costs			(118.2	)			—				(118.2	)			—
Legal recovery and other			—				—				—				16.5
Changes in assets and liabilities from operating activities			13.6				(24.7	)			45.1				(110.6	)
Realized loss on mark-to-market derivative contracts			8.0				6.4				55.4				29.9
Net cash provided by operating activities (GAAP)		$	188.1			$	235.3			$	1,110.8			$	912.5

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Page 15

 

Plains Exploration & Production Company

Proved Reserves, Reserve Replacement Ratio, PV-10 to Standardized Measure Reconciliation

 

Estimated Proved Reserves (MMBOE):
2010 Year-end proved reserves			416.1
2011 Extensions, discoveries and revisions and other additions			81.0
2011 Divestments			(49.7	)
2011 Production			(36.5	)
2011 Year-end proved reserves			410.9
Reserve Replacement Ratio(1)			222	%
Estimated Pro Forma Proved Reserves (MMBOE)(2)
2010 Year-end proved reserves			355.0
2011 Extensions, discoveries and revisions and other additions			88.1
2011 Divestments			(1.8	)
2011 Pro forma production			(30.4	)
2011 Year-end proved reserves			410.9
Pro Forma Reserve Replacement Ratio(1)			290	%
PV-10 to Standardized Measure Reconciliation (in millions)
Estimated undiscounted future net cash flows before income taxes		$	15,942.2
Present value of estimated future net cash flows before income taxes (PV-10)(3)(4)		$	7,884.5
Discounted future income taxes			(2,750.3	)
Standardized measure of discounted net cash flows		$	5,134.2

 

(1)

Calculation: reserve extensions, discoveries, revisions and other additions divided by production. The Reserve Replacement Ratio is an indicator of our ability to replace annual production volume and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. Reserve Replacement Ratio is a statistical indicator which has limitations, including its predictive and comparative value. As such, this metric should not be considered in isolation or as a substitute for an analysis of our performance as reported under GAAP. Furthermore, this metric may not be comparable to similarly titled measurements used by other companies.

(2)	Reflects the impact of fourth-quarter property divestments.

(3)

PV-10 is PXP’s estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. PV-10 is a non-GAAP financial measure and generally differs from the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the Standardized Measure as computed under GAAP.

(4)

PXP believes PV-10 to be an important measure for evaluating the relative significance of its oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, PXP believes the use of a pre-tax measure is valuable for evaluating its company. PXP believes that most other companies in the oil and gas industry calculate PV-10 on the same basis.

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Page 16

 

Plains Exploration & Production Company

Costs Incurred & Finding and Development Costs

 

Costs Incurred ($ Millions):
Property acquisition costs:
Unproved properties		$	36.6
Proved properties			9.2
Exploration costs			1,147.9
Development costs			708.5
Total costs incurred(1)		$	1,902.2
Pro Forma Costs Incurred ($ Millions):(2)
Property acquisition costs:
Unproved properties		$	36.2
Proved properties			1.4
Exploration costs			1,027.9
Development costs			521.3
Total costs incurred		$	1,586.8
Finding and Development Costs (F&D)(3)
All-In F&D Costs per BOE		$	23.48
Calculation: Total costs incurred divided by reserve extensions, discoveries, revisions and other additions
All-In F&D Costs Pro Forma for Asset Sales per BOE		$	18.01
Calculation: Total pro forma costs incurred divided by pro forma reserve extensions, discoveries, revisions and other additions

 

(1)	Includes capitalized interest expense of $115.4 million and capitalized general and administrative expense of $77.1 million.

(2)	Reflects the impact of fourth quarter property divestments.

(3)

Finding and Development Costs per BOE is a non-GAAP metric commonly used in the exploration and production industry. The calculations presented are described above. This calculation does not include the future development costs required for the development of proved undeveloped reserves. Finding and Development Costs per BOE is a statistical indicator which has limitations, including its predictive and comparative value. As such, this metric should not be considered in isolation or as a substitute for an analysis of our performance as reported under GAAP. Furthermore, this metric may not be comparable to similarly titled measurements used by other companies.

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Page 17

 

Plains Exploration & Production Company

Full-Year 2012 Operating and Financial Guidance

 

		Year Ended December 31, 2012
Production Volumes (MBOE/day)
Total Production volumes sold		92		—		96
Oil		55%		—		57%
NGLs		3%		—		4%
Natural Gas		42%		—		39%
Product Price Realization (Unhedged)
Oil - Brent		98%		—		102%
Oil - Transportation Expense				$5.00
NGLs - WTI				40%
Gas - Henry Hub				100%
Gas - Transportation Expense				$0.15
Production Costs per BOE
Lease operating expense		$  9.50		—		$10.50
Steam gas costs(1)		$  1.25		—		$  1.75
Electricity		$  1.20		—		$  1.40
Production and ad valorem taxes(2)		$  2.00		—		$  2.25
Gathering and transportation		$  1.50		—		$  2.00
Depreciation, Depletion and Amortization per BOE		$     22		—		$     24
General and Administrative Expenses (in millions)
Cash		$   107		—		$   111
Stock-based compensation(3)		$     40		—		$     46
Interest Expense
Average revolver balance		30 Day LIBOR + 1.50% -2.50%
$79 Million Senior Notes				7.750%
$185 Million Senior Notes				10.000%
$77 Million Senior Notes				7.000%
$400 Million Senior Notes				7.625%
$400 Million Senior Notes				8.625%
$300 Million Senior Notes				7.625%
$600 Million Senior Notes				6.625%
$1,000 Million Senior Notes				6.750%
Effective Tax Rate		38%       —         40%
Weighted Average Equivalent Shares Outstanding (in thousands)
Basic				127,600
Diluted				129,300
Capital Expenditures (in millions)(4)
PXP				$1,366
Gulf of Mexico - Plains Offshore				234
Total				$1,600

 

(1)	Steam gas costs assume a base SoCal Border index price of $3.02 per MMBtu. The purchased volumes are anticipated to be 43,000 - 45,000 MMBtu per day.

(2)	Production and ad valorem taxes assume base index prices of $110.00 per barrel and $3.00 per MMBtu. (Note: Brent index price for oil)

(3)	Based on current outstanding and projected awards and current stock price.

(4)	Includes capitalized interest and general and administrative expenses.

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