PLAINS EXPLORATION & PRODUCTION CO - FORM 8-K/A - EX-99.3 - UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Attached files

file	filename
8-K/A - FORM 8-K AMENDMENT - PLAINS EXPLORATION & PRODUCTION CO	d453647d8ka.htm
EX-99.1 - UNAUDITED INTERIM STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES - PLAINS EXPLORATION & PRODUCTION CO	d453647dex991.htm
EX-99.2 - UNAUDITED INTERIM STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES - PLAINS EXPLORATION & PRODUCTION CO	d453647dex992.htm

Exhibit 99.3

PLAINS EXPLORATION & PRODUCTION COMPANY

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Acquisition of Gulf of Mexico Oil and Gas Properties from BP and Shell

BP Acquisition. On September 4, 2012, Plains Exploration & Production Company (“PXP” or the “Company”) entered into a purchase and sale agreement (the “BP PSA”) to acquire from BP Exploration & Production Inc. and BP America Production Company (“BP”), 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, in exchange for $5.55 billion in cash (the “BP Acquisition”). On November 30, 2012, PXP closed the BP Acquisition and after pre-closing adjustments from the effective date of October 1, 2012, which resulted in a reduction to the $5.55 billion purchase price of approximately $191.0 million, PXP paid $5.36 billion in cash, which includes the deposit of $555 million previously paid by PXP to BP.

Shell Acquisition. On September 7, 2012, PXP entered into a purchase and sale agreement to acquire from Shell Offshore Inc. (“Shell”), certain oil and gas interests in the Holstein Field, located in the Gulf of Mexico, in exchange for $560 million in cash (the “Shell Acquisition”). On November 30, 2012, PXP closed the Shell Acquisition and after pre-closing adjustments from the effective date of October 1, 2012, which resulted in a reduction to the $560 million purchase price of approximately $27.9 million, PXP paid $532.1 million in cash.

PXP funded the acquisitions from BP and Shell with borrowings under its Amended Credit Agreement (as defined below) and the net proceeds from the issuance of senior notes in October 2012.

Description of the deepwater Gulf of Mexico oil and gas properties acquired from BP and Shell. Upon completion of the BP Acquisition and the Shell Acquisition (collectively, the “GOM Acquisition”), we hold a 100% working interest and operate the Holstein, Horn Mountain and Marlin, Dorado, King Fields. Additionally, we hold a 31% working interest in the Ram Powell Field and 33.33% working interest in the Diana Hoover Field, and we are a non-operator of those fields.

•

The Holstein Field is located in Green Canyon blocks 644, 645 and 688. The Holstein platform is a truss spar in water depth of approximately 4,300 feet, and production commenced in December 2004. The capacity is approximately 113,500 barrels of oil per day, 142,300 thousand cubic feet (“Mcf”) of gas per day and 45,900 barrels of water per day. We plan to upgrade the Holstein drilling rig and infrastructure and focus on further developing existing field pay intervals through recompletion, sidetrack, and water injection projects. In addition, we plan to develop and explore via subsea tiebacks deeper potential on the Holstein structure and leases in the Green Canyon area.

•

The Horn Mountain Field is located in Mississippi Canyon blocks 82, 126 and 127. The Horn Mountain platform is a truss spar in water depth of approximately 5,400 feet, and production commenced in November 2002. The capacity is approximately 75,000 barrels of oil per day, 72,000 Mcf of gas per day and 30,000 barrels of water per day. We plan to focus on further developing the field primarily through sidetracks of existing producing wells to undrained portions of the field pay reservoir intervals. In addition, we plan to develop and explore via subsea tiebacks additional amplitude driven resource opportunities as well as deeper potential on the Horn Mountain leases.

•

The Marlin Hub is the production facility for three fields: the Marlin Field (S/2 Viosca Knoll block 871 and N/2 Viosca Knoll block 915), the Dorado Field (S/2 Viosca Knoll block 915) and the King Field (Mississippi Canyon 84, 85, 128 and 129). The Marlin Hub is a tension leg platform in water depth of approximately 3,200 feet, and production commenced in December 2000. The capacity is approximately 60,000 barrels of oil per day, 235,000 Mcf of gas per day and 20,000 barrels of water per day. The Marlin Field currently produces via a combination of platform and subsea tieback wells while the Dorado and King Fields currently produce exclusively via subsea wells and tieback infrastructure. Our development plans focus on installation of additional compression, deepening of existing wells, and drilling of additional producing wells to optimize recovery and target additional resources primarily in the King and Dorado Fields. In addition, we plan to target deeper potential in the King Field for future tieback to the Marlin Hub.

