UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2010


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-32747

MARINER ENERGY, INC.

(Exact name of registrant as specified in its charter)


Delaware		86-0460233
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification Number)

One BriarLake Plaza, Suite 2000
2000 West Sam Houston Parkway South
Houston, Texas 77042
(Address of principal executive offices and zip code)

(713) 954-5500
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
	(Do not check if a smaller reporting company)

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

As of July 31, 2010, there were 103,137,493 shares issued and outstanding of the issuer’s common stock, par value $0.0001 per share.

TABLE OF CONTENTS


PART I
Item 1. Unaudited Condensed Consolidated Financial Statements:
Condensed Consolidated Balance Sheets at June 30, 2010 and December 31, 2009			3
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009			4
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2010 and 2009			5
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009			6
Notes to the Condensed Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			32
Item 3. Quantitative and Qualitative Disclosures About Market Risk			46
Item 4. Controls and Procedures			48
PART II
Item 1A. Risk Factors			49
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			52
Item 6. Exhibits			53
Items 1, 3, 4 and 5 are not applicable and have been omitted.
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I

Item 1. Unaudited Condensed Consolidated Financial Statements

MARINER ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share data)


	June 30,			December 31,
	2010			2009
ASSETS
Current Assets:
Cash and cash equivalents	$	7,656		$	8,919
Receivables, net of allowances of $1,024 and $3,408 as of June 30, 2010 and December 31, 2009, respectively		135,486			148,725
Insurance receivables		7,681			8,452
Derivative financial instruments		25,792			2,239
Intangible assets		12,676			22,615
Prepaid expenses and other		27,126			11,667
Deferred income tax		—			9,704

Total current assets		216,417			212,321
Property and Equipment:
Proved oil and gas properties, full cost method		5,420,608			5,117,273
Unproved properties, not subject to amortization		439,604			292,237

Total oil and gas properties		5,860,212			5,409,510
Other property and equipment		56,202			55,695
Accumulated depreciation, depletion and amortization:
Proved oil and gas properties		(3,059,123	)		(2,884,411	)
Other property and equipment		(10,039	)		(8,235	)

Total accumulated depreciation, depletion and amortization		(3,069,162	)		(2,892,646	)

Total property and equipment, net		2,847,252			2,572,559
Derivative Financial Instruments		19,154			902
Deferred Income Tax		—			12,491
Other Assets, net of amortization		83,772			68,932

TOTAL ASSETS	$	3,166,595		$	2,867,205


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	8,805		$	3,579
Accrued liabilities		139,923			137,206
Accrued capital costs		139,404			140,941
Deferred income tax		6,447			—
Abandonment liability		86,799			54,915
Accrued interest		8,171			8,262
Derivative financial instruments		7,606			27,708

Total current liabilities		397,155			372,611
Long-Term Liabilities:
Abandonment liability		308,443			362,972
Deferred income tax		10,306			—
Derivative financial instruments		—			15,017
Long-term debt		1,458,564			1,194,850
Other long-term liabilities		35,475			38,800

Total long-term liabilities		1,812,788			1,611,639

Commitments and Contingencies (see Note 9)

Stockholders’ Equity:
Preferred stock, $.0001 par value; 20,000,000 shares authorized, no shares issued and outstanding at June 30, 2010 and December 31, 2009		—			—
Common stock, $.0001 par value; 180,000,000 shares authorized, 103,140,173 shares issued and outstanding at June 30, 2010; 180,000,000 shares authorized, 101,806,825 shares issued and outstanding at December 31, 2009		10			10
Additional paid-in capital		1,266,081			1,257,526
Accumulated other comprehensive income (loss)		22,220			(25,955	)
Accumulated deficit		(331,659	)		(348,626	)

Total stockholders’ equity		956,652			882,955

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,166,595		$	2,867,205

The accompanying notes are an integral part of these condensed consolidated financial statements

MARINER ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands except share data)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues:
Natural gas	$	92,414		$	142,363		$	209,926		$	295,701
Oil		96,496			78,954			192,135			139,879
Natural gas liquids		20,166			8,193			47,826			14,662
Other revenues		1,696			2,460			3,998			25,064

Total revenues		210,772			231,970			453,885			475,306


Costs and Expenses:
Lease operating expense		59,710			47,092			112,653			100,491
Severance and ad valorem taxes		6,101			3,730			13,020			7,262
Transportation expense		4,401			4,575			10,090			9,159
General and administrative expense		23,859			21,122			51,439			38,533
Depreciation, depletion and amortization		94,127			100,282			194,630			195,087
Full cost ceiling test impairment		—			—			—			704,731
Other miscellaneous expense		807			2,758			3,496			10,767

Total costs and expenses		189,005			179,559			385,328			1,066,030

OPERATING INCOME (LOSS)		21,767			52,411			68,557			(590,724	)

Other Income (Expense):
Interest income		634			302			769			387
Interest expense, net of amounts capitalized		(19,885	)		(16,972	)		(40,348	)		(31,374	)


Income (Loss) Before Taxes		2,516			35,741			28,978			(621,711	)
(Provision) Benefit for Income Taxes		(812	)		(18,528	)		(12,011	)		214,806

NET INCOME (LOSS)	$	1,704		$	17,213		$	16,967		$	(406,905	)


Net Income (Loss) per share:
Basic	$	0.02		$	0.19		$	0.17		$	(4.50	)
Diluted	$	0.02		$	0.19		$	0.17		$	(4.50	)
Weighted average shares outstanding:
Basic		101,371,705			91,798,761			101,182,367			90,339,810
Diluted		102,631,715			92,152,933			102,362,050			90,339,810

The accompanying notes are an integral part of these condensed consolidated financial statements

MARINER ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(Unaudited)
(In thousands)
For the six months ended June 30, 2010 and 2009


									Accumulated
									Other
						Additional			Comprehensive						Total
	Common			Stock		Paid-In-			Income/			Accumulated			Stockholders’
	Stock			Amount		Capital			(Loss)			Deficit			Equity
Balance at December 31, 2009		101,807		$	10	$	1,257,526		$	(25,955	)	$	(348,626	)	$	882,955

Common shares issued — restricted stock		1,616			—		—			—			—			—
Treasury stock bought and cancelled on same day		(292	)		—		(5,656	)		—			—			(5,656	)
Forfeiture of restricted stock		(12	)		—		—			—			—			—
Share-based compensation		—			—		13,971			—			—			13,971
Stock options exercised		21			—		240			—			—			240
Comprehensive income:
Net income		—			—		—			—			16,967			16,967
Change in fair value of derivative hedging instruments — net of income taxes of $31,823		—			—		—			57,013			—			57,013
Hedge settlements reclassified to income — net of income taxes of $(4,858)		—			—		—			(8,675	)		—			(8,675	)
Foreign currency translation adjustment		—			—		—			(163	)		—			(163	)

Total comprehensive income		—			—		—			48,175			16,967			65,142

Balance at June 30, 2010		103,140		$	10	$	1,266,081		$	22,220		$	(331,659	)	$	956,652


									Accumulated
									Other
						Additional			Comprehensive						Total
	Common			Stock		Paid-In-			Income/			Accumulated			Stockholders’
	Stock			Amount		Capital			(Loss)			Deficit			Equity
Balance at December 31, 2008		88,846		$	9	$	1,071,347		$	78,181		$	(29,217	)	$	1,120,320

Common shares issued — equity offering		11,500			1		159,673			—			—			159,674
Common shares issued — restricted stock		1,689			—		—			—			—			—
Treasury stock bought and cancelled on same day		(167	)		—		(1,891	)		—			—			(1,891	)
Forfeiture of restricted stock		(20	)		—		—			—			—			—
Share-based compensation		—			—		14,143			—			—			14,143
Stock options exercised		—			—		5			—			—			5
Comprehensive loss:
Net loss		—			—		—			—			(406,905	)		(406,905	)
Change in fair value of derivative hedging instruments — net of income taxes of $26,725		—			—		—			46,876			—			46,876
Hedge settlements reclassified to income — net of income taxes of $(48,138)		—			—		—			(86,063	)		—			(86,063	)

Total comprehensive loss		—			—		—			(39,187	)		(406,905	)		(446,092	)

Balance at June 30, 2009		101,848		$	10	$	1,243,277		$	38,994		$	(436,122	)	$	846,159

The accompanying notes are an integral part of these condensed consolidated financial statements

MARINER ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)


	Six Months
	Ended June 30,
	2010			2009
Operating Activities:
Net income (loss)	$	16,967		$	(406,905	)
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax		12,011			(214,806	)
Depreciation, depletion and amortization		194,630			195,087
Ineffectiveness of derivative instruments		(1,620	)		3
Full cost ceiling test impairment		—			704,731
Share-based compensation		11,840			12,208
Derivative financial instruments		—			(10,269	)
Other		2,312			483
Changes in operating assets and liabilities:
Receivables		13,378			66,302
Insurance receivables		771			4,347
Cash from liquidation of hedges		—			20,519
Prepaid expenses and other		(34,199	)		(9,053	)
Intangible assets		939			1,001
Accounts payable and accrued liabilities		(18,796	)		(25,917	)

Net cash provided by operating activities		198,233			337,731

Investing Activities:
Acquisitions and additions to oil and gas properties		(455,049	)		(318,625	)
Additions to other property and equipment		(507	)		(616	)

Net cash used in investing activities		(455,556	)		(319,241	)

Financing Activities:
Credit facility borrowings		456,000			261,221
Credit facility repayments		(193,000	)		(691,221	)
Repurchase of stock		(5,656	)		(1,891	)
Debt redetermination costs		(1,524	)		(2,300	)
Debt offering costs		—			(5,282	)
Proceeds from equity offering		—			160,138
Proceeds from debt issuance		—			291,279
Proceeds from exercise of stock options		240			5

Net cash provided by financing activities		256,060			11,949

(Decrease) Increase in Cash and Cash Equivalents		(1,263	)		30,439
Cash and Cash Equivalents at Beginning of Period		8,919			3,209

Cash and Cash Equivalents at End of Period	$	7,656		$	33,648


Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized)	$	35,737		$	28,765

The accompanying notes are an integral part of these condensed consolidated financial statements

MARINER ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. Summary of Significant Accounting Policies

Operations — Mariner Energy, Inc. (“Mariner” or “the Company”) is an independent oil and gas exploration, development and production company with principal operations in the Permian Basin, Gulf Coast and in the Gulf of Mexico, both shelf and deepwater. Unless otherwise indicated, references to “Mariner”, “the Company”, “we”, “our”, “ours” and “us” refer to Mariner Energy, Inc. and its subsidiaries collectively.

Interim Financial Statements — The accompanying unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures normally included in financial statements prepared in conformity with generally accepted accounting principles in the United States of America (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, all adjustments (consisting of a normal and recurring nature) considered necessary for a fair presentation have been included. Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements included herein should be read in conjunction with the Financial Statements and Notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

Use of Estimates — The preparation of the condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. The Company’s most significant financial estimates are based on remaining proved natural gas and oil reserves. Estimates of proved reserves are key components of Mariner’s depletion rate for natural gas and oil properties, its unevaluated properties and its full cost ceiling test. In addition, estimates are used in computing taxes, preparing accruals of operating costs and production revenues, asset retirement obligations, fair value and effectiveness of derivative instruments and fair value of stock options and the related compensation expense. Because of the inherent nature of the estimation process, actual results could differ materially from these estimates.

Principles of Consolidation — Mariner’s condensed consolidated financial statements as of and for the period ended June 30, 2010 and consolidated financial statements as of and for the period ended December 31, 2009 include its accounts and the accounts of its subsidiaries. All inter-company balances and transactions have been eliminated.

Income Taxes — The Company’s provision for taxes includes both federal and state taxes. The Company records its federal income taxes using an asset and liability approach which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount more likely than not to be recovered.

The Company had no uncertain tax positions during the six months ended June 30, 2010 or for the year ended December 31, 2009.

Recent Accounting Pronouncements — In July 2010, the Financial Accounting Standards Board (FASB) issued authoritative guidance which requires an entity to provide a greater level of disaggregated information about the credit quality of its financing receivables and its allowance for credit losses. In addition, an entity is required to disclose credit quality indicators, past due information, and modifications of its financing receivables. These disclosures are intended to help financial statement users assess an entity’s credit risk exposures and evaluate the adequacy of its allowance for credit losses. The guidance is effective for interim and annual reporting periods ending on or after December 15, 2010. The Company is currently evaluating the potential impact of adopting the guidance.

Mariner will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ended December 31, 2010.

In April 2010, the FASB issued authoritative guidance which provides clarification that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trade should not be considered to contain a condition that is not a market, performance or service condition. Therefore, the award would be classified as an equity award if it otherwise qualifies as equity. The guidance is effective for interim and annual reporting periods beginning on or after December 15, 2010. The Company is currently evaluating the potential impact of adopting the guidance.

In February 2010, the FASB issued authoritative guidance which requires additional information to be disclosed principally in respect of Level 3 fair value measurements and transfers to and from Level 1 and Level 2 measurements. In addition, enhanced disclosure is required concerning inputs and valuation techniques used to determine Level 2 and Level 3 fair value measurements. The guidance is generally effective for interim and annual reporting periods beginning after December 15, 2009; however, the requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). The Company adopted the standard effective January 1, 2010. The adoption did not have a material impact on the Company’s consolidated financial position, cash flows or results of operations.

2. Acquisitions and Dispositions

Onshore Acquisition — On December 31, 2009, Mariner acquired the reorganized subsidiaries and operations of Edge Petroleum Corporation (“Edge”). The assets acquired consist primarily of (i) estimated proved reserves, (ii) undeveloped oil and gas property, primarily in Texas and New Mexico, (iii) exploration assets in the form of seismic data, and (iv) certain tax attributes of the acquired subsidiaries. The effective date of the acquisition was June 30, 2009 and the purchase price was $260.0 million, less adjustments which resulted in a net purchase price as of December 31, 2009 of approximately $213.6 million, subject to final adjustments. Mariner financed the net purchase price by borrowing under its secured revolving credit facility.

Pro Forma Financial Information: The unaudited pro forma information set forth below gives effect to the acquisition of the reorganized Edge subsidiaries as if it had been consummated as of the beginning of the applicable period. The unaudited pro forma information has been derived from the historical Consolidated Financial Statements of the Company and of Edge. The unaudited pro forma information is for illustrative purposes only. The financial results may have been different had each of the acquired Edge subsidiaries been an independent company and had the companies always been combined. No reliance should be placed on the pro forma financial information as being indicative of the historical results that would have been achieved had the acquisition occurred in the past or the future financial results that the Company will achieve after the acquisition.