•

The Ram Powell Field is located in Viosca Knoll blocks 911 through 913 and 955 through 957. The Ram Powell platform is a tension leg platform in water depth of approximately 3,200 feet, commissioned in 1997 with capacity of approximately 70,000 barrels of oil per day and 310,000 Mcf of gas per day. A drilling rig is scheduled to be installed on the platform in the fourth quarter of 2012. We intend to participate in production optimization projects as well as drilling opportunities in the main field pay intervals as planned by the operator.

•

The Diana Field is located in East Breaks blocks 945, 946 and 989, and the Hoover Field is located in Alaminos Canyon blocks 25 and 26. The Hoover platform is a deep draft caisson vessel located in Alaminos Canyon block 25 in water depth of approximately 4,800 feet. Production commenced May 2000, and the platform has a capacity of approximately 100,000 barrels of oil per day, 325,000 Mcf of gas per day and 60,000 barrels of water per day. While the Hoover Field is developed via platform wells, production from the Hoover Field is produced via subsea tieback at the Hoover platform. Several additional drilling opportunities exist in established field pay intervals in the Diana Field.

Product markets. Our share of Gulf of Mexico oil and gas production will be sold under a series of arms-length contracts awarded on a competitive bid basis or entered into following negotiations. Oil will be sold directly to companies with refineries in the Gulf Coast regions of Texas and Louisiana at prices based on widely-used industry benchmarks. Gas will be processed in one of three large onshore gas plants, where we will be paid our contractual share of revenues from the sale of natural gas liquids. We will sell or deliver our residue gas to various industrial and energy markets as well as intrastate and interstate pipeline systems.

Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production are subject to wide fluctuations and depend on numerous factors beyond our control, including location and quality differentials, seasonality, economic conditions, foreign imports,

political conditions in other oil-producing and gas-producing countries, the actions of OPEC, and domestic government regulation, legislation and policies. Decreases in oil and gas prices have had, and could have in the future, an adverse effect on the carrying value and volumes of our proved reserves and our revenues, profitability and cash flow.

We use a series of pipelines, some of which are ours, to transport our oil and gas production from the platforms to shore. These movements are made under a combination of life-of-lease contracts and tariffs subject to Federal Energy Regulatory Commission regulation. Currently all the pipelines we rely upon are operating normally, but natural disasters or other operational situations beyond our control could result in increased transportation costs to us or require us to find transportation alternatives. Such circumstances may also result in significant decreases in our oil and gas production.

Financing. On November 30, 2012, PXP entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (the “Amended Credit Agreement”), which amends and restates PXP’s senior revolving credit facility that closed on August 3, 2010 (as amended to date, the “Prior Credit Facility”). The Amended Credit Agreement provides for (i) a 5-year revolving line of credit, a 5-year term loan and a 7-year term loan and (ii) an initial borrowing base of $5.18 billion which will be redetermined on an annual basis, with PXP and the revolving lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on PXP’s oil and gas properties, reserves, other indebtedness (including the outstanding commitments under the credit agreement dated November 18, 2011 among PXP’s subsidiary, Plains Offshore Operations Inc., JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto from time to time (as amended, the “POOI Credit Agreement”)) and other relevant factors. The aggregate commitments of the revolving lenders under the Amended Credit Agreement are $3.0 billion and can be increased to $3.6 billion if certain conditions are met. The outstanding principal balance of the 5-year term loan is $750 million and the outstanding principal balance of the 7-year term loan is $1.25 billion. The revolving line of credit under the Amended Credit Agreement also includes a $750 million sub limit on letters of credit and a $100 million sub limit for swingline loans.