	For the Three Months		For the Six Months
	Ended June 30, 2009
	(In thousands, except per share amounts)
Pro Forma:
Revenue	$	244,123	$	511,944
Net income (loss) available to common stockholders	$	8,238	$	(491,113	)
Basic income (loss) per share	$	0.09	$	(5.44	)
Diluted income (loss) per share	$	0.09	$	(5.44	)

3. Long-Term Debt

As of June 30, 2010 and December 31, 2009, the Company’s long-term debt was as follows:


	June 30,		December 31,
	2010		2009
	(In thousands)
Bank credit facility	$	568,000	$	305,000
7 ¹/₂% Senior Notes, due April 15, 2013, net of discount		298,410		298,125
8% Senior Notes, due May 15, 2017		300,000		300,000
11 ³/₄% Senior Notes, due June 30, 2016, net of discount		292,154		291,725

Total long-term debt	$	1,458,564	$	1,194,850

Bank Credit Facility — The Company has a secured revolving credit facility with a group of banks pursuant to an amended and restated credit agreement dated March 2, 2006, as further amended. The credit facility matures January 31, 2012 and is subject to a borrowing base which is redetermined periodically. The outstanding principal balance of loans under the credit facility may not exceed the borrowing base. The most recent borrowing base redetermination concluded in April 2010 when the credit facility was amended to:

	•		Increase the borrowing base by $150.0 million to $950.0 million until the next redetermination under the credit agreement,

	•		Reschedule the regular periodic borrowing base redeterminations to begin in February and August of each year,

	•		Give the lenders an option to redetermine the borrowing base upon termination of hedge contracts with more than six months remaining in their original nominal term,

	•		Increase the maximum permitted ratio of total debt to EBITDA (as defined in the credit agreement) to 3.5 to 1.0 from 2.5 to 1.0, and

	•		Give Mariner optionality to issue before January 1, 2011 up to $400.0 million in additional unsecured debt with a non-default interest rate of up to 13% per annum (plus a maximum default rate of 3%) and a scheduled maturity date no earlier than March 2, 2015. Upon closing such a debt issuance, the borrowing base automatically would reduce by 25% of the aggregate principal amount of the debt issued until otherwise redetermined under the credit agreement.

As of June 30, 2010, maximum credit availability under the facility was $1.0 billion, including up to $50.0 million in letters of credit, subject to a borrowing base of $950.0 million. As of June 30, 2010, there were $568.0 million in advances outstanding under the credit facility and four letters of credit outstanding totaling $4.7 million, of which $4.2 million is required for plugging and abandonment obligations at certain of the Company’s offshore fields. As of June 30, 2010, after accounting for the $4.7 million of letters of credit, the Company had $377.3 million available to borrow under the credit facility.

Borrowings under the bank credit facility bear interest at either a LIBOR-based rate or a prime-based rate, at the Company’s option, plus a specified margin. At June 30, 2010, when borrowings at both LIBOR and prime-based rates were outstanding, the blended interest rate was 2.92% on all amounts borrowed. During the six months ended June 30, 2010, the commitment fee on unused capacity was 0.5% per annum. Commitment fees are included in “Accrued interest” in the Condensed Consolidated Balance Sheets in Item 1 of Part I of this Quarterly Report.

The credit facility subjects the Company to various restrictive covenants and contains other usual and customary terms and conditions, including limits on additional debt, cash dividends and other restricted payments, liens, investments, asset dispositions, mergers and speculative hedging. Financial covenants under the credit facility require the Company to, among other things:

•

maintain a ratio of consolidated current assets plus the unused borrowing base to consolidated current liabilities of not less than 1.0 to 1.0; and

•

maintain a ratio of total debt to EBITDA (as defined in the credit agreement) of not more than 3.5 to 1.0.

The Company was in compliance with these covenants as of June 30, 2010 when the ratio of consolidated current assets plus the unused borrowing base to consolidated current liabilities was 1.92 to 1.0 and the ratio of total debt to EBITDA was 2.6 to 1.0.

The Company’s payment and performance of its obligations under the credit facility (including any obligations under commodity and interest rate hedges entered into with facility lenders) are secured by liens upon substantially all of the assets of the Company and its subsidiaries, except its Canadian subsidiary, and guaranteed by its subsidiaries, other than Mariner Energy Resources, Inc. which is a co-borrower, and its Canadian subsidiary.

Senior Notes — In 2009, the Company sold and issued $300.0 million aggregate principal amount of its 11³/₄% senior notes due 2016 (the “11³/₄% Notes”). In 2007, the Company sold and issued $300.0 million aggregate principal amount of its 8% senior notes due 2017 (the “8% Notes”). In 2006, the Company sold and issued $300.0 million aggregate principal amount of its 7¹/₂% senior notes due 2013 (the “7¹/₂% Notes” and together with the 11³/₄% Notes and the 8% Notes, the “Notes”). The Notes are governed by indentures that are substantially identical for each series. The Notes are senior unsecured obligations of the Company. The 11³/₄% Notes mature on June 30, 2016 with interest payable on June 30 and December 30 of each year beginning December 30, 2009. The 8% Notes mature on May 15, 2017 with interest payable on May 15 and November 15 of each year. The 7¹/₂% Notes mature on April 15, 2013 with interest payable on April 15 and October 15 of each year. There is no sinking fund for the Notes. The Company and its restricted subsidiaries are subject to certain financial and non-financial covenants under each of the indentures governing the Notes. The Company was in compliance with the financial covenants under the Notes as of June 30, 2010.

Capitalized Interest — For the three-month periods ended June 30, 2010 and 2009, capitalized interest totaled $6.2 million and $3.0 million, respectively. For the six-month periods ended June 30, 2010 and 2009, capitalized interest totaled $11.5 million and $5.2 million, respectively.

4. Stockholders’ Equity

Common Stock Offering – On June 10, 2009, the Company sold and issued 11.5 million shares of its common stock, par value $.0001 per share, at a public offering price of $14.50 per share in an underwritten offering registered under the 1933 Act. The total sold included 1.5 million shares issued upon full exercise of the underwriters’ overallotment option. Net offering proceeds, after deducting underwriters’ discounts and estimated offering expenses but before giving effect to the underwriters’ reimbursement of up to $0.5 million for offering expenses, were approximately $159.2 million. The Company used net offering proceeds to repay debt under its bank credit facility.

5. Oil and Gas Properties

The Company’s oil and gas properties are accounted for using the full cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and gas properties are capitalized, including eligible general and administrative costs (“G&A”). G&A costs associated with production, operations, marketing and general corporate activities are expensed as incurred. These capitalized costs, coupled with the Company’s estimated asset retirement obligations recorded in accordance with accounting for asset retirement and environmental obligations under GAAP, are included in the amortization base and amortized to expense using the unit-of-production method. Amortization is calculated based on estimated proved oil and gas reserves. Proceeds from the sale or disposition of oil and gas properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between costs and the estimated value of proved reserves. For the three-month periods ended June 30, 2010 and 2009, capitalized G&A totaled $7.2 million and $5.3 million, respectively. For the six-month periods ended June 30, 2010 and 2009, capitalized G&A totaled $13.8 million and $10.3 million, respectively.

Capitalized costs (net of accumulated depreciation, depletion and amortization and deferred income taxes) of proved oil and gas properties are subject to a full cost ceiling limitation. The ceiling limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves less

estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with SEC rules, the natural gas and oil prices used to calculate the full cost ceiling limitation for periods ending on or after December 31, 2009 are the 12-month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Price is held constant over the life of the reserves. The Company uses derivative financial instruments that qualify for cash flow hedge accounting under GAAP to hedge against the volatility of oil and natural gas prices. In accordance with SEC guidelines, Mariner includes estimated future cash flows from its hedging program in the ceiling test calculation. If net capitalized costs related to proved properties exceed the ceiling limit, the excess is impaired and recorded in the Condensed Consolidated Statement of Operations.

At June 30, 2010 and June 30, 2009 the ceiling limit exceeded the net capitalized costs of the Company’s proved oil and gas properties and no impairment was recorded. The ceiling limit of its proved reserves at June 30, 2010 was calculated based upon 12-month average prices of $4.10 per Mcf for gas and $75.76 per barrel for oil, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. The ceiling limit of its proved reserves at June 30, 2009 was calculated based upon quoted market prices of $3.89 per Mcf for gas and $70.00 per barrel for oil. The Company may be required to recognize non-cash impairment charges in future reporting periods if average 12-month market prices for oil and natural gas were to decline. At June 30, 2010, the Company had 78,168,919 MMbtus of natural gas and 4,476,544 Bbls of oil of future production hedged.

6. Accrual for Future Abandonment Liabilities

In accordance with accounting for asset retirement and environmental obligations under GAAP, the Company records the fair value of a liability for the legal obligation to retire an asset in the period in which it is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. Upon adoption, the Company recorded an asset retirement obligation to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recognized in proved oil and gas properties.

To estimate the fair value of an asset retirement obligation, the Company employs a present value technique, which reflects certain assumptions, including its credit-adjusted risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.

The following roll forward is provided as a reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation:


	(In thousands)
Abandonment liability as of January 1, 2010 (1)	$	417,887
Liabilities incurred		1,092
Liabilities settled		(26,111	)
Accretion expense		18,113
Revisions to previous estimates		(15,739	)

Abandonment liability as of June 30, 2010 (2)	$	395,242


(1)		Includes $54.9 million classified as a current liability at January 1, 2010.

(2)		Includes $86.8 million classified as a current liability at June 30, 2010.

7. Share-Based Compensation

Applicable Plans — In May 2009, the Company’s stockholders approved the Mariner Energy, Inc. Third Amended and Restated Stock Incentive Plan (the “Stock Incentive Plan”) in which the Company’s directors, employees and consultants are eligible to participate. Awards of up to an aggregate 12,500,000 shares of the Company’s common stock may be made under the Stock Incentive Plan in the form of incentive stock options, non-

qualified stock options or restricted stock. Restricted common stock and non-qualified stock options are outstanding under the Stock Incentive Plan. Options to purchase the Company’s common stock granted to certain employees in connection with a March 2006 merger transaction also are outstanding but are not governed by the Stock Incentive Plan (“Rollover Options”).

Plan Activity — The Company recorded total compensation expense related to restricted stock and stock options of $7.1 million and $7.3 million for the three-month periods ended June 30, 2010 and 2009, respectively and $14.0 million and $14.1 million for the six-month periods ended June 30, 2010 and 2009, respectively. Unrecognized compensation expense at June 30, 2010 for the unvested portion of restricted stock granted under the Stock Incentive Plan was $53.4 million and for unvested options was $0.

Share-based compensation, including restricted stock and options under each of the Company’s plans, for the periods reflected was as follows:


	Three Months				Six Months
	Ended June 30,
	2010		2009		2010		2009
			(In thousands)
Share-based compensation included in:
General and administrative expense	$	5,949	$	6,284	$	11,840	$	12,208
Oil and natural gas properties under full cost method		1,131		1,081		2,131		1,935

Total share-based compensation	$	7,080	$	7,365	$	13,971	$	14,143

Share-based compensation charged to earnings for the periods reflected was as follows:


	Three Months						Six Months
	Ended June 30,
	2010			2009			2010			2009
				(In thousands)
Charged to earnings	$	5,949		$	6,284		$	11,840		$	12,208
Tax benefit		(2,308	)		(2,269	)		(4,594	)		(4,358	)

	$	3,641		$	4,015		$	7,246		$	7,850

The following table presents a summary of stock option activity under the Stock Incentive Plan and under Rollover Options for the six months ended June 30, 2010:


				Weighted
				Average		Aggregate Intrinsic
				Exercise		Value (1)
	Shares			Price		(In thousands)
Outstanding at January 1, 2010		644,160		$	13.88	$	4,896
Granted		—			—		—
Exercised		(20,860	)		11.52		(208	)
Forfeited		(1,600	)		14.00		(12	)

Outstanding and exercisable at June 30, 2010		621,700			13.96	$	4,676


(1)		Based upon the difference between the closing price per share of Mariner’s common stock on June 30, 2010 of $21.48 and the option exercise price of in-the-money options.

A summary of the activity for unvested restricted stock awards under the Stock Incentive Plan as of June 30, 2010 and 2009, respectively, and changes during the six-month periods then ended is as follows:


	Restricted Shares under
	Stock Incentive Plan
	June 30,
	2010			2009
Total unvested shares at beginning of period: January 1		3,660,265			2,697,926
Shares granted (1)		1,616,254			1,689,342
Shares vested		(931,612	)		(562,798	)
Shares forfeited (2)		(11,776	)		(20,426	)

Total unvested shares at end of period: June 30		4,333,131			3,804,044

Available for future grant as options or restricted stock		5,759,936			7,028,732


(1)		Includes 121,022 shares granted during the three months ended June 30, 2010 and 4,741 shares granted during the six months ended June 30, 2009 under the Stock Incentive Plan’s 2008 Long-Term Performance-Based Restricted Stock Program discussed below.

(2)		Includes 4,741 shares forfeited in each of the six months ended June 30, 2010 and 2009 under the Stock Incentive Plan’s 2008 Long-Term Performance-Based Restricted Stock Program.

The following table summarizes the status under the provisions for accounting for stock compensation under GAAP of the Company’s restricted stock, including long-term performance based restricted stock, at June 30, 2010 and the changes during the six months then ended:


									Weighted
						Aggregate			Average
	Equity			Weighted		Intrinsic			Remaining
	Instruments			Average		Value			Contractual
	(thousands)			Fair Value		($ thousands)			Life (Years)
Unvested at January 1, 2010		3,660,265		$	21.51	$	78,734
Granted		1,616,254			15.22		24,598
Vested		(931,612	)		17.60		(16,401	)
Forfeited		(11,776	)		15.34		(181	)

Unvested at June 30, 2010		4,333,131			20.02	$	86,750			6.09

Long-Term Performance-Based Restricted Stock Program — In June 2008, Mariner’s board of directors adopted a Long-Term Performance-Based Restricted Stock Program (the “Program”) under the Stock Incentive Plan. Shares of restricted common stock subject to the Program were granted in 2008, 2009 and 2010. Vesting of these shares is contingent, begins upon satisfaction of specified thresholds of $38.00 and $46.00 for the market price per share of Mariner’s common stock, and continues in installments over five to seven years thereafter, assuming, in most instances, continued employment by Mariner. The fair value of restricted stock grants made under the Program is estimated using a Monte Carlo simulation. For the three months and six months ended June 30, 2010, stock-based compensation expense related to these restricted stock grants totaled $2.1 million and $4.4 million, respectively.

Weighted average fair values and valuation assumptions used to value Program grants for the quarter ended June 30, 2010 are as follows:


	Quarter Ended
	June 30, 2010
Weighted average fair value of grants	$	16.02
Expected volatility		60.24	%
Risk-free interest rate		4.20	%
Dividend yield		0.00	%
Expected life	10 years

Expected volatility is calculated based on the average historical stock price volatility of Mariner and a peer group as of June 30, 2010. The peer group consisted of the following seven independent oil and gas exploration and production companies: ATP Oil & Gas Corporation, Callon Petroleum Co., Energy Partners, Ltd., McMoRan Exploration Co., Plains Exploration & Production Company, Stone Energy Corporation and W&T Offshore, Inc.

The risk-free interest rate is determined at the grant date and is based on 10-year, zero-coupon government bonds with maturity equal to the contractual term of the awards, converted to a continuously compounded rate. The expected life is based upon the contractual terms of the restricted stock grants under the Program.

8. Derivative Financial Instruments and Hedging Activities

The energy markets historically have been very volatile, and Mariner expects oil and gas prices will be subject to wide fluctuations in the future. In an effort to reduce the effects of the volatility of the price of oil and natural gas on the Company’s operations, management has elected to hedge oil and natural gas prices from time to time through the use of commodity price swap agreements and costless collars. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. In addition, forward price curves and estimates of future volatility are used to assess and measure the ineffectiveness of the Company’s open contracts at the end of each period.

For derivative contracts that are designated and qualify as cash flow hedges pursuant to accounting for derivatives and hedging under GAAP, the portion of the gain or loss on the derivative instrument that is effective in offsetting the variable cash flows associated with the hedged forecasted transaction is reported as a component of other comprehensive income and reclassified into earnings in the same line item associated with the forecasted transaction in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are commodity sales). The remaining gain or loss on the derivative contract in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion) is recognized in earnings during the current period. The Company currently does not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness.

On January 29, 2009, the Company liquidated crude oil fixed price swaps that previously had been designated as cash flow hedges for accounting purposes in respect of 977,000 barrels of crude oil in exchange for a cash payment to Mariner of $10.0 million and installment payments of $13.5 million to be paid monthly to Mariner through 2009. On April 16, 2009, the Company received a $10.5 million cash settlement on the hedges that were settled in monthly installments at January 29, 2009. Since, at the time of liquidation, the forecasted sales of crude oil volumes were still expected to occur, the accumulated losses through January 29, 2009 on the related derivative contracts remained in accumulated other comprehensive income. These accumulated losses were reclassified to oil revenues throughout 2009 as the physical transactions occurred. Additionally, all changes in the value of these derivative contracts subsequent to January 29, 2009 were also reclassified monthly from accumulated other comprehensive income to current period oil revenues. The table below reflects these reclassifications for the three months and six months ended June 30, 2009.

Derivative gains and losses are recorded by commodity type in oil and gas revenues in the Condensed Consolidated Statements of Operations. The effects on the Company’s oil and gas revenues from its hedging activities were as follows:


	Three Months Ended June 30,					Six Months Ended June 30,
	2010			2009		2010		2009
	(In thousands)
Cash Gain on Settlements (1)	$	13,798		$	63,547	$	11,913	$	121,004
Reclassification of Liquidated Swaps (2)		—			6,677		—		13,200
(Loss) Gain on Hedge Ineffectiveness (3)		(838	)		176		1,620		(3	)

Total	$	12,960		$	70,400	$	13,533	$	134,201


(1)		Designated as cash flow hedges pursuant to accounting for derivatives and hedging under GAAP.

(2)		Net gain realized in 2009 on liquidated crude oil fixed price swaps that do not qualify for hedge accounting.

(3)		Unrealized (loss) gain recognized in natural gas revenue related to the ineffective portion of open contracts designated as cash flow hedges that are not eligible for deferral under GAAP due primarily to the basis differentials between the contract price and the indexed price at the point of sale.

As of June 30, 2010, the Company had the following hedge contracts outstanding:


			Weighted Average		Fair Value
Fixed Price Swaps	Quantity		Fixed Price		Asset/(Liability)
					(In thousands)
Natural Gas (MMbtus)
July 1 — December 31, 2010		20,600,274	$	5.56	$	15,297
January 1 — December 31, 2011		29,389,843	$	5.79		13,430
January 1 — December 31, 2012		22,338,802	$	6.11		9,267
January 1 — December 31, 2013		5,840,000	$	6.76		4,795
Crude Oil (Bbls)
July 1 — December 31, 2010		1,595,280	$	73.64		(5,179	)
January 1 — December 31, 2011		1,978,364	$	79.33		(275	)
January 1 — December 31, 2012		494,100	$	80.76		(199	)
January 1 — December 31, 2013		408,800	$	82.81		204

Total					$	37,340

The Company has reviewed the financial strength of its counterparties and believes the credit risk associated with these swaps to be minimal. Hedges with counterparties that are lenders under the Company’s bank credit facility are secured under the bank credit facility.

For derivative instruments that are not designated as a hedge for accounting purposes, all realized and unrealized gains and losses are recognized in the consolidated statement of operations during the current period. This will result in non-cash gains or losses being reported in Mariner’s operating results.

As of June 30, 2010, the Company expects to realize within the next 12 months a net gain of approximately $18.2 million resulting from hedging activities that are currently recorded in accumulated other comprehensive income. The net hedging gain is expected to be realized as a decrease of $8.0 million to oil revenues and an increase of $26.2 million to natural gas revenues.

Additional Disclosures about Derivative Instruments and Hedging Activities

At June 30, 2010 and December 31, 2009, the Company had derivative financial instruments under GAAP recorded in its consolidated balance sheets as set forth below (in thousands). The fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. See Note 12, “Fair Value Measurement” for information regarding the methods and assumptions used to estimate the fair values of the Company’s derivative financial instruments.

Fair Value of Derivative Contracts

Asset Derivatives

June 30, 2010

December 31, 2009

Balance sheet

Location

Fair value

Location

Fair value

Derivatives designated as cash flow hedging contracts

Fixed Price Swaps

Current Assets: Derivative financial instruments

25,792

Current Assets: Derivative financial instruments

2,239

Long-Term Assets: Derivative Financial Instruments

19,154

Long-Term Assets: Derivative Financial Instruments

902

Total:

44,946

Total:

3,141

Fair Value of Derivative Contracts

Liability Derivatives

June 30, 2010

December 31, 2009

Balance sheet

Location

Fair value

Location

Fair value

Derivatives designated as cash flow hedging contracts

Fixed Price Swaps

Current Liabilities: Derivative financial instruments

7,606

Current Liabilities: Derivative financial instruments

27,708

Long-Term Liabilities: Derivative financial instruments

—

Long-Term Liabilities: Derivative financial instruments

15,017

Total:

7,606

Total:

42,725

For the three months ended June 30, 2010 and 2009, the effect on income (loss) of derivative financial instruments under GAAP was as follows (in thousands):

Amount of

Location of

Amount of gain/(loss)

gain/(loss)

reclassified from

Amount of gain/(loss)

Derivatives

recognized in OCI

reclassified from

Accumulated OCI into

recognized in income

designated as cash

on derivative

Accumulated OCI

income (effective

Location of gain/(loss)

on derivative

flow hedging

(effective portion)

into income

portion)

recognized in income

(ineffective portion)

contracts under

Second Quarter

(effective

Second Quarter

on derivative

Second Quarter

GAAP

2010

2009

portion)

2010

2009

(ineffective portion)

2010

2009

Fixed Price Swaps

28,799

(23,589

)

Revenues-Natural Gas

16,848

58,668

Revenues-Natural Gas

(838

)

176

Revenues-Crude Oil

(3,050

)

4,879

Total

13,798

63,547


		Amount of gain recognized
	Location of gain	in income on derivative
Derivatives not designated as cash flow hedging contracts	recognized in income on	Second Quarter	Second Quarter
under GAAP	derivative	2010	2009
Fixed Price Swaps	Revenues-Crude Oil	$ —	$	6,677

For the six months ended June 30, 2010 and 2009, the effect on income (loss) of derivative financial instruments under GAAP was as follows (in thousands):

Amount of

Location of

Amount of gain/(loss)

gain/(loss)

reclassified from

Amount of gain/(loss)

Derivatives

recognized in OCI

reclassified from

Accumulated OCI into

recognized in income

designated as cash

on derivative

Accumulated OCI

income (effective

Location of gain/(loss)

on derivative

flow hedging

(effective portion)

into income

portion)

recognized in income

(ineffective portion)

contracts under

Six Months Ended June 30,

(effective

Six Months Ended June 30,

on derivative

Six Months Ended June 30,

GAAP

2010

2009

portion)

2010

2009

(ineffective portion)

2010

2009

Fixed Price Swaps

88,837

63,351

Revenues-Natural Gas

20,357

101,813

Revenues-Natural Gas

1,620

)

Revenues-Crude Oil

(8,444

)

19,191

Total

11,913

121,004


		Amount of gain recognized
	Location of gain	in income on derivative
Derivatives not designated as cash flow hedging contracts	recognized in income on	Six Months Ended June 30,	Six Months Ended June 30,
under GAAP	derivative	2010	2009
Fixed Price Swaps	Revenues-Crude Oil	$ —	$	13,200

See Note 11, “Comprehensive Income (Loss)” for more information related to the Company’s derivative financial instruments.

9. Commitments and Contingencies

Minimum Future Lease Payments — The Company leases certain office facilities and other equipment under long-term operating lease arrangements. Minimum future lease obligations under the Company’s operating leases in effect at June 30, 2010 are as follows:


	(In thousands)
2011	$	1,898
2012		3,695
2013		3,435
2014		3,308
2015 and thereafter		13,065

Other Commitments — In the ordinary course of business, the Company enters into long-term commitments to purchase seismic data and other geological information such as maps, logs and studies. The minimum annual payments under these contracts are $4.8 million in 2011.

Insurance Matters

Current Insurance Against Hurricanes

Mariner is a member of OIL Insurance Limited (“OIL”), an energy industry insurance cooperative, which provides Mariner windstorm insurance coverage. During 2009, the coverage was subject to a $10.0 million per-occurrence deductible, a $250.0 million per-occurrence loss limit, and a $750.0 million industry aggregate per-event loss limit. Effective January 1, 2010, the coverage is subject to a $10.0 million per-occurrence deductible; a $150.0 million per-occurrence loss limit per member that Mariner elected to supplement with $25.0 million in additional coverage which if used, would be repayable, interest free, over five years; an annual maximum of $300.0 million per member; and a $750.0 million industry aggregate per-event loss limit. Annual industry windstorm losses of $300.0 million or less will be mutualized among all members. Annual industry windstorm losses exceeding $300.0 million will be mutualized among windstorm members in two pools, one for offshore and one for onshore, with future premiums based upon a pool’s loss experience and a member’s weighted percent of the pool’s asset base. Mariner anticipates these changes to increase its loss retention by approximately $100.0 million for windstorm losses, which it expects to either self insure, insure through the commercial market, insure through the purchase of additional OIL coverage or a combination of these.

Mariner annually considers whether the commercial market offers supplemental or excess insurance that would, based on Mariner’s historical experience, supplement its OIL coverage on a cost-effective basis. In 2010, Mariner elected to purchase insurance from the commercial market to supplement the reduced windstorm coverage offered by OIL. The supplemental insurance will provide up to an additional $78.3 million of aggregate annual coverage in respect of windstorms, of which up to $49.1 million could cover revenues lost as a result of constructive total losses of third-party owned structures through which a material amount of Mariner production is routed and cannot be rerouted.

As of June 30, 2010, Mariner accrued approximately $41.2 million for an OIL withdrawal premium contingency. As part of its OIL membership, Mariner is obligated to pay a withdrawal premium if it elects to withdraw from OIL. Mariner does not anticipate withdrawing from OIL; however, due to the contingency, Mariner periodically reassesses the sufficiency of its accrued withdrawal premium based on OIL’s periodic calculation of the potential withdrawal premium in light of past losses, and Mariner may adjust its accrual accordingly in the future. OIL requires smaller members to provide a letter of credit or other acceptable security in favor of OIL to secure payment of the withdrawal premium. Acceptable security has included a letter of credit or a security agreement pursuant to which a member grants OIL a security interest in certain claim proceeds payable by OIL to the member. Mariner has entered into such a security agreement, granting to OIL a senior security interest in up to the next $50.0 million in excess of $100.0 million of Mariner’s Hurricane Ike claim proceeds payable by OIL. Mariner has the ability to replace the security agreement with a letter of credit or other acceptable security in favor of OIL.

Hurricane Ike (2008)

In 2008, the Company’s operations were adversely affected by Hurricane Ike. The hurricane resulted in shut-in and delayed production as well as facility repairs and replacement expenses. The Company estimates that repairs and plugging and abandonment costs resulting from Hurricane Ike will total approximately $160.0 million net to Mariner’s interest. OIL has advised the Company that industry-wide damages from Hurricane Ike are expected to substantially exceed OIL’s $750.0 million industry aggregate per event loss limit and that OIL expects to initially prorate the payout of all OIL members’ Hurricane Ike claims at approximately 50%, subject to further adjustment. OIL also has indicated that the scaling factor it expects to apply to Mariner’s Hurricane Ike claims will result in settlement at less than 70%. Mariner expects that approximately 75% of the shortfall in its primary insurance coverage will be covered under applicable commercial excess coverage. In respect of Hurricane Ike claims that the Company made through June 30, 2010, the Company received approximately $37.0 million from OIL and $14.0 million from excess carriers. Although in 2009 Mariner started receiving payment in respect of its Hurricane Ike claims, due to the magnitude of the storm and the complexity of the insurance claims being processed by the insurance industry, Mariner expects to maintain a potentially significant insurance receivable through 2010 while it actively pursues settlement.

Litigation — The Company, in the ordinary course of business, is a claimant and/or a defendant in various legal proceedings, including proceedings as to which the Company has insurance coverage and those that may involve the filing of liens against the Company or its assets. The Company does not consider its exposure in these proceedings, individually or in the aggregate, to be material.

Letters of Credit — Mariner’s bank credit facility has a letter of credit subfacility of up to $50.0 million that is included as a use of the borrowing base. As of June 30, 2010, four such letters of credit totaling $4.7 million were outstanding of which $4.2 million is required for plugging and abandonment obligations at certain of Mariner’s offshore fields.

Gulf of Mexico Oil Spill — As a result of the Deepwater Horizon incidents in April 2010, the U.S. Department of Interior (DOI) has issued a series of reforms to the oversight and management of offshore drilling activities on the federal Outer Continental Shelf (OCS). On July 12, 2010, the Secretary of the DOI directed the Bureau of Ocean Energy Management, Regulation and Enforcement, to issue a suspension until November 30, 2010 of drilling activities that use subsea blowout preventers or surface blowout preventers on floating facilities. Mariner’s Gulf of Mexico offshore operations have been impacted and likely may be impacted in the future by increased regulatory oversight, which may increase the cost of OCS wells, such as Lucius, Heidelberg and Bass Lite, and delay drilling and production therefrom.

10. Earnings per Share

Basic earnings per share does not include dilution and is computed by dividing net income or loss attributed to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution that could occur upon vesting of restricted common stock or exercise of options to purchase common stock.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
	(In thousands, except per share data)
Numerator:
Net Income (Loss)	$	1,704	$	17,213	$	16,967	$	(406,905	)
Denominator:
Weighted average shares outstanding		101,372		91,799		101,182		90,340
Add dilutive securities
Options		215		11		180		—
Restricted stock		1,045		343		1,000		—

Total weighted average shares outstanding and dilutive securities		102,632		92,153		102,362		90,340

Net Income (Loss) per share:
Basic:	$	0.02	$	0.19	$	0.17	$	(4.50	)
Diluted:	$	0.02	$	0.19	$	0.17	$	(4.50	)

Shares issuable upon exercise of options to purchase common stock and unvested shares of restricted stock that would have been anti-dilutive are excluded from the computation of diluted earnings per share. For the six months ended June 30, 2010, none of the Company’s shares issuable upon exercise of stock options and approximately 1,082,000 unvested shares of restricted stock were excluded from the computation of diluted earnings per share because the effect was anti-dilutive. For the three months ended June 30, 2010, none of the Company’s shares issuable upon exercise of stock options and approximately 1,355,000 unvested shares of restricted stock were excluded from the computation of diluted earnings per share because the effect was anti-dilutive. As a result of the Company’s net loss for the six months ended June 30, 2009, all of the Company’s shares issuable upon exercise of stock options and unvested shares of restricted stock (approximately 623,461 and 2,306,203, respectively) were excluded from the computation of diluted earnings per share because the effect was anti-dilutive. For the three months ended June 30, 2009, 612,805 shares issuable upon exercise of stock options and 1,605,688 unvested shares of restricted stock were excluded from the computation of diluted earnings per share because the effect was anti-dilutive.

The provisions of Accounting Standards Codification Topic 260, “Earnings Per Share,” state that unvested share-based payment awards that contain rights to receive nonforfeitable dividends or dividend equivalents are participating securities prior to vesting and are required to be included in the earnings allocations in computing basic earnings per share under the two-class method. These participating securities had a negligible impact on earnings per share.

11. Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and certain items recorded directly to stockholders’ equity and classified as other comprehensive income (loss). The table below summarizes comprehensive income (loss) and provides the components of the change in accumulated other comprehensive income (loss) for the three months and six months ended June 30, 2010 and 2009:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
				(In thousands)
Net Income (Loss)	$	1,704		$	17,213		$	16,967		$	(406,905	)
Other comprehensive income (loss), net of tax:
Change in fair value of derivative hedging instruments, net of taxes		18,470			(15,460	)		57,013			46,876
Derivative contracts settled and reclassified, net of taxes		(8,308	)		(45,147	)		(8,675	)		(86,063	)
Foreign currency translation adjustment		(295	)		—			(163	)		—

Change in accumulated other comprehensive income (loss)		9,867			(60,607	)		48,175			(39,187	)

Comprehensive income (loss)	$	11,571		$	(43,394	)	$	65,142		$	(446,092	)

12. Fair Value Measurement

Certain of Mariner’s assets and liabilities are reported at fair value in the accompanying Condensed Consolidated Balance Sheets. Such assets and liabilities include amounts for both financial and nonfinancial instruments. The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including income taxes payable and accrued expenses) approximated fair value at June 30, 2010 and December 31, 2009. These assets and liabilities are not included in the following tables.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the table below, the hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are market-based and are directly or indirectly observable but not considered Level 1 quoted prices, including quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; or valuation techniques whose inputs are observable. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Level 3 inputs are unobservable (meaning they reflect Mariner’s own assumptions regarding how market participants would price the asset or liability based on the best available information) and therefore have the lowest priority. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Mariner believes it uses appropriate valuation techniques based on the available inputs to measure the fair values of its assets and liabilities.

GAAP requires a credit adjustment for non-performance in calculating the fair value of financial instruments. The credit adjustment for derivatives in an asset position is determined based on the credit rating of the counterparty and the credit adjustment for derivatives in a liability position is determined based on Mariner’s credit rating.

The following table provides fair value measurement information for the Company’s derivative financial instruments.


	Fair Value Measurements Using:
			Significant
	Quoted Prices		other			Significant
	in Active		Observable			Unobservable
	Markets		Inputs			Inputs		Total Fair						Carrying
	(Level 1)		(Level 2)			(Level 3)		Value(1)			Netting			Amount
	(In thousands)
As of June 30, 2010
Natural gas and crude oil fixed price swaps — Short Term	$	—	$	33,503		$	—	$	33,503		$	(15,317	)	$	18,186

Natural gas and crude oil fixed price swaps — Long Term		—		19,897			—		19,897			(743	)		19,154

Total Derivative Financial Instruments	$	—	$	53,400		$	—	$	53,400		$	(16,060	)	$	37,340


As of December 31, 2009
Natural gas and crude oil fixed price swaps — Short Term	$	—	$	(27,708	)	$	—	$	(27,708	)	$	2,239		$	(25,469	)

Natural gas and crude oil fixed price swaps — Long Term		—		(16,562	)		—		(16,562	)		2,447			(14,115	)

Total Derivative Financial Instruments	$	—	$	(44,270	)	$	—	$	(44,270	)	$	4,686		$	(39,584	)


(1)		Derivative fair values are based on analysis of each contract as required by accounting for fair value measurements and disclosures under GAAP. Derivative assets and liabilities with the same counterparty are presented here on a gross basis even where the legal right of offset exists.

The following methods and assumptions were used to estimate the fair values of Mariner’s derivative financial instruments in the table above.

Level 2 Fair Value Measurements

The fair values of the natural gas and crude oil fixed price swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves, terms of each contract, and a credit adjustment based on the credit rating of the Company and its counterparties as of June 30, 2010.

Level 3 Fair Value Measurements

The Company had no Level 3 financial instruments as of June 30, 2010.

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of accounting for financial instruments under GAAP, which Mariner adopted effective March 31, 2009. The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying amounts and fair values of the Company’s long-term debt are as follows:


	June 30, 2010
	Carrying
Long-term Debt	Amount		Fair Value
	(In thousands)
Bank credit facility	$	568,000	$	568,000
7 ¹/₂% Notes, net of discount		298,410		309,375
8% Notes		300,000		327,750
11 ³/₄% Notes, net of discount		292,154		375,000

Total long-term debt	$	1,458,564	$	1,580,125

The fair value of the amounts outstanding under the bank credit facility at June 30, 2010 is based on rates currently available for debt instruments with similar terms and average maturities from companies with similar credit ratings in the industry. The fair value of the Notes, excluding discount, is based on quoted market prices based on trades of such debt at June 30, 2010 or the nearest actual trade date.

13. Segment Information

The FASB issued authoritative guidance establishing standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses. Separate financial information is available and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance.

Mariner measures financial performance as a single enterprise, allocating capital resources on a project-by-project basis across its entire asset base to maximize profitability. Mariner utilizes a company-wide management team that administers all enterprise operations encompassing the exploration, development and production of natural gas and oil. Since Mariner follows the full cost method of accounting and all of its oil and gas properties and operations are located in the United States, the Company has determined that it has one reporting unit. Inasmuch as Mariner is one enterprise, the Company does not maintain comprehensive financial statement information by area but does track basic operational data by area.

14. Supplemental Guarantor Information

On June 10, 2009, the Company sold and issued $300.0 million aggregate principal amount of its 11 ³/₄% Notes. On April 30, 2007, the Company sold and issued $300.0 million aggregate principal amount of its 8% Notes. On April 24, 2006, the Company sold and issued to eligible purchasers $300.0 million aggregate principal amount of its 7 ¹/₂% Notes. The Notes are jointly and severally guaranteed on a senior unsecured basis by the Company’s existing and certain of its future domestic subsidiaries (“Subsidiary Guarantors”). The guarantees are full and unconditional, and the guarantors are wholly-owned. In the future, the guarantees may be released or terminated under certain circumstances.

The following information sets forth Mariner’s Condensed Consolidating Balance Sheets as of June 30, 2010 and December 31, 2009, its Condensed Consolidating Statements of Operations for the three months and six months ended June 30, 2010 and 2009, and its Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2010 and 2009.

Mariner accounts for investments in its subsidiaries using the equity method of accounting; accordingly, entries necessary to consolidate Mariner, the parent company, and its Subsidiary Guarantors are reflected in the eliminations column.

MARINER ENERGY, INC.
CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)
June 30, 2010
(In thousands except share data)


							Subsidiary						Consolidated
	Parent			Subsidiary			Non-						Mariner
	Company			Guarantors			Guarantors			Eliminations			Energy, Inc.
Current Assets:
Cash and cash equivalents	$	4,210		$	3,269		$	177		$	—		$	7,656
Receivables, net of allowances		73,029			62,457			—			—			135,486
Insurance receivables		53			7,628			—			—			7,681
Derivative financial instruments		25,792			—			—			—			25,792
Intangible assets		12,676			—			—			—			12,676
Prepaid expenses and other		25,302			1,824			—			—			27,126

Total current assets		141,062			75,178			177			—			216,417
Property and Equipment:
Proved oil and gas properties, full cost method		2,715,979			2,704,146			483			—			5,420,608
Unproved properties, not subject to amortization		390,009			45,981			3,614			—			439,604

Total oil and gas properties		3,105,988			2,750,127			4,097			—			5,860,212
Other property and equipment		20,421			35,358			423			—			56,202
Accumulated depreciation, depletion and amortization:
Proved oil and gas properties		(1,598,554	)		(1,460,569	)		—			—			(3,059,123	)
Other property and equipment		(7,372	)		(2,609	)		(58	)		—			(10,039	)

Accumulated depreciation, depletion and amortization		(1,605,926	)		(1,463,178	)		(58	)		—			(3,069,162	)

Total property and equipment, net		1,520,483			1,322,307			4,462			—			2,847,252
Investment in Subsidiaries		727,287			—			—			(727,287	)		—
Intercompany Receivables		213,688			—			—			(213,688	)		—
Intercompany Note Receivable		7,175			—			—			(7,175	)		—
Derivative Financial Instruments		19,154			—			—			—			19,154
Deferred income tax		20,063			—			—			(20,063	)		—
Other Assets, net of amortization		83,060			712			—			—			83,772

TOTAL ASSETS	$	2,731,972		$	1,398,197		$	4,639		$	(968,213	)	$	3,166,595

Current Liabilities:
Accounts payable	$	4,630		$	4,170		$	5		$	—		$	8,805
Accrued liabilities		106,888			33,035			—			—			139,923
Accrued capital costs		71,696			67,708			—			—			139,404
Deferred income tax		6,447			—			—			—			6,447
Abandonment liability		13,695			73,104			—			—			86,799
Accrued interest		8,171			—			—			—			8,171
Derivative financial instruments		7,606			—			—			—			7,606

Total current liabilities		219,133			178,017			5			—			397,155
Long-Term Liabilities:
Abandonment liability		62,320			246,123			—			—			308,443
Deferred income tax		—			30,369			—			(20,063	)		10,306
Intercompany payables		—			213,688			—			(213,688	)		—
Long-term debt		1,458,564			—			—			—			1,458,564
Other long-term liabilities		35,133			342			—			—			35,475
Intercompany note payable		—			7,175			—			(7,175	)		—

Total long-term liabilities		1,556,017			497,697			—			(240,926	)		1,812,788
Commitments and Contingencies
Stockholders’ Equity:
Preferred stock, $.0001 par value; 20,000,000 shares authorized, no shares issued and outstanding at June 30, 2010		—			—			—			—			—
Common stock, $.0001 par value; 180,000,000 shares authorized, 103,140,173 shares issued and outstanding at June 30, 2010		10			5			—			(5	)		10
Additional paid-in-capital		1,266,081			1,078,386			5,550			(1,083,936	)		1,266,081
Partner capital		—			38,181			—			(38,181	)		—
Accumulated other comprehensive income (loss)		22,390			—			(170	)		—			22,220
Accumulated retained deficit		(331,659	)		(394,089	)		(746	)		394,835			(331,659	)

Total stockholders’ equity		956,822			722,483			4,634			(727,287	)		956,652

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,731,972		$	1,398,197		$	4,639		$	(968,213	)	$	3,166,595

MARINER ENERGY, INC.
CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)
December 31, 2009
(In thousands except share data)


							Subsidiary						Consolidated
	Parent			Subsidiary			Non-						Mariner
	Company			Guarantors			Guarantors			Eliminations			Energy, Inc.
Current Assets:
Cash and cash equivalents	$	8,365		$	3		$	551		$	—		$	8,919
Receivables, net of allowances		94,958			53,767			—			—			148,725
Insurance receivables		74			8,378			—			—			8,452
Derivative financial instruments		2,239			—			—			—			2,239
Intangible assets		22,615			—			—			—			22,615
Prepaid expenses and other		10,450			1,217			—			—			11,667
Deferred income tax		9,704			—			—			—			9,704

Total current assets		148,405			63,365			551			—			212,321
Property and Equipment:
Proved oil and gas properties, full cost method		2,472,963			2,644,310			—			—			5,117,273
Unproved properties, not subject to amortization		246,037			46,134			66			—			292,237

Total oil and gas properties		2,719,000			2,690,444			66			—			5,409,510
Other property and equipment		19,926			35,358			411			—			55,695
Accumulated depreciation, depletion and amortization:
Proved oil and gas properties		(1,499,787	)		(1,384,624	)		—			—			(2,884,411	)
Other property and equipment		(6,145	)		(2,090	)		—			—			(8,235	)

Accumulated depreciation, depletion and amortization		(1,505,932	)		(1,386,714	)		—			—			(2,892,646	)

Total property and equipment, net		1,232,994			1,339,088			477			—			2,572,559
Investment in Subsidiaries		715,772			—			—			(715,772	)		—
Intercompany Receivables		222,273			—			—			(222,273	)		—
Intercompany Note Receivable		7,175			—			—			(7,175	)		—
Derivative Financial Instruments		902			—			—			—			902
Deferred Income Tax		35,583			(23,092	)		—			—			12,491
Other Assets, net of amortization		68,631			301			—			—			68,932

TOTAL ASSETS	$	2,431,735		$	1,379,662		$	1,028		$	(945,220	)	$	2,867,205

Current Liabilities:
Accounts payable	$	3,569		$	—		$	10		$	—		$	3,579
Accrued liabilities		107,537			29,669			—			—			137,206
Accrued capital costs		71,420			69,521			—			—			140,941
Abandonment liability		10,632			44,283			—			—			54,915
Accrued interest		8,262			—			—			—			8,262
Derivative financial instruments		27,708			—			—			—			27,708

Total current liabilities		229,128			143,473			10			—			372,611
Long-Term Liabilities:
Abandonment liability		71,320			291,652			—			—			362,972
Intercompany payables		—			222,273			—			(222,273	)		—
Derivative financial instruments		15,017			—			—			—			15,017
Long-term debt		1,194,850			—			—			—			1,194,850
Other long-term liabilities		38,458			342			—			—			38,800
Intercompany note payable		—			7,175			—			(7,175	)		—

Total long-term liabilities		1,319,645			521,442			—			(229,448	)		1,611,639
Commitments and Contingencies
Stockholders’ Equity:
Preferred stock, $.0001 par value; 20,000,000 shares authorized, no shares issued and outstanding at December 31, 2009		—			—			—			—			—
Common stock, $.0001 par value; 180,000,000 shares authorized, 101,806,825 shares issued and outstanding at December 31, 2009		10			5			—			(5	)		10
Additional paid-in-capital		1,257,526			1,098,156			1,538			(1,099,694	)		1,257,526
Partner capital		—			33,019			—			(33,019	)		—
Accumulated other comprehensive loss		(25,948	)		—			(7	)		—			(25,955	)
Accumulated retained deficit		(348,626	)		(416,433	)		(513	)		416,946			(348,626	)

Total stockholders’ equity		882,962			714,747			1,018			(715,772	)		882,955

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,431,735		$	1,379,662		$	1,028		$	(945,220	)	$	2,867,205

MARINER ENERGY, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)
Three Months Ended June 30, 2010
(In thousands)


							Subsidiary						Consolidated
	Parent			Subsidiary			Non-						Mariner
	Company			Guarantors			Guarantors			Eliminations			Energy, Inc.
Revenues:
Natural gas	$	56,828		$	35,586		$	—		$	—		$	92,414
Oil		52,395			44,101			—			—			96,496
Natural gas liquids		14,454			5,712			—			—			20,166
Other revenues		561			1,135			—			—			1,696

Total revenues		124,238			86,534			—			—			210,772

Costs and Expenses:
Operating expenses		36,389			33,823			—			—			70,212
General and administrative expense		22,479			1,328			52			—			23,859
Depreciation, depletion and amortization		49,901			44,202			24			—			94,127
Other miscellaneous expense		773			34			—			—			807

Total costs and expenses		109,542			79,387			76			—			189,005

OPERATING INCOME (LOSS)		14,696			7,147			(76	)		—			21,767
Earnings of Affiliates		5,695			—			—			(5,695	)		—
Other Income/(Expense):
Interest income		704			2			4			(76	)		634
Interest expense, net of amounts capitalized		(19,866	)		(95	)		—			76			(19,885	)

Income (Loss) Before Taxes		1,229			7,054			(72	)		(5,695	)		2,516
Benefit (Provision) for Income Taxes		475			(1,287	)		—			—			(812	)

NET INCOME (LOSS)	$	1,704		$	5,767		$	(72	)	$	(5,695	)	$	1,704

MARINER ENERGY, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)
Three Months Ended June 30, 2009
(In thousands)


										Consolidated
	Parent			Subsidiary						Mariner
	Company			Guarantors			Eliminations			Energy, Inc.
Revenues:
Natural gas	$	104,704		$	37,659		$	—		$	142,363
Oil		57,162			21,792			—			78,954
Natural gas liquids		6,144			2,049			—			8,193
Other revenues		2,460			—			—			2,460

Total revenues		170,470			61,500			—			231,970


Costs and Expenses:
Operating expenses		29,040			26,357			—			55,397
General and administrative expense		21,421			(299	)		—			21,122
Depreciation, depletion and amortization		55,050			45,232			—			100,282
Other miscellaneous expense		1,599			1,159			—			2,758

Total costs and expenses		107,110			72,449			—			179,559

OPERATING INCOME (LOSS)		63,360			(10,949	)		—			52,411
Loss of Affiliates		(8,961	)		—			8,961			—
Other Income (Expense):
Interest income		2,183			—			(1,881	)		302
Interest expense, net of amounts capitalized		(16,973	)		(1,880	)		1,881			(16,972	)

Income (Loss) Before Taxes		39,609			(12,829	)		8,961			35,741
(Provision) Benefit for Income Taxes		(22,396	)		3,868			—			(18,528	)

NET INCOME (LOSS)	$	17,213		$	(8,961	)	$	8,961		$	17,213

MARINER ENERGY, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)
Six Months Ended June 30, 2010
(In thousands)


							Subsidiary						Consolidated
	Parent			Subsidiary			Non-						Mariner
	Company			Guarantors			Guarantors			Eliminations			Energy, Inc.
Revenues:
Natural gas	$	128,282		$	81,644		$	—		$	—		$	209,926
Oil		103,798			88,337			—			—			192,135
Natural gas liquids		31,468			16,358			—			—			47,826
Other revenues		2,772			1,226			—			—			3,998

Total revenues		266,320			187,565			—			—			453,885

Costs and Expenses:
Operating expenses		71,823			63,940			—			—			135,763
General and administrative expense		48,072			3,186			181			—			51,439
Depreciation, depletion and amortization		104,220			90,352			58			—			194,630
Other miscellaneous expense		3,199			297			—			—			3,496

Total costs and expenses		227,314			157,775			239			—			385,328

OPERATING INCOME (LOSS)		39,006			29,790			(239	)		—			68,557
Earnings of Affiliates		22,111			—			—			(22,111	)		—
Other Income/(Expense):
Interest income		912			2			6			(151	)		769
Interest expense, net of amounts capitalized		(40,329	)		(170	)		—			151			(40,348	)

Income (Loss) Before Taxes		21,700			29,622			(233	)		(22,111	)		28,978
Provision for Income Taxes		(4,733	)		(7,278	)		—			—			(12,011	)

NET INCOME (LOSS)	$	16,967		$	22,344		$	(233	)	$	(22,111	)	$	16,967

MARINER ENERGY, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)
Six Months Ended June 30, 2009
(In thousands)


										Consolidated
	Parent			Subsidiary						Mariner
	Company			Guarantors			Eliminations			Energy, Inc.
Revenues:
Natural gas	$	208,155		$	87,546		$	—		$	295,701
Oil		105,945			33,934			—			139,879
Natural gas liquids		10,190			4,472			—			14,662
Other revenues		7,420			17,644			—			25,064

Total revenues		331,710			143,596			—			475,306


Costs and Expenses:
Operating expenses		63,579			53,333			—			116,912
General and administrative expense		38,473			60			—			38,533
Depreciation, depletion and amortization		106,793			88,294			—			195,087
Full cost ceiling test impairment		342,595			362,136			—			704,731
Other miscellaneous expense		9,037			1,730			—			10,767

Total costs and expenses		560,477			505,553			—			1,066,030

OPERATING LOSS		(228,767	)		(361,957	)		—			(590,724	)
Loss of Affiliates		(253,867	)		—			253,867			—
Other Income (Expense):
Interest income		3,716			—			(3,329	)		387
Interest expense, net of amounts capitalized		(31,248	)		(3,455	)		3,329			(31,374	)

Loss Before Taxes		(510,166	)		(365,412	)		253,867			(621,711	)
Benefit for Income Taxes		103,261			111,545			—			214,806

NET LOSS	$	(406,905	)	$	(253,867	)	$	253,867		$	(406,905	)

MARINER ENERGY, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)
Six Months Ended June 30, 2010
(In thousands)


							Subsidiary			Consolidated
	Parent			Subsidiary			Non-			Mariner
	Company			Guarantors			Guarantors			Energy, Inc.
Net cash provided by (used in) operating activities	$	101,054		$	97,360		$	(181	)	$	198,233

Cash flow from investing activities:
Acquisitions and additions to oil and gas properties		(380,116	)		(70,902	)		(4,031	)		(455,049	)
Additions to other property and equipment		(495	)		—			(12	)		(507	)

Net cash used in investing activities		(380,611	)		(70,902	)		(4,043	)		(455,556	)

Cash flow from financing activities:
Credit facility borrowings		456,000			—			—			456,000
Credit facility repayments		(193,000	)		—			—			(193,000	)
Other financing activities		12,402			(23,192	)		3,850			(6,940	)

Net cash provided by (used in) financing activities		275,402			(23,192	)		3,850			256,060

(Decrease) Increase in Cash and Cash Equivalents		(4,155	)		3,266			(374	)		(1,263	)
Cash and Cash Equivalents at Beginning of Period		8,365			3			551			8,919

Cash and Cash Equivalents at End of Period	$	4,210		$	3,269		$	177		$	7,656

MARINER ENERGY, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)
Six Months Ended June 30, 2009
(In thousands)


										Consolidated
	Parent			Subsidiary						Mariner
	Company			Guarantors			Eliminations			Energy, Inc.
Net cash provided by operating activities	$	235,346		$	102,385		$	—		$	337,731

Cash flow from investing activities:
Acquisitions and additions to oil and gas properties		(198,862	)		(119,763	)		—			(318,625	)
Additions to other property and equipment		(614	)		(2	)		—			(616	)
Repayments of notes from affiliates		169,025			—			(169,025	)		—

Net cash used in investing activities		(30,451	)		(119,765	)		(169,025	)		(319,241	)

Cash flow from financing activities:
Credit facility borrowings		261,221			—			—			261,221
Credit facility repayments		(691,221	)		—			—			(691,221	)
Repayments of notes from affiliates		—			(169,025	)		169,025			—
Proceeds from equity offering		160,138			—			—			160,138
Proceeds from debt issuance		291,279			—			—			291,279
Other financing activities		(195,473	)		186,005			—			(9,468	)

Net cash (used in) provided by financing activities		(174,056	)		16,980			169,025			11,949

Increase (Decrease) in Cash and Cash Equivalents		30,839			(400	)		—			30,439
Cash and Cash Equivalents at Beginning of Period		2,809			400			—			3,209

Cash and Cash Equivalents at End of Period	$	33,648		$	—		$	—		$	33,648

15. Apache Merger

On April 15, 2010, Mariner and Apache Corporation, a Delaware corporation (“Apache”), announced that they entered into a definitive agreement pursuant to which Apache will acquire Mariner in a stock and cash transaction. The Agreement and Plan of Merger dated April 14, 2010 (the “Merger Agreement”), by and among Apache, Mariner and ZMZ Acquisitions LLC, a Delaware limited liability company and wholly owned subsidiary of Apache (“Merger Sub”), contemplates a merger (the “Merger”) whereby Mariner will be merged with and into Merger Sub, with Merger Sub surviving the Merger as a wholly owned subsidiary of Apache.

The total amount of cash and shares of Apache common stock that will be paid and issued, respectively, pursuant to the Merger Agreement is fixed, and Mariner stockholders will be entitled to receive (on an aggregate basis) 0.17043 of a share of Apache common stock, par value $0.625 per share, and $7.80 in cash for each share of Mariner common stock (the “Mixed Consideration”). Mariner stockholders have the right to elect to receive all cash ($26.00 per share), all Apache common stock (0.24347 of a share of Apache common stock) or the Mixed Consideration, subject to proration procedures as provided in the Merger Agreement.

Upon completion of the Merger, each outstanding option to purchase Mariner common stock will be converted into a fully vested option to purchase 0.24347 of a share of Apache common stock.

In addition, each outstanding share of Mariner restricted stock (other than restricted stock granted pursuant to Mariner’s 2008 Long-Term Performance-Based Restricted Stock Program) that is not subject to an unsatisfied price or other condition and that has not lapsed will vest and each holder will have the opportunity to elect the form of consideration as described above. Forty percent of the outstanding shares of Mariner restricted stock granted pursuant to its 2008 Long-Term Performance-Based Restricted Stock Program will vest and each holder will have the opportunity to elect the form of consideration as described above, and the remaining portion of such shares of Mariner restricted stock will be cancelled.

The Merger Agreement has been approved by the boards of directors of Apache, Mariner, and Merger Sub. The completion of the Merger is subject to certain conditions, including: (i) the adoption of the Merger Agreement by the stockholders of Mariner; (ii) subject to certain materiality exceptions, the accuracy of the representations and warranties made by Apache and Mariner; (iii) the effectiveness of a registration statement on Form S-4 that will be filed by Apache for the issuance of its common stock in the Merger, and the approval of the listing of these shares on the New York Stock Exchange; (iv) the termination or expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (v) the delivery of customary opinions from counsel to Apache and Mariner that the Merger will be treated as a tax-free reorganization for U.S. federal income tax purposes; (vi) compliance by Apache and Mariner with their respective obligations under the Merger Agreement; and (vii) the absence of legal impediments prohibiting the Merger.

The Merger Agreement also contains customary representations and warranties that the parties have made to each other as of specific dates. Apache and Mariner also have each agreed to certain covenants in the Merger Agreement. Among other covenants, Mariner has agreed, subject to certain exceptions, not to initiate, solicit, negotiate, provide information in furtherance of, approve, recommend or enter into an Acquisition Proposal (as defined in the Merger Agreement).

The Merger Agreement contains certain termination rights for both Apache and Mariner, including if the Merger is not completed by January 31, 2011. In the event of a termination of the Merger Agreement under certain circumstances, Mariner may be required to pay to Apache a termination fee of $67.0 million. In certain circumstances involving the termination of the Merger Agreement, one of Apache or Mariner will be obligated to reimburse the other’s expenses incurred in connection with the transactions contemplated by the Merger Agreement in an aggregate amount not to exceed $7.5 million. Any reimbursement of expenses by Mariner to Apache will reduce the amount of any termination fee paid by Mariner to Apache.

In connection with the Merger Agreement, Mariner and Continental Stock Transfer & Trust Company (the “Rights Agent”), entered into an Amendment to Rights Agreement, dated as of April 14, 2010 (the “Amendment”), to the Rights Agreement dated as of October 12, 2008 (the “Rights Agreement”), between Mariner and the Rights Agent, in connection with the execution of the Merger Agreement. Undefined capitalized terms used in this paragraph have the meaning ascribed to them in the Rights Agreement. The Amendment provides that none of (i) the announcement of the Merger, (ii) the execution and delivery of the Merger Agreement, (iii) the conversion of shares of Mariner common stock into the right to receive the Merger Consideration (as defined in the Merger Agreement) or (iv) the consummation of the Merger or any other transaction contemplated by the Merger Agreement will cause (1) Apache, Merger Sub or any of their Affiliates or Associates to become an Acquiring Person, or (2) the occurrence of a Flip-In Event, a Flip-Over Event, a Distribution Date or a Stock Acquisition Date under the Rights Agreement.

Subsequent to the announcement of the merger with Apache, two stockholder lawsuits styled as class actions were commenced on behalf of Mariner stockholders challenging the merger. City of Livonia Employees’ Retirement System v. Mariner Energy, Inc., et al, Cause No. 2010-24355, was filed in the 334th Judicial District Court of Harris County, Texas against Mariner and its directors. Plaintiff alleges that the Mariner directors breached their fiduciary duties by agreeing to sell the company through an unfair process and at an unfair price, and that Mariner aided and abetted those breaches of fiduciary duties. Plaintiff seeks to enjoin the transaction and to be awarded attorney’s fees. Southeastern Pennsylvania Transportation Authority v. Scott D. Josey, et al, cause No. 5427-VCP, was filed in the Court of Chancery of the State of Delaware against Mariner, its directors, certain Mariner officers, Apache and Merger Sub. Plaintiff alleges that the Mariner directors breached their fiduciary duties by agreeing to sell the company through an unfair process and at an unfair price, and by agreeing to the vesting of certain restricted stock held by Mariner management. Plaintiff also alleges that Apache and Merger Sub aided and abetted in those breaches of fiduciary duties. Plaintiff seeks to enjoin the merger and to be awarded attorney’s fees.

On August 1, 2010, the parties to the Delaware action entered into a memorandum of understanding, which, when reduced to a settlement agreement, is intended to be a final resolution of that action. Also on August 1, 2010, the parties to the Texas action agreed to be bound by the memorandum of understanding with respect to that action. In connection with the settlement, and in exchange for the releases described below, Apache and Mariner agreed to, and on August 2, 2010 Apache, Mariner and Merger Sub did, amend the Merger Agreement to eliminate the termination fee in the event that Mariner terminates the Merger Agreement in order to enter into a “superior proposal” with another party and to make certain additional disclosures in the proxy statement/prospectus for the transaction filed with the Securities and Exchange Commission. Additionally, in the event that any proceedings regarding appraisal rights under Section 262 of the Delaware General Corporation Law are commenced following the merger, Apache and Mariner have waived and will not present any argument that shares of Mariner restricted stock granted pursuant to Mariner’s 2008 Long-Term Performance-Based Restricted Stock Program will be counted in determining the total number of Mariner shares outstanding in such proceeding.

Subject to the completion of agreed-upon confirmatory discovery, the parties will negotiate in good faith to execute a settlement agreement to present to the Court of Chancery of the State of Delaware. Pursuant to the settlement, the Delaware action will be dismissed with prejudice on the merits, the plaintiffs in the Texas action will voluntarily dismiss that action with prejudice, and all defendants will be released from any and all claims relating to, among other things, the merger, the Merger Agreement and any disclosures made in connection therewith. The settlement is subject to customary conditions, including consummation of the merger, completion of certain confirmatory discovery, class certification, and final approval by the Court of Chancery of the State of Delaware. The settlement will not affect the form or amount of the consideration to be received by Mariner stockholders in the merger.

The defendants have denied and continue to deny any wrongdoing or liability with respect to all claims, events, and transactions complained of in these actions or that they have engaged in any wrongdoing. The defendants entered into the settlement to eliminate the uncertainty, burden, risk, expense and distraction of further litigation.

16. Subsequent Events

The Company’s evaluation has identified no matters which required disclosure as a subsequent event.

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

The following discussion is intended to assist you in understanding our business and the results of operations together with our present financial condition. This section should be read in conjunction with our Condensed Consolidated Financial Statements and the accompanying notes included in this Quarterly Report, as well as our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. For meanings of natural gas and oil terms used in the Quarterly Report, please refer to “Glossary of Oil and Natural Gas Terms” under “Business” in Part I, Item 1 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Forward-Looking Statements

Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. Please see “Risk Factors” in Item 1A of Part II of this Quarterly Report regarding certain risk factors relating to us.

Overview

We are an independent oil and natural gas exploration, development and production company with principal operations in the Permian Basin, the Gulf Coast and the Gulf of Mexico. During 2009, we produced approximately 21.1 MMboe and our average daily production rate was 58 Mboe. At December 31, 2009, we had 181.2 MMboe of estimated proved reserves, of which approximately 56% were onshore (47% in the Permian Basin and 8% in the Gulf Coast), with the balance offshore (15% in the Gulf of Mexico deepwater and 29% on the Gulf of Mexico shelf); 53% were natural gas; and 47% were oil and natural gas liquids (“NGLs”). Approximately 66% of our estimated proved reserves were classified as proved developed.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and our ability to find, develop and acquire oil and gas reserves that are economically recoverable while controlling and reducing costs. The energy markets historically have been very volatile. Oil and natural gas prices increased to, and then declined significantly from, historical highs in mid-2008 and may fluctuate and decline significantly in the future. Although we attempt to mitigate the impact of price declines and provide for more predictable cash flows through our hedging strategy, a substantial or extended decline in oil and natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of natural gas and oil reserves that we can economically produce and our access to capital. Conversely, the use of derivative instruments also can prevent us from realizing the full benefit of upward price movements.

The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. A sustained recession or slowdown in economic activity could further reduce worldwide demand for energy and result in lower oil and natural gas prices, which could materially adversely affect our profitability and results of operations.

Recent Developments

Apache Merger. On April 15, 2010, Mariner and Apache Corporation, a Delaware corporation (“Apache”), announced that they entered into a definitive agreement pursuant to which Apache will acquire Mariner in a stock and cash transaction. The Agreement and Plan of Merger dated April 14, 2010 (the “Merger Agreement”), by and among Apache, Mariner and ZMZ Acquisitions LLC, a Delaware limited liability company and wholly owned subsidiary of Apache (“Merger Sub”), contemplates a merger (the “Merger”) whereby Mariner will be merged with and into Merger Sub, with Merger Sub surviving the Merger as a wholly owned subsidiary of Apache.

($26.00 per share), all Apache common stock (0.24347 of a share of Apache common stock) or the Mixed Consideration, subject to proration procedures as provided in the Merger Agreement.

Upon completion of the Merger, each outstanding option to purchase Mariner common stock will be converted into a fully vested option to purchase 0.24347 of a share of Apache common stock.

Southeastern Pennsylvania Transportation Authority v. Scott D. Josey, et al, cause No. 5427-VCP, was filed in the Court of Chancery of the State of Delaware against Mariner, its directors, certain Mariner officers, Apache and Merger Sub. Plaintiff alleges that the Mariner directors breached their fiduciary duties by agreeing to sell the company through an unfair process and at an unfair price, and by agreeing to the vesting of certain restricted stock held by Mariner management. Plaintiff also alleges that Apache and Merger Sub aided and abetted in those breaches of fiduciary duties. Plaintiff seeks to enjoin the merger and to be awarded attorney’s fees.

Acquisitions. On December 31, 2009, we acquired the reorganized subsidiaries and operations of Edge Petroleum Corporation (“Edge”). The material assets acquired consist primarily of (i) estimated proved reserves as of December 31, 2009 of 100.5 Bcfe, of which approximately 75% are developed (consisting of 69% natural gas and 31% oil and NGLs), 81% are located in South Texas, and 44% are in the Flores/Bloomberg field in Starr County, Texas, (ii) approximately 60,000 net acres of undeveloped leasehold, primarily in Texas and New Mexico, and (iii) deferred tax assets of approximately $83.3 million, comprised of approximately $61.2 million in net operating loss carryforwards and $22.1 million in built-in losses from carryover tax basis in the properties. The effective date of the acquisition was June 30, 2009 and the purchase price was $260.0 million, less adjustments which resulted in a net purchase price as of December 31, 2009 of approximately $213.6 million, subject to final adjustments. We financed the net purchase price by borrowing under our secured revolving credit facility.

Second Quarter 2010 Highlights

In second quarter 2010 we reported net income of $1.7 million, which on a diluted earnings per share (EPS) basis was $0.02. During second quarter 2009, we reported net income of $17.2 million and $0.19 diluted EPS. Other financial and operational items include:

•

Average daily production during second quarter 2010 decreased 13% to 52 Mboe per day from 60 Mboe per day during second quarter 2009.

	•		Net cash provided by operations for the three-month period ended June 30, 2010 decreased 60% to $84.3 million from $211.8 million for the same period in 2009.

	•		Total revenues during second quarter 2010 decreased 9% to $210.8 million from $232.0 million during second quarter 2009.

Operational Update

Offshore — We drilled six offshore wells in the second quarter of 2010, five of which were successful. Information regarding these wells is shown below:


		Approximate
Well Name	Operator	Working Interest			Water Depth (Ft)		Location
South Marsh Island 11 #58	Mariner		100	%		73	Conventional Shelf
West Cameron 112 #A-2	Mariner		55	%		43	Conventional Shelf
Desoto Canyon 4 #1	Murphy Exploration		13	%		5,822	Deepwater
Keathley Canyon 875 #2	Anadarko		17	%		6,840	Deepwater
High Island 206 #B-3	Mariner		100	%		55	Conventional Shelf

As of June 30, 2010 no offshore wells were drilling.

In addition, we were the high bidder on 45 blocks on which we bid at the Minerals Management Service of the United States Department of the Interior (MMS) Central Gulf of Mexico Lease Sale 213 held on March 17, 2010, of which 44 were awarded and one was rejected. Our working interest in the awarded blocks ranges from 16.67% to 100% and our total net exposure is $62.5 million.

We are a non-operator and own a 12.5% working interest in the Heidelberg discovery comprised of Green Canyon blocks 816, 859, 860 and 903. The appraisal well drilled on Green Canyon Block 903 will be permanently plugged and abandoned due to mechanical problems which prevented the well from reaching the depth necessary to test the targeted objectives. The operator plans to drill a substitute appraisal well on Green Canyon Block 903 in order to evaluate the geologic objectives. Drilling operations for the substitute well are planned to commence after the drilling moratorium is lifted. Our estimated costs of the initial and substitute appraisal wells are $9.0 million and $14.0 million, respectively.

We operate Atwater Valley 426 (Bass Lite) in which we own a 53.8% working interest. On March 8, 2010, production of approximately 2,700 Boe/d was shut-in due to a suspected downhole mechanical failure. We plan to perform a well intervention during second half of 2010 in an effort to recommence production.

As a result of the Deepwater Horizon incidents in April 2010, the U.S. Department of the Interior (DOI) has issued a series of reforms to the oversight and management of offshore drilling activities on the federal Outer Continental Shelf (OCS). On July 12, 2010, the Secretary of the DOI directed the Bureau of Ocean Energy Management, Regulation and Enforcement, to issue a suspension until November 30, 2010 of drilling activities that use subsea blowout preventers or surface blowout preventers on floating facilities. Our Gulf of Mexico offshore operations have been impacted and likely may be impacted in the future by increased regulatory oversight, which may increase the cost of OCS wells, such as Lucius, Heidelberg and Bass Lite, and delay drilling and production therefrom.

Onshore — In the second quarter of 2010, in the Permian Basin we drilled 21 development wells and nine extension wells, all of which were successful. We also drilled three wells on our other onshore properties, all of which were successful. As of June 30, 2010, eight rigs were operating, seven on our Permian Basin properties and one on our other onshore properties.

Results of Operations

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

The following table sets forth summary information with respect to our oil and gas operations:


	Three Months Ended
	June 30,					Increase			%
	2010			2009		(Decrease)			Change
	(In thousands, except net production, average sales prices and % change)
Summary Operating Information:

Net Production:
Natural gas (MMcf)		17,674			23,811		(6,137	)		(26	)%
Oil (MBbls)		1,304			1,180		124			11	%
Natural gas liquids (MBbls)		513			332		181			55	%
Total barrel of oil equivalent (Mboe)		4,764			5,481		(717	)		(13	)%
Average daily production (Mboe/d)		52			60		(8	)		(13	)%
Hedging Activities:
Natural gas revenue gain	$	16,010		$	58,844	$	(42,834	)		(73	)%
Oil revenue (loss) gain		(3,050	)		11,556		(14,606	)		(126	)%

Total hedging revenue gain	$	12,960		$	70,400	$	(57,440	)		(82	)%

Average Sales Prices:
Natural gas (per Mcf) realized(1)	$	5.23		$	5.98	$	(0.75	)		(13	)%
Natural gas (per Mcf) unhedged		4.32			3.51		0.81			23	%
Oil (per Bbl) realized(1)		73.98			66.91		7.07			11	%
Oil (per Bbl) unhedged		76.32			57.12		19.20			34	%
Natural gas liquids (per Bbl) realized(1)		39.28			24.68		14.60			59	%
Natural gas liquids (per Bbl) unhedged		39.28			24.68		14.60			59	%
Total barrel of oil equivalent ($/Mboe) realized(1)		43.89			41.87		2.02			5	%
Total barrel of oil equivalent ($/Mboe) unhedged		41.17			29.03		12.14			42	%
Summary of Financial Information:
Natural gas revenue	$	92,414		$	142,363	$	(49,949	)		(35	)%
Oil revenue		96,496			78,954		17,542			22	%
Natural gas liquids revenue		20,166			8,193		11,973			146	%
Other revenues		1,696			2,460		(764	)		(31	)%
Lease operating expense		59,710			47,092		12,618			27	%
Severance and ad valorem taxes		6,101			3,730		2,371			64	%
Transportation expense		4,401			4,575		(174	)		(4	)%
General and administrative expense		23,859			21,122		2,737			13	%
Depreciation, depletion and amortization		94,127			100,282		(6,155	)		(6	)%
Other miscellaneous expense		807			2,758		(1,951	)		(71	)%
Net interest expense		19,251			16,670		2,581			15	%

Income before taxes		2,516			35,741		(33,225	)		(93	)%
Provision for income taxes		812			18,528		(17,716	)		(96	)%

Net Income	$	1,704		$	17,213	$	(15,509	)		(90	)%

Average Unit Costs per Mboe:
Lease operating expense	$	12.53		$	8.59	$	3.94			46	%
Severance and ad valorem taxes		1.28			0.68		0.60			88	%
Transportation expense		0.92			0.83		0.09			11	%
General and administrative expense		5.01			3.85		1.16			30	%
Depreciation, depletion and amortization		19.76			18.30		1.46			8	%


(1)		Average sales prices include the effects of hedging

Net Income for second quarter 2010 was $1.7 million compared to $17.2 million for the comparable period in 2009. The decrease was primarily attributable to a decrease in revenues of $21.2 million resulting from lower natural gas production and lower realized natural gas prices, and increases in lease operating expense and net interest expense of $12.6 million and $2.6 million, respectively. Partially offsetting the lower net income was a decrease in tax provision of $17.7 million. Basic and diluted earnings per share for second quarter 2010 were $0.02 for each measure compared to basic and diluted earnings per share of $0.19 for second quarter 2009.

Net Production for second quarter 2010 was approximately 4,764 Mboe, down 13% from 5,481 Mboe for second quarter 2009. Natural gas production for second quarter 2010 comprised approximately 62% of total net production compared to approximately 72% for second quarter 2009.

Natural gas production for second quarter 2010 decreased 26% to approximately 194 MMcf per day, compared to approximately 262 MMcf per day for second quarter 2009. Oil production for second quarter 2010 increased 11% to approximately 14,334 barrels per day, compared to approximately 12,964 barrels per day for second quarter 2009. Natural gas liquids production for second quarter 2010 increased 55% to approximately 5,641 barrels per day, compared to approximately 3,648 barrels per day for second quarter 2009.

Period over period changes in our production were primarily attributable to the following:

	•		Increased production of 164.9 Mboe, or 21%, from our Permian Basin properties, primarily as a result of our drilling and development of existing acreage.

	•		Increased production of 370.5 Mboe from our Gulf Coast and other onshore properties due to the Edge acquisition.

	•		Decreased production of 684.0 Mboe, or 31%, from our Gulf of Mexico deepwater properties at Bass Lite located in Atwater 426 (265.5 Mboe), Green Canyon 472 (137.4 Mboe), East Breaks 558 (103.4 Mboe) and Viosca Knoll 917 (62.1 Mboe). These decreases were primarily attributable to normal production declines, except for Bass Lite which was attributable to permitting delays and equipment unavailability resulting from the Deepwater Horizon incident. Decreases in production were partially offset by increased production at Geauxpher located in Garden Banks 462 (135.8 Mboe).

	•		Decreased production of 568.0 Mboe, or 23%, from our Gulf of Mexico shelf properties as a result of a recompletion not performed at High Island 116 (205.0 Mboe) as production was still flowing, and normal depletion declines at South Marsh Island 76 (150.0 Mboe) and South Timbalier 148 (113.7 Mboe), partially offset by increased production at West Cameron 172 (112.5 Mboe) as the well came back on production in the second quarter 2010.

Natural gas, oil and NGL revenues for second quarter 2010 decreased 9% to $209.1 million compared to $229.5 million for second quarter 2009 as a result of decreased production (approximately $30.0 million), partially offset by higher prices (approximately $9.6 million, net of the effect of hedging).

During second quarter 2010, our revenues reflected a net recognized hedging gain of $12.9 million comprised of $13.8 million in favorable cash settlements and an unrealized loss of $0.9 million related to the ineffective portion of open contracts that are not eligible for deferral under accounting for derivatives and hedging under GAAP due primarily to the basis differentials between the contract price and the indexed price at the point of sale. This compares to a net recognized hedging gain of approximately $70.4 million for second quarter 2009, comprised of $63.5 million in favorable cash settlements on our hedges, a $6.7 million gain reclassification on our liquidated swaps and an unrealized gain of $0.2 million related to the ineffective portion of open contracts that are not eligible for deferral under GAAP.

Our natural gas and oil average sales prices, and the effects of hedging activities on those prices, were as follows:


					Hedging
	Realized		Unhedged		Gain (Loss)			% Change
Three Months Ended June 30, 2010:
Natural gas (per Mcf)	$	5.23	$	4.32	$	0.91			21	%
Oil (per Bbl)		73.98		76.32		(2.34	)		(3	)%

Three Months Ended June 30, 2009:
Natural gas (per Mcf)	$	5.98	$	3.51	$	2.47			70	%
Oil (per Bbl)		66.91		57.12		9.79			17	%

Other revenues for second quarter 2010 decreased approximately $0.8 million to $1.7 million from $2.5 million for second quarter 2009 primarily as a result of $1.8 million in decreased third party gas sales partially offset by a $0.6 million gain on retirement of other property and $0.3 million receipt of claim settlement.

Lease operating expense (“LOE”) for second quarter 2010 increased approximately $12.6 million to $59.7 million from $47.1 million for second quarter 2009, due primarily to increases of $2.8 million from properties related to the Edge acquisition, $2.7 million in expenses on properties shut-in during second quarter 2009 due to Hurricane Ike that are currently producing, $1.6 million in platform and other repairs, $2.2 million in workovers at West Cameron 110 and $2.9 million of expenses related to Ewing Bank 921 (Black Widow).

Severance and ad valorem tax for second quarter 2010 increased approximately $2.4 million to $6.1 million from $3.7 million for second quarter 2009 due to an increase of $0.8 million relating to additional properties from the Edge acquisition, $1.5 million in additional severance tax from 57 new wells added in our onshore properties and increased production from our Permian Basin properties.

General and administrative expense for second quarter 2010 increased approximately $2.7 million to $23.8 million from $21.1 million for second quarter 2009 due to increases of $2.5 million in salaries and wages resulting from an average increase of 22% in headcount period over period and $2.0 million attributable to professional fees associated with the pending Apache merger. These increases were partially offset by $1.9 million in capitalized G&A related to our acquisition, exploration and development activities, $0.9 million in non-recurring projects and $0.3 million in stock compensation expense.

Depreciation, depletion, and amortization expense for second quarter 2010 decreased approximately $6.2 million to $94.1 million ($19.76 per Mboe) from $100.3 million ($18.30 per Mboe) for second quarter 2009. This decrease primarily resulted from $11.9 million in decreased expense due to lower production, partially offset by a $5.0 million increase in the depletion rate due to capital additions and the Edge acquisition.

Other miscellaneous expense for second quarter 2010 decreased approximately $2.0 million to $0.8 million from $2.8 million for second quarter 2009 due primarily to a decrease of $1.6 million in third party gas purchases made to satisfy our pipeline transportation commitments.

Net interest expense for second quarter 2010 increased approximately $2.6 million to $19.3 million from $16.7 million for second quarter 2009 due primarily to an increase in interest expense of $6.5 million as a result of our June 2009 issuance of 11³/₄% senior notes due 2016, partially offset by decreased capitalized interest of $3.2 million.

Provision for income taxes for second quarter 2010 reflected an effective tax rate of 32.3% as compared to 51.8% for second quarter 2009. The second quarter 2010 effective tax rate benefitted from a reduction in the tax expense associated with stock vesting award shortfalls recorded in the first quarter 2010 partially offset by additional tax expenses associated with non-deductible Apache merger transaction costs and other non-deductible costs. For the second quarter 2010, these offsetting tax adjustments provide a net reduction in tax expense of approximately $0.2 million. Without the impact of these adjustments, the effective tax rate would have been 39.1%. The second quarter 2009 tax provision included tax expense totaling $5.6 million attributable to stock award shortfalls. Without the impact of the shortfalls, the effective tax rate for second quarter 2009 would have been 36.1%.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

The following table sets forth summary information with respect to our oil and gas operations:


	Six Months Ended
	June 30,						Increase			%
	2010			2009			(Decrease)			Change
	(In thousands, except net production, average sales prices and % change)
Summary Operating Information:

Net Production:
Natural gas (MMcf)		38,399			45,859			(7,460	)		(16	)%
Oil (MBbls)		2,627			2,149			478			22	%
Natural gas liquids (MBbls)		1,089			605			484			80	%
Total barrel of oil equivalent (Mboe)		10,115			10,397			(282	)		(3	)%
Average daily production (Mboe/d)		56			57			(1	)		(2	)%
Hedging Activities:
Natural gas revenue gain	$	21,977		$	101,810		$	(79,833	)		(78	)%
Oil revenue (loss) gain		(8,444	)		32,391			(40,835	)		(126	)%

Total hedging revenue gain	$	13,533		$	134,201		$	(120,668	)		(90	)%

Average Sales Prices:
Natural gas (per Mcf) realized(1)	$	5.47		$	6.45		$	(0.98	)		(15	)%
Natural gas (per Mcf) unhedged		4.89			4.23			0.66			16	%
Oil (per Bbl) realized(1)		73.14			65.09			8.05			12	%
Oil (per Bbl) unhedged		76.35			50.02			26.33			53	%
Natural gas liquids (per Bbl) realized(1)		43.93			24.23			19.70			81	%
Natural gas liquids (per Bbl) unhedged		43.93			24.23			19.70			81	%
Total barrel of oil equivalent ($/Mboe) realized(1)		44.48			43.30			1.18			3	%
Total barrel of oil equivalent ($/Mboe) unhedged		43.14			30.40			12.74			42	%
Summary of Financial Information:
Natural gas revenue	$	209,926		$	295,701		$	(85,775	)		(29	)%
Oil revenue		192,135			139,879			52,256			37	%
Natural gas liquids revenue		47,826			14,662			33,164			226	%
Other revenues		3,998			25,064			(21,066	)		(84	)%
Lease operating expense		112,653			100,491			12,162			12	%
Severance and ad valorem taxes		13,020			7,262			5,758			79	%
Transportation expense		10,090			9,159			931			10	%
General and administrative expense		51,439			38,533			12,906			33	%
Depreciation, depletion and amortization		194,630			195,087			(457	)		<1	%
Full cost ceiling test impairment		—			704,731			(704,731	)		(100	)%
Other miscellaneous expense		3,496			10,767			(7,271	)		(68	)%
Net interest expense		39,579			30,987			8,592			28	%

Income (Loss) before taxes		28,978			(621,711	)		650,689			105	%
Provision (Benefit) for income taxes		12,011			(214,806	)		226,817			106	%

Net Income (Loss)	$	16,967		$	(406,905	)	$	423,872			104	%

Average Unit Costs per Mboe:
Lease operating expense	$	11.14		$	9.67		$	1.47			15	%
Severance and ad valorem taxes		1.29			0.70			0.59			84	%
Transportation expense		1.00			0.88			0.12			14	%
General and administrative expense		5.09			3.71			1.38			37	%
Depreciation, depletion and amortization		19.24			18.76			0.48			3	%


(1)		Average sales prices include the effects of hedging

Net Income (Loss) for first six months 2010 was $17.0 million compared to $(406.9) million for the comparable period in 2009. The increase was primarily attributable to no full-cost ceiling test impairment in first six months 2010 compared to an impairment of $704.7 million in first six months 2009. The increase in net income was partially offset by a decrease in tax benefit of $226.8 million, a decrease in revenues of $21.4 million, and increases in general and administrative expense and lease operating expense of $12.9 million and $12.2 million, respectively. Basic and diluted earnings per share for first six months 2010 were $0.17 for each measure, compared to basic and diluted earnings per share of $(4.50) for each measure for first six months 2009.

Net Production for first six months 2010 was approximately 10,115 Mboe, down 3% from 10,397 Mboe for first six months 2009. Natural gas production for first six months 2010 comprised approximately 63% of total net production compared to approximately 74% for first six months 2009.

Natural gas production for first six months 2010 decreased 16% to approximately 212 MMcf per day, compared to approximately 253 MMcf per day for first six months 2009. Oil production for first six months 2010 increased 22% to approximately 14,514 barrels per day, compared to approximately 11,874 barrels per day for first six months 2009. Natural gas liquids production for first six months 2010 increased 80% to approximately 6,014 barrels per day, compared to approximately 3,341 barrels per day for first six months 2009.

Period over period changes in our production were primarily attributable to the following:

	•		Increased production of 254.0 Mboe, or 17%, from our Permian Basin properties, primarily as a result of our drilling and development of existing acreage.

	•		Increased production of 737.0 Mboe from our Gulf Coast and other onshore properties due to the Edge acquisition.

	•		Decreased production of 535.7 Mboe, or 13%, from our Gulf of Mexico deepwater properties at East Breaks 558 (314.5 Mboe), Atwater 426 (311.6 Mboe), Green Canyon 472 (248.8 Mboe), Garden Banks 195 (223.9 Mboe), and Viosca Knoll 917 (140.9 Mboe). These decreases were primarily attributable to normal production declines, except for Bass Lite which was attributable to permitting delays and equipment unavailability resulting from the Deepwater Horizon incident. Decreases in production were partially offset by increased production at Geauxpher located in Garden Banks 462 (832.1 Mboe).

	•		Decreased production of 736.9 Mboe, or 16%, from our Gulf of Mexico shelf properties as a result of normal depletion declines at High Island 163 (127.3 Mboe), South Marsh Island 76 (373.2 Mboe) and South Timbalier 148 (113.9 Mboe), recompletion delays at High Island 116 (334.2 Mboe), High Island A467 (132.3 Mboe) and West Cameron 112 (117.5 Mboe), partially offset by increased production at certain of our properties including Vermilion 380 (230.8 Mboe), where production was shut-in due to Hurricane Ike in the first six months 2009, and South Timbalier 49 (156.1 Mboe), due to a new producing well in the current period.

Natural gas, oil and NGL revenues for first six months 2010 remained relatively flat at $449.9 million compared to $450.2 million for first six months 2009 as a result of decreased production (approximately $12.2 million, net of the effect of hedging) largely offset by higher prices (approximately $11.8 million, net of the effect of hedging).

During first six months 2010, our revenues reflected a net recognized hedging gain of $13.5 million comprised of $11.9 million in favorable cash settlements and an unrealized gain of $1.6 million related to the ineffective portion of open contracts that are not eligible for deferral under accounting for derivatives and hedging under GAAP due primarily to the basis differentials between the contract price and the indexed price at the point of sale. This compares to a net recognized hedging gain of approximately $134.2 million for first six months 2009, comprised of $121.0 million in favorable cash settlements on our hedges and a $13.2 million gain reclassification on our liquidated swaps.

Our natural gas and oil average sales prices, and the effects of hedging activities on those prices, were as follows:


					Hedging
	Realized		Unhedged		Gain (Loss)			% Change
Six Months Ended June 30, 2010:
Natural gas (per Mcf)	$	5.47	$	4.89	$	0.58			12	%
Oil (per Bbl)		73.14		76.35		(3.21	)		(4	)%

Six Months Ended June 30, 2009:
Natural gas (per Mcf)	$	6.45	$	4.23	$	2.22			52	%
Oil (per Bbl)		65.09		50.02		15.07			30	%

Other revenues for first six months 2010 decreased approximately $21.1 million to $4.0 million from $25.1 million for first six months 2009 primarily as a result of our receipt of a $16.6 million arbitration award in 2009 related to a consummated acquisition, $3.7 million in decreased third party gas sales and a $0.4 million decrease in income from gathering systems. Partially offsetting the decreases was a $0.6 million gain on retirement of other property.

Lease operating expense (“LOE”) for first six months 2010 increased approximately $12.2 million to $112.7 million from $100.5 million for first six months 2009, due primarily to increases of $5.9 million from properties related to the Edge acquisition, $4.8 million in expenses on properties shut-in during the first six months 2009 due to Hurricane Ike that are currently producing, $6.4 million due to workovers primarily on West Cameron 110 and South Marsh Island 76, $3.2 million of pipeline repairs for Mississippi Canyon (Pluto), $2.0 million in methanol charges on Garden Banks 462 (Geauxpher) and $3.0 million of expenses related to Ewing Bank 921 (Black Widow). These were partially offset by decreases of $7.2 million in hurricane reimbursements received in first six months 2010 and $6.8 million related to the retrospective contingent OIL insurance premium in first six months 2010.

Severance and ad valorem tax for first six months 2010 increased approximately $5.7 million to $13.0 million from $7.3 million for first six months 2009 due to an increase of $2.4 million relating to additional properties from the Edge acquisition, $3.1 million in additional severance tax from 65 new wells added in our onshore properties and increased production from our Permian Basin properties.

Transportation expense for first six months 2010 increased approximately $0.9 million to $10.1 million from $9.2 million for first six months 2009 due primarily to increased expense at Garden Banks 462 (Geauxpher) and Green Canyon 646 not included in first six months 2009 due to production at those fields commencing subsequent to that period.

General and administrative expense for first six months 2010 increased approximately $12.9 million to $51.4 million from $38.5 million for first six months 2009 due to increases of $9.2 million in salaries and wages resulting from an average increase of 20% in headcount period over period, $2.0 million attributable to professional fees associated with the pending Apache merger, $1.8 million in costs associated with the expansion of our corporate offices and other administrative expenses , and $1.6 million in office, computer and corporate expenditures due to higher taxes and insurance. These increases were partially offset by $3.5 million in capitalized G&A related to our acquisition, exploration and development activities and $1.1 million in decreased overhead recovery.

Depreciation, depletion, and amortization expense for first six months 2010 decreased approximately $0.5 million to $194.6 million ($19.24 per Mboe) from $195.1 million ($18.76 per Mboe) for first six months 2009. This decrease primarily resulted from lower expense of $4.8 million due to reduced production and lower expense of $2.3 million due to a full-cost ceiling test impairment recorded in 2009 which increased our depletion rate in 2009, partially offset by a $5.6 million increase in the depletion rate in 2010 due to capital additions and the Edge acquisition.

Full cost ceiling test impairment was not recognized for first six months 2010 due to the net capitalized cost of our proved oil and gas properties not exceeding our ceiling limit. For first six months 2009, the net capitalized cost of our proved oil and gas properties exceeded our ceiling limit and an impairment of $704.7 million was recognized. See Note 5 “Oil and Gas Properties” in Item 1 of Part I of this Quarterly Report on Form 10-Q for more detail on this impairment.

Other miscellaneous expense for first six months 2010 decreased approximately $7.3 million to $3.5 million from $10.8 million for first six months 2009 due primarily to a decrease in bad debt expense of approximately $3.4 million and a $3.2 million decrease in third party gas purchases made to satisfy our pipeline transportation commitments.

Net interest expense for first six months 2010 increased approximately $8.6 million to $39.6 million from $31.0 million for first six months 2009 due primarily to an increase in interest expense of $16.0 million as a result of our June 2009 issuance of 11³/₄% senior notes due 2016, partially offset by increased capitalized interest of $6.3 million.

Provision for income taxes for first six months 2010 reflected an effective tax rate of 41.4% as compared to 34.6% for first six months 2009. The effective tax rate for first six months 2010 includes the impact of additional tax expense totaling $1.5 million for non-deductible Apache merger transaction costs and other non-deductible costs. Without the impact of the non-deductible Apache merger transaction costs, the effective tax rate for first six months 2010 would have been 38.8%. The effective tax rate for first six months 2009 included tax expense totaling $7.1 million associated with stock award shortfalls. Due to the net loss for the first six months of 2009, the increase in tax expense reduced the effective tax rate to 34.6%. Without the impact of the shortfalls, the effective tax rate for first six months 2009 would have been 35.7%.

Liquidity and Capital Resources

Net cash provided by operating activities decreased by $139.5 million to $198.2 million from $337.7 million for the six months ended June 30, 2010 and 2009, respectively. The decrease was due primarily to decreased receivables collections of $52.9 million, decreased hurricane insurance proceeds of $32.8 million, $10.3 million received in first six months 2009 for liquidated crude oil fixed price swaps reclassified to earnings in subsequent quarters and an additional OIL payment of $7.2 million.

As of June 30, 2010, we had a working capital deficit of $180.7 million, including an abandonment liability and a deferred tax liability partially offset by a non-cash current derivative asset and prepaid assets. In addition, working capital was negatively impacted by accrued capital expenditures. We expect that this deficit will be funded by cash flow from operating activities and borrowings under our bank credit facility, as needed.

Net cash flows used in investing activities increased by $136.3 million to $455.5 million from $319.2 million for the six months ended June 30, 2010 and 2009, respectively, due primarily to our acquisition of additional interests in the Permian Basin for approximately $100.0 million and increased capital expenditures attributable to greater activity in our drilling programs.

Net cash flows provided by financing activities increased by $244.2 million to $256.1 million from $11.9 million for the six months ended June 30, 2010 and 2009, respectively. This increase was due primarily to $693.0 million net increased borrowings under our bank credit facility, primarily to finance acquisitions (including approximately $100.0 million in additional interests in the Permian Basin), partially offset by $446.2 million of proceeds from debt and securities offerings in June 2009.

Capital Expenditures — The following table presents major components of our capital expenditures during the six months ended June 30, 2010.


	In thousands		Percentage
Capital Expenditures:
Acquisitions (property and leasehold)	$	208,971		43	%
Offshore natural gas and oil development		124,147		25	%
Natural gas and oil exploration		67,348		14	%
Onshore natural gas and oil development		66,000		13	%
Other items (primarily capitalized overhead)		25,761		5	%

Total capital expenditures	$	492,227		100	%

The above table reflects decreased non-cash capital accruals of $1.5 million that are a component of working capital changes in the statement of cash flows.

Bank Credit Facility — We have a secured revolving credit facility with a group of banks pursuant to an amended and restated credit agreement dated March 2, 2006, as further amended. The credit facility matures January 31, 2012 and is subject to a borrowing base which is redetermined periodically. The outstanding principal balance of loans under the credit facility may not exceed the borrowing base. The most recent borrowing base redetermination concluded in April 2010 when the credit facility was amended to:

	•		Increase the borrowing base by $150.0 million to $950.0 million until the next redetermination under the credit agreement,

	•		Reschedule the regular periodic borrowing base redeterminations to begin in February and August of each year,

	•		Give the lenders an option to redetermine the borrowing base upon termination of hedge contracts with more than six months remaining in their original nominal term,

	•		Increase the maximum permitted ratio of total debt to EBITDA (as defined in the credit agreement) to 3.5 to 1.0 from 2.5 to 1.0, and

	•		Give us optionality to issue before January 1, 2011 up to $400.0 million in additional unsecured debt with a non-default interest rate of up to 13% per annum (plus a maximum default rate of 3%) and a scheduled maturity date no earlier than March 2, 2015. Upon closing such a debt issuance, the borrowing base automatically would reduce by 25% of the aggregate principal amount of the debt issued until otherwise redetermined under the credit agreement.

As of June 30, 2010, maximum credit availability under the facility was $1.0 billion, including up to $50.0 million in letters of credit, subject to a borrowing base of $950.0 million. As of June 30, 2010, there were $568.0 million in advances outstanding under the credit facility and four letters of credit outstanding totaling $4.7 million, of which $4.2 million is required for plugging and abandonment obligations at certain of our offshore fields. As of June 30, 2010, after accounting for the $4.7 million of letters of credit, we had $377.3 million available to borrow under the credit facility.

Borrowings under the bank credit facility bear interest at either a LIBOR-based rate or a prime-based rate, at our option, plus a specified margin. At June 30, 2010, when borrowings at both LIBOR and prime-based rates were outstanding, the blended interest rate was 2.92% on all amounts borrowed. During the six months ended June 30, 2010, the commitment fee on unused capacity was 0.5% per annum.

The credit facility subjects us to various restrictive covenants and contains other usual and customary terms and conditions, including limits on additional debt, cash dividends and other restricted payments, liens, investments, asset dispositions, mergers and speculative hedging. Financial covenants under the credit facility require us to, among other things:

	•		maintain a ratio of consolidated current assets plus the unused borrowing base to consolidated current liabilities of not less than 1.0 to 1.0; and

	•		maintain a ratio of total debt to EBITDA (as defined in the credit agreement) of not more than 3.5 to 1.0.

We were in compliance with these covenants as of June 30, 2010 when the ratio of consolidated current assets plus the unused borrowing base to consolidated current liabilities was 1.92 to 1.0 and the ratio of total debt to EBITDA was 2.6 to 1.0.

Our payment and performance of our obligations under the credit facility (including any obligations under commodity and interest rate hedges entered into with facility lenders) are secured by liens upon substantially all of the assets of us and our subsidiaries, except our Canadian subsidiary, and guaranteed by our subsidiaries, other than Mariner Energy Resources, Inc. which is a co-borrower, and our Canadian subsidiary.

Senior Notes — In 2009, we sold and issued $300.0 million aggregate principal amount of our 11³/₄% senior notes due 2016 (the “11³/₄% Notes”). In 2007, we sold and issued $300.0 million aggregate principal amount of our 8% senior notes due 2017 (the “8% Notes”). In 2006, we sold and issued $300.0 million aggregate principal amount of our 7¹/₂% senior notes due 2013 (the “7¹/₂% Notes” and together with the 11³/₄% Notes and the 8% Notes, the “Notes”). The Notes are governed by indentures that are substantially identical for each series. The Notes are senior unsecured obligations of Mariner. The 11³/₄% Notes mature on June 30, 2016 with interest payable on June 30 and December 30 of each year beginning December 30, 2009. The 8% Notes mature on May 15, 2017 with interest payable on May 15 and November 15 of each year. The 7¹/₂% Notes mature on April 15, 2013 with interest payable on April 15 and October 15 of each year. There is no sinking fund for the Notes. We and our restricted subsidiaries are subject to certain financial and non-financial covenants under each of the indentures governing the Notes. We were in compliance with the financial covenants under the Notes as of June 30, 2010.

Future Uses of Capital. Our identified needs for liquidity in the future are as follows:

	•		funding future capital expenditures;

	•		funding hurricane repairs and hurricane-related abandonment operations;

	•		financing any future acquisitions that we may identify;

	•		paying routine operating and administrative expenses; and

	•		paying other commitments comprised largely of cash settlement of hedging obligations and debt service.

2010 Capital Expenditures. We anticipate that our base operating capital expenditures for 2010 will be approximately $728.0 million (excluding hurricane-related expenditures and acquisitions). This amount includes our net exposure of approximately $62.5 million as a result of the 44 blocks awarded from the March 2010 MMS Central Gulf of Mexico Lease Sale 213. There is significant potential for increase or decrease in our capital expenditure budget depending upon drilling success, acquisition opportunities and cash flow during the year, subject to our obligations under the Merger Agreement not to exceed the budget by more the $50.0 million in the aggregate without Apache’s prior written consent. Approximately 65% of the base operating capital program is planned to be allocated to development activities, 28% to exploration activities, and the remainder to other items (primarily capitalized overhead and interest). In addition, we estimate additional hurricane-related costs of $44.5 million during 2010 related to Hurricane Ike that we believe are substantially covered under applicable insurance. Complete recovery or settlement is not expected to occur during the next 12 months.

Future Capital Resources. Our anticipated sources of liquidity in the future are as follows:

	•		cash flow from operations in future periods;

	•		proceeds under our bank credit facility;

	•		proceeds from insurance policies relating to hurricane repairs; and

	•		proceeds from future capital markets transactions as needed.

Historically, we generally have tailored our operating capital program (exclusive of hurricane-related expenditures and acquisitions) within our projected operating cash flow so that our operating capital requirements were largely self-funding. In 2010, we anticipate that this program will exceed our projected operating cash flow due primarily to accelerated development of our long-lived, oily Permian Basin properties, and development of two deepwater discoveries and our unconventional resource portfolio. Based on our current operating plan and assumed price case, our expected cash flow from operations and continued access to our bank credit facility allows us ample liquidity to conduct our operations as planned for the foreseeable future. We generally expect to fund future acquisitions on a case by case basis through a combination of bank debt and capital markets activities, subject to our obligations under the Apache Merger Agreement.

The timing of expenditures (especially regarding deepwater projects) is unpredictable. Also, our cash flows are heavily dependent on the oil and natural gas commodity markets, and our ability to hedge oil and natural gas prices. If either oil or natural gas commodity prices decrease from their current levels, our ability to finance our planned capital expenditures could be affected negatively. Amounts available for borrowing under our bank credit facility are largely dependent on our level of estimated proved reserves and current oil and natural gas prices. If either our estimated proved reserves or commodity prices decrease, amounts available to us to borrow under our bank credit facility could be reduced. If our cash flows are less than anticipated or amounts available for borrowing are reduced, we may be forced to defer planned capital expenditures.

In addition, the recent worldwide financial and credit crisis may adversely affect our liquidity. We may be unable to obtain adequate funding under our bank credit facility because our lending counterparties may be unwilling or unable to meet their funding obligations, or because our borrowing base under the facility may be decreased as the result of a redetermination, reducing it due to lower oil or natural gas prices, operating difficulties, declines in reserves or other reasons. If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our business strategies or otherwise take advantage of business opportunities or respond to competitive pressures.

Off-Balance Sheet Arrangements

Letters of Credit — Our bank credit facility has a letter of credit subfacility of up to $50.0 million that is included as a use of the borrowing base. As of June 30, 2010, four such letters of credit totaling $4.7 million were outstanding.

Fair Value Measurement

We determine the fair value of our natural gas and crude oil fixed price swaps by reference to forward pricing curves for natural gas and oil futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit-risk adjusted discount rate. The credit risk adjustment for swap liabilities is based on our credit quality and the credit risk adjustment for swap assets is based on the credit quality of our counterparty. Our fair value determinations of our swaps have historically approximated our exit price for such derivatives.

We have determined that the fair value methodology described above for our swaps is consistent with observable market inputs and have categorized our swaps as Level 2 in accordance with accounting for fair value measurements and disclosures under GAAP.

During the six months ended June 30, 2010, we recorded a net asset for the increase in the fair value of our derivative financial instruments of $76.9 million, principally due to the decrease in natural gas commodity prices below our swap prices. The increase was comprised of an increase in accumulated other comprehensive income of approximately $57.0 million, net of income taxes of $31.8 million, approximately $11.9 million of favorable cash hedging settlements during the period reflected in natural gas and oil revenues and an unrealized, non-cash gain due to hedging ineffectiveness under GAAP of approximately $1.6 million reflected in natural gas revenues.

We expect the continued volatility of natural gas and oil commodity prices will have a material impact on the fair value of our derivatives positions. It is our intent to hold all of our derivatives positions to maturity such that realized gains or losses are generally recognized in income when the hedged natural gas or oil is produced and sold. While the derivatives settlements may decrease (or increase) our effective price realized, the ultimate settlement of our derivatives positions is not expected to materially adversely affect our liquidity, results of operations or cash flows.

Recent Accounting Pronouncements

In July 2010, the Financial Accounting Standards Board (FASB) issued authoritative guidance which requires an entity to provide a greater level of disaggregated information about the credit quality of its financing receivables and its allowance for credit losses. In addition, an entity is required to disclose credit quality indicators, past due information, and modifications of its financing receivables. These disclosures are intended to help financial

statement users assess an entity’s credit risk exposures and evaluate the adequacy of its allowance for credit losses. The guidance is effective for interim and annual reporting periods ending on or after December 15, 2010. We are currently evaluating the potential impact of adopting the guidance. We will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2010.

In April 2010, the FASB issued authoritative guidance which provides clarification that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trade should not be considered to contain a condition that is not a market, performance or service condition. Therefore, the award would be classified as an equity award if it otherwise qualifies as equity. The guidance is effective for interim and annual reporting periods beginning on or after December 15, 2010. Early adoption is allowed. We are currently evaluating the potential impact of adopting the guidance.

In February 2010, the FASB issued authoritative guidance which requires additional information to be disclosed principally in respect of Level 3 fair value measurements and transfers to and from Level 1 and Level 2 measurements. In addition, enhanced disclosure is required concerning inputs and valuation techniques used to determine Level 2 and Level 3 fair value measurements. The guidance is generally effective for interim and annual reporting periods beginning after December 15, 2009; however, the requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Early adoption is allowed. We adopted the standard effective January 1, 2010. The adoption did not have a material impact on our consolidated financial position, cash flows or results of operations.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Prices and Related Hedging Activities

Our major market risk exposure continues to be the prices applicable to our natural gas and oil production. The sales price of our production is primarily driven by the prevailing market price. Historically, prices received for our natural gas and oil production have been volatile and unpredictable. Hypothetically, if production levels were to remain at 2010 levels, a 10% increase in commodity prices from those as of June 30, 2010 would increase our cash flow by approximately $43.7 million for the six months ended June 30, 2010.

The energy markets historically have been very volatile, and we can reasonably expect that oil and gas prices will be subject to wide fluctuations in the future. In an effort to reduce the effects of the volatility of the price of oil and natural gas on our operations, management has adopted a policy of hedging oil and natural gas prices from time to time primarily through the use of commodity price swap agreements and costless collar arrangements. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. In addition, forward price curves and estimates of future volatility are used to assess and measure the ineffectiveness of our open contracts at the end of each period. If open contracts cease to qualify for hedge accounting, the mark-to-market change in fair value is recognized in oil and natural gas revenue in the Condensed Consolidated Statements of Operations. Not qualifying for hedge accounting and cash flow hedge designation will cause volatility in Net Income. The fair values we report in our Condensed Consolidated Financial Statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

On January 29, 2009, we liquidated crude oil fixed price swaps that previously had been designated as cash flow hedges for accounting purposes in respect of 977,000 barrels of crude oil in exchange for a cash payment to us of $10.0 million and installment payments of $13.5 million to be paid monthly to us through 2009. On April 16, 2009, we received a $10.5 million cash settlement on the hedges that were settled in monthly installments at January 29, 2009. Since, at the time of liquidation, the forecasted sales of crude oil volumes were still expected to occur, the accumulated losses through January 29, 2009 on the related derivative contracts remained in accumulated other comprehensive income. These accumulated losses were reclassified to oil revenues throughout 2009 as the physical transactions occurred. Additionally, all changes in the value of these derivative contracts subsequent to January 29, 2009 were also reclassified monthly from accumulated other comprehensive income to current period oil revenues. The table below reflects these reclassifications for the three months and six months ended June 30, 2009.

Derivative