Revolving amounts borrowed under the Amended Credit Agreement bear an interest rate, at PXP’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%; (ii) a variable amount ranging from 0.50% to 1.50% plus the ABR, which will be 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%; or (iii) the over-night federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The Eurodollar spread and the ABR spread set forth above will be increased 0.25% while any term loans are outstanding. The additional variable amount of interest payable on outstanding revolving borrowings is based on the utilization rate as a percentage of the total amount of funds borrowed under the Amended Credit Agreement and the POOI Credit Agreement to the borrowing base. The 5-year and 7-year term loans bear an interest rate, at PXP’s election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus 3.00% or (ii) 2.00% plus the ABR, which will be 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%. Notwithstanding the foregoing, in no event shall the LIBOR rate for any 7-year term loan be less than 1.00% per year. Letter of credit fees under PXP’s Amended Credit Agreement 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 are based on the utilization rate and range from 0.375% to 0.50% of the amount available for borrowing.

In October 2012, we completed an underwritten public offering of $3.0 billion of senior notes, consisting of $1.5 billion in aggregate principal amount of 6 1/2% Senior Notes due 2020, issued at par, and $1.5 billion in aggregate principal amount of 6 7/8% Senior Notes due 2023, issued at par.

The proceeds of the Amended Credit Agreement and the $3.0 billion of senior notes offered were used (i) to refinance certain existing indebtedness of PXP, (ii) to pay the cash consideration for the GOM Acquisition, (iii) to pay the fees and expenses incurred in connection with the GOM Acquisition and related financing transactions and (iv) for other general corporate purposes.

Unaudited Pro Forma Condensed Combined Financial Statements

The unaudited pro forma condensed combined balance sheet at September 30, 2012, and the unaudited pro forma condensed combined statements of income for the nine months ended September 30, 2012, and for the year ended December 31, 2011, of PXP reflect the pro forma effects of:

•

BP Acquisition. The acquisition of certain oil and gas working interests in and near the Holstein, Diana, Hoover, Horn Mountain, Marlin, Dorado, King and Ram Powell Fields located in the Gulf of Mexico, in exchange for $5.36 billion in cash, as adjusted for working capital and other pre-closing adjustments. PXP assumed the plugging and abandonment obligations for these properties. We did not acquire any derivatives or retain any corporate management or staff.

•

Shell Acquisition. The acquisition of certain oil and gas interests in the Holstein Field located in the Gulf of Mexico, in exchange for $532.1 million in cash, as adjusted for working capital and other pre-closing adjustments. PXP assumed the plugging and abandonment obligations for these properties. We did not acquire any derivatives or retain any corporate management or staff.

•

Financing. Borrowings under our Amended Credit Agreement, which include (i) approximately $1.5 billion under the senior secured 5-year revolving credit facility, (ii) the $750 million senior secured 5-year term loan and (iii) the $1.25 billion 7-year term loan. Borrowings under our Amended Credit Agreement and the $3.0 billion of senior notes offered were used as follows:

•

refinance certain existing indebtedness of PXP;

•

pay the cash consideration for the GOM Acquisition;

•

pay the fees and expenses incurred in connection with the GOM Acquisition and related financing transactions; and

•

other general corporate purposes.

•

Panhandle Divestment. Additionally, in December 2011, and upon resolution of certain third party preferential rights during the first quarter of 2012, PXP and certain of its subsidiaries completed the divestment of its Texas Panhandle properties to an affiliate of Linn Energy, LLC. After the exercise of third party preferential rights and preliminary closing adjustments, we received approximately $598 million in cash in exchange for our working interests in oil and gas properties located in the Texas Panhandle. At September 30, 2012, we continued to have interests in approximately 40,000 gross leasehold acres in the Texas Panhandle and expected to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments. The cash proceeds received, net of approximately $10 million in transaction costs, were primarily used to repay the outstanding borrowings under the senior revolving credit facility. Our aggregate working interest in the Texas Panhandle properties generated total sales volumes of approximately 75 million cubic feet equivalent (“MMcfe”) per day during 2011 and had 263 billion cubic feet equivalent (“Bcfe”) of estimated proved reserves as of December 31, 2010. The Panhandle Divestment was completed pursuant to a Purchase and Sale Agreement dated as of November 3, 2011, and effective as of November 1, 2011.

The unaudited pro forma condensed combined statements of income for the nine month period ended September 30, 2012, and for the year ended December 31, 2011, and the unaudited pro forma condensed combined balance sheet at September 30, 2012, have been prepared based on our historical consolidated statements of income for such periods and our historical consolidated balance sheet at September 30, 2012. The pro forma condensed combined statements of income assume that the GOM Acquisition and the associated financing and the Panhandle Divestment occurred on January 1, 2011, and the unaudited pro forma condensed combined balance sheet assumes the GOM Acquisition and the associated financing occurred on September 30, 2012. The Panhandle Divestment is reflected in our historical balance sheet at September 30, 2012.

The unaudited pro forma condensed combined statements of income do not purport to represent what our results of operations would have been if these transactions had occurred on January 1, 2011. PXP’s management believes the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to the transactions described above. Pursuant to Securities and Exchange Commission rules for pro forma financial statements, no pro forma adjustments may be made with respect to nonrecurring charges or credits directly attributable to these transactions that are included in our historical statement of income. Accordingly, in the unaudited pro forma condensed combined statement of income for the nine months ended September 30, 2012, no pro forma adjustments have been made to exclude nonrecurring expenses we would have incurred as a result of the GOM Acquisition and related financings and debt extinguishment.

The unaudited pro forma condensed combined financial statements and accompanying notes should be read together with our Annual Report on Form 10-K for the year ended December 31, 2011, and our quarterly report on Form 10-Q for the period ended September 30, 2012. The unaudited pro forma condensed consolidated financial statements and accompanying notes also should be read in conjunction with the historical Statements of Revenues and Direct Operating Expenses for the BP Acquisition and the notes thereto included in PXP’s Current Report on Form 8-K filed on October 23, 2012 and the Statements of Revenues and Direct Operating Expenses for the Shell Acquisition and the notes thereto included in PXP’s Current Report on Form 8-K filed on October 23, 2012.

PLAINS EXPLORATION & PRODUCTION COMPANY

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

AT SEPTEMBER 30, 2012

(in thousands of dollars)


	PXP			Pro Forma Adjustments
	Historical			BP Acquisition			Shell Acquisition			(Note 3)			Pro Forma
				(Note 2)
ASSETS
Current Assets
										$	6,490,261
											(895,000	)
											(118,212	)
											(73,147	)
Cash and cash equivalents	$	217,018		$	(4,804,049	)	$	(532,122	)		(67,730	)	$	217,019
Investment		519,370			—			—			—			519,370
Other current assets		551,219			8,988			2,410			(45,700	)		516,917

		1,287,607			(4,795,061	)		(529,712	)		5,290,472			1,253,306

Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		14,083,960			3,897,503			301,894			—			18,283,357
Not subject to amortization		1,718,876			1,768,349			278,709			—			3,765,934
Other property and equipment		150,031			—			—			—			150,031

		15,952,867			5,665,852			580,603			—			22,199,322
Less allowance for depreciation, depletion, amortization and impairment		(7,473,140	)		—			—			—			(7,473,140	)

		8,479,727			5,665,852			580,603			—			14,726,182
Goodwill		535,140			—			—			—			535,140
Deposit Related to the Gulf of Mexico Acquisition		555,000			(555,000	)		—			—			—
											118,212
Other Assets		117,321			—			—			(3,374	)		232,159

	$	10,974,795		$	315,791		$	50,891		$	5,405,310		$	16,746,787

LIABILITIES AND EQUITY
Current Liabilities	$	778,544		$	—		$	—		$	(73,147	)	$	705,397

Long-Term Debt
											1,539,397
Senior revolving credit facility		895,000			—			—			(895,000	)		1,539,397
5-year term loan		—			—			—			730,533			730,533
7-year term loan		—			—			—			1,220,331			1,220,331
Senior notes		3,621,571			—			—			3,000,000			6,621,571

		4,516,571			—			—			5,595,261			10,111,832

Other Long-Term Liabilities
Asset retirement obligation		242,390			311,258			50,415			—			604,063
Other		21,372			—			—			—			21,372

		263,762			311,258			50,415			—			625,435

											(32,894	)
											(45,700	)
Deferred Income Taxes		1,691,473			—			—			(26,650	)		1,586,229

Equity
Stockholders’ equity		3,286,893			4,533			476			(11,560	)		3,280,342
Noncontrolling interest		437,552			—			—			—			437,552

		3,724,445			4,533			476			(11,560	)		3,717,894

	$	10,974,795		$	315,791		$	50,891		$	5,405,310		$	16,746,787

The accompanying notes are an integral part of these financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012

(in thousands, except per share data)


								Pro Forma
	PXP			BP		Shell		Adjustments
	Historical			Historical		Historical		(Note 3)			Pro Forma
Revenues
Oil and gas sales	$	1,689,543		$	1,312,807	$	144,269	$	—		$	3,146,619
Other operating revenues		6,560			—		—		—			6,560

		1,696,103			1,312,807		144,269		—			3,153,179

Costs and Expenses
									12,742	(A)
Production costs		441,068			130,658		31,022		357	(B)		615,847

Revenues in excess of direct operating expenses		1,255,035			1,182,149		113,247		(13,099	)		2,537,332

General and administrative		109,281							—			109,281
Depreciation, depletion, amortization and accretion		710,277							476,535	(C)		1,186,812
Other operating income		(3,142	)						—			(3,142	)

		1,257,484							489,634			1,908,798

Income From Operations		438,619							(489,634	)		1,244,381

Other (Expense) Income
									(229,798	)(D)
Interest expense		(157,404	)						87,188	(D)		(300,014	)
Debt extinguishment costs		(5,167	)						—			(5,167	)
Gain on mark-to-market derivative contracts		12,573							—			12,573
Loss on investment measured at fair value		(92,301	)						—			(92,301	)
Other income		440							—			440

Income From Continuing
Operations Before Income Taxes		196,760							(632,244	)		859,912
Income tax expense		(81,762	)						(248,549	)(E)		(330,311	)

Net Income From Continuing Operations		114,998							(880,793	)		529,601
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		(27,206	)						—			(27,206	)

Net Income Attributable to Common Stockholders	$	87,792						$	(880,793	)	$	502,395

Earnings From Continuing Operations Per Share
Basic	$	0.68									$	3.87
Diluted	$	0.67									$	3.81

Weighted Average Common Shares Outstanding
Basic		129,806										129,806

Diluted		131,774										131,774

The accompanying notes are an integral part of these financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME

FOR THE YEAR ENDED DECEMBER 31, 2011

(in thousands, except per share data)


								Pro Forma
	PXP			BP		Shell		Adjustments
	Historical			Historical		Historical		(Note 3)			Pro Forma
Revenues
Oil and gas sales	$	1,956,876		$	1,854,708	$	218,837	$	(176,103	)(F)	$	3,854,318
Other operating revenues		7,612			—		—		—			7,612

		1,964,488			1,854,708		218,837		(176,103	)		3,861,930

Costs and Expenses
									(46,386	)(F)
									16,949	(A)
Production costs		558,975			169,781		40,099		(5,749	)(B)		733,669

Revenues in excess of direct operating expenses		1,405,513			1,684,927		178,738		(140,917	)		3,128,261

General and administrative		134,044							3,000	(G)		137,044
Depreciation, depletion, amortization and									582,784	(C)
accretion		681,655							(87,139	)(H)		1,177,300
Other operating income		(735	)						—			(735	)

		1,373,939							463,459			2,047,278

Income From Operations		590,549							(639,562	)		1,814,652

Other (Expense) Income

									(337,928	)(D)
									101,232	(D)
									5,893	(I)
Interest expense		(161,316	)						5,829	(I)		(386,290	)
Debt extinguishment costs		(120,954	)						—			(120,954	)
Gain on mark-to-market derivative contracts		81,981							—			81,981
Loss on investment measured at fair value		(52,675	)						—			(52,675	)
Other income		3,356							—			3,356

Income From Continuing
Operations Before Income Taxes		340,941							(864,536	)		1,340,070
									(386,038	)(E)
Income tax expense		(134,262	)						11,565	(E)		(508,735	)

Net Income From Continuing Operations		206,679							(1,239,009	)		831,335
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		(1,400	)						—			(1,400	)

Net Income Attributable to Common Stockholders	$	205,279						$	(1,239,009	)	$	829,935

Earnings From Continuing Operations Per Share
Basic	$	1.45									$	5.88

Diluted	$	1.44									$	5.80

Weighted Average Shares Common Outstanding
Basic		141,227										141,227

Diluted		142,999										142,999

The accompanying notes are an integral part of these financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED

FINANCIAL STATEMENTS

Note 1 – Basis of Presentation

•

refinance certain existing indebtedness of PXP;

•

pay the cash consideration for the GOM Acquisition;

•

pay the fees and expenses incurred in connection with the GOM Acquisition and related financing transactions; and

•

other general corporate purposes.

•

The unaudited pro forma combined financial information includes adjustments to conform BP’s and Shell’s accounting for oil and gas properties to the full cost method. PXP follows the full cost method of accounting for oil and gas properties while BP and Shell follow the successful efforts method of accounting for oil and gas properties. Certain costs that are capitalized under the full cost method are expensed under the successful efforts method. These costs consist primarily of unsuccessful exploration drilling costs, geological and geophysical costs, delay rental on leases, abandonment costs and general and administrative expenses directly related to exploration and development activities.

•

Panhandle Divestment. Additionally, in December 2011, and upon resolution of certain third party preferential rights during the first quarter of 2012, PXP and certain of its subsidiaries completed the divestment of its Texas Panhandle properties to an affiliate of Linn Energy, LLC. After the exercise of third party preferential rights and preliminary closing adjustments, we received approximately $598 million in cash in exchange for our working interests in oil and gas properties located in the Texas Panhandle. At September 30, 2012, we continued to have interests in approximately 40,000 gross leasehold acres in the Texas Panhandle and expected to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments. The cash proceeds received, net of approximately $10 million in transaction costs, were primarily used to repay the outstanding borrowings under the senior revolving credit facility. Our aggregate working interest in the Texas Panhandle properties generated total sales volumes of approximately 75 MMcfe per day during 2011 and had 263 Bcfe of estimated proved reserves as of December 31, 2010. The Panhandle Divestment was completed pursuant to a Purchase and Sale Agreement dated as of November 3, 2011, and effective as of November 1, 2011.

The unaudited pro forma condensed combined statements of income do not purport to represent what our results of operations would have been if these transactions had occurred on January 1, 2011. PXP’s management believes the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to the transactions described above. Pursuant to Securities and Exchange Commission rules for pro forma financial statements, no pro forma adjustments may be made with respect to nonrecurring charges or credits directly attributable to these transactions that are included in our historical statement of income. Accordingly, in the unaudited pro forma condensed combined statement of income no pro forma adjustments have been made to exclude nonrecurring expenses we would have incurred as a result of the GOM Acquisition and related financings and debt extinguishment.

Note 2 – Acquisition Method

The pro forma condensed combined financial statements reflect the accounting for acquisitions in accordance with the Financial Accounting Standards Board Accounting Standards Codification Topic 805, Business Combinations. Under the acquisition method, the purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. The initial accounting for the GOM Acquisition is not complete and there may be additional adjustments to working capital, recognition of assets acquired and liabilities assumed and revisions to estimated amounts.

The following represents the purchase price allocation of the GOM Acquisition, as adjusted for working capital and other pre-closing adjustments (in thousands):

Purchase Price Allocation


	BP		Shell		Total
Assets:
Oil and natural gas properties - full cost method
Subject to amortization	$	3,897,503	$	301,894	$	4,199,397
Not subject to amortization		1,768,349		278,709		2,047,058

		5,665,852		580,603		6,246,455
Inventory		8,988		—		8,988
Other current assets		—		2,410		2,410

Total assets acquired		5,674,840		583,013		6,257,853

Liabilities:
Asset retirement obligation		311,258		50,415		361,673

Net assets acquired	$	5,363,582	$	532,598	$	5,896,180

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation.

Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates and are the most sensitive and subject to change.

Note 3 – Pro Forma Adjustments and Assumptions

The following represents the allocation of the purchase price to assets acquired and liabilities assumed based on their relative fair value, as of September 30, 2012 (in thousands):


Property Acquisition Costs
PXP Senior revolving credit facility	$	644,397
$750 million 3.31% term loan		730,533
$1.25 billion 4.0% term loan		1,220,331
Senior notes		3,000,000
Asset retirement obligation		361,673

	$	5,956,934

Balance Sheet Classification
Inventory	$	8,988
Other current assets		2,410
Oil and gas properties:
Subject to amortization		4,270,987
Not subject to amortization		2,048,615
Deposit		(555,000	)
Other assets		118,212
Retained earnings		62,722

	$	5,956,934

The total purchase price includes $67.7 million of estimated acquisition costs of:

•

the $30.0 million commitment fee associated with the unused bridge facility, which we expensed upon obtaining alternate financing through the offering of the $3.0 billion of senior notes;

•

a $20 million amendment fee that we paid in connection with an amendment to our Stockholders Agreement with the preferred investors of Plains Offshore Operations Inc. to limit certain exclusivity provisions; and

•

certain investment advisory, legal and other acquisition related fees.

The pro forma financing adjustment includes $73.1 million of additional property costs related to seismic licenses acquired in conjunction with the GOM Acquisition. These costs were classified as current liabilities in PXP’s historical September 30, 2012 statements and for pro forma presentation purposes have been treated as paid with financing proceeds.

The pro forma balance sheet reflects the incremental borrowings as follows (in thousands):


	Cash			Other Assets		Long-Term Debt
	(in thousands)
Variable rate financing:
PXP Senior revolving credit facility	$	1,539,397		$	—	$	1,539,397
Related issuance costs		(69,632	)		69,632		—
Paydown existing revolving credit facility		(895,000	)		—		(895,000	)

$750 million 3.31% Term loan		750,000			—		750,000
Discount on issuance		(19,467	)		—		(19,467	)

$ 1.25 billion 4% Term loan		1,250,000			—		1,250,000
Discount on issuance		(29,669	)		—		(29,669	)

Fixed rate financing:
$3.0 billion 6.5% and 6.875% Notes		3,000,000			—		3,000,000
Related issuance costs		(48,580	)		48,580		—

	$	5,477,049		$	118,212	$	5,595,261

The pro forma adjustments also reflect (i) a write off of approximately $3.4 million of deferred financing charges reflected in other assets related to the amendment and restatement of our senior revolving credit facility, (ii) a $45.7 million decrease in current deferred income tax asset and non-current deferred income tax liability reflecting the impact of the acquisition on the twelve month utilization of tax attributes, (iii) a $32.9 million reduction in our deferred income tax liability (offset by a corresponding increase in stockholders’ equity) related to a reduction in the apportionment factor as a result of the GOM Acquisition and (iv) a $26.7 million reduction in non-current deferred income taxes reflecting the tax effect of the acquisition costs.

Unaudited Pro Forma Condensed Combined Statements of Income

Reflects recurring production costs, including (i) incremental insurance costs related to the GOM Acquisition, and (ii) fiber optic service fees paid to BP, as per the fiber optic service agreement between PXP and BP.

Adjustment to conform BP’s and Shell’s accounting for oil and gas properties to the full cost method of accounting for oil and gas properties utilized by PXP.

Adjusts depreciation, depletion and amortization expense (“DD&A”) for (1) the increase in DD&A reflecting the fair values and production volumes attributable to the oil and gas properties acquired in the GOM Acquisition and (2) the revision to PXP’s DD&A rate reflecting the reserve volumes acquired in the GOM Acquisition. The increase in accretion expense reflects the increase in the Company’s asset retirement obligation attributable to the respective properties acquired. The pro forma DD&A rate is $26.95 per BOE for the nine months ended September 30, 2012 and $21.11 per BOE for the year ended December 31, 2011.

Reflects the adjustment to interest expense associated with the financing related to the GOM Acquisition. The pro forma interest expense adjustment is comprised of incremental interest on net borrowings, which includes the senior unsecured notes, and the incremental $2.6 billion under the Amended Credit Agreement, of $224.6 million for the nine months ended September 30, 2012, and $330.9 million for the year ended December 31, 2011 (which includes the $30.0 million of expense for the commitment fee associated with the unused bridge facility and other miscellaneous financing fees), an increase to expense related to unused commitment fees of $5.2 million for the nine months ended September 30, 2012, and $7.0 million for the year ended December 31, 2011, and a decrease in interest expense due to increased capitalized interest of $87.2 million for the nine months ended September 30, 2012, and $101.2 million for the year ended December 31, 2011.

Borrowings under the Amended Credit Agreement bear interest at variable rates and are subject to interest rate risk. If interest rates increase, the debt service obligations on the loans would increase and cash available for servicing indebtedness would decrease. A 1/8% change in the interest rate would result in a change in interest expense related to variable rate financing of $2.5 million for the nine months ended September 30, 2012, and $3.3 million for the year ended December 31, 2011.

Reflects the adjustment to income tax expense resulting from the GOM Acquisition and Panhandle Divestment. Variances in PXP’s effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes.

Reflects the reversal of revenues and expenses attributable to the divested interests in the Company’s oil and gas properties related to the Panhandle Divestment.

Reflects the service fees paid to the operator during the transition period, as per the transaction services agreement between PXP and BP, included within the BP PSA.

Adjusts DD&A for (i) the reduction in DD&A reflecting the production volumes attributable to the Panhandle Divestment and (ii) the revision to PXP’s DD&A rate reflecting the reserve volumes sold and the reduction in capitalized costs resulting from the Panhandle Divestment. The proceeds from the Panhandle Divestment were reflected as a reduction to the PXP’s capitalized costs. The reduction in accretion expense reflects the reduction in the PXP’s asset retirement obligation attributable to the respective properties sold.

Reflects the adjustment to interest expense of $5.8 million and capitalized interest of $5.9 million, associated with the Panhandle Divestment and to reflect the use of proceeds from the sale to retire debt under the senior revolving credit facility.

Note 4 – Supplemental Oil and Gas Reserve Information

Pro forma reserve quantity information. The following table presents certain unaudited pro forma information regarding PXP’s proved reserves as of December 31, 2011, giving effect to the oil and gas properties acquired in the GOM Acquisition as if they were acquired on January 1, 2011. The reserve disclosures are based on reserve studies prepared as of December 31, 2011, in accordance with the guidelines established by the Securities and Exchange Commission. There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. The following reserve data represents estimates only and should not be construed as being precise.


	Year Ended December 31, 2011
	PXP			BP			Shell
	Historical			Historical			Historical			Pro Forma
	(MBOE)
Proved Reserves
Beginning balance		416,113			135,248			34,055			585,416
Revisions of previous estimates		1,466			1,212			(1,287	)		1,391
Extensions, discoveries and other additions		75,248			—			—			75,248
Improved recovery		—			2,307			—			2,307
Purchase of reserves in-place		4,291			5,220			—			9,511
Sale of reserves in-place		(49,735	)		—			—			(49,735	)
Production		(36,468	)		(20,552	)		(2,558	)		(59,578	)

Ending balance		410,915			123,435			30,210			564,560

Proved Developed Reserves, December 31		227,188			84,714			12,109			324,011

Proved Undeveloped Reserves, December 31		183,727			38,721			18,101			240,549

Pro forma Standardized Measure of Discounted Future Net Cash Flows. The following tables presents the Standardized Measure of Discounted Future Net Cash Flows relating to the proved crude oil and gas reserves of PXP and the oil and gas properties acquired in the GOM Acquisition and on a pro forma combined basis as of December 31, 2011. The Standardized Measure shown below represents estimates only and should not be construed as the current market value of our estimated oil and gas reserves or those attributable to the oil and gas properties acquired in the GOM Acquisition.


	Year Ended December 31, 2011
	PXP			BP			Shell			Pro Forma
	Historical			Historical			Historical			Adjustments			Pro Forma
	(in thousands)
Future cash inflows	$	29,502,864		$	11,061,189		$	2,802,805		$	—		$	43,366,858
Future development costs		(4,017,365	)		(1,292,090	)		(320,916	)		—			(5,630,371	)
Future production expense		(9,543,319	)		(1,574,797	)		(413,053	)		—			(11,531,169	)
Future income tax expense		(4,999,822	)		—			—			(2,308,588	)		(7,308,410	)

Future net cash flows		10,942,358			8,194,302			2,068,836			(2,308,588	)		18,896,908
Discounted at 10% per year		(5,808,177	)		(2,231,071	)		(716,464	)		(1,782,752	)		(10,538,464	)

Standardized measure of discounted future net cash flows	$	5,134,181		$	5,963,231		$	1,352,372		$	(4,091,340)		$	8,358,444

Pro forma income tax expense reflects expense on the combined future net cash flows based on PXP’s estimated effective tax rate, after giving effect to the pro forma transactions. Variances in PXP’s effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes.

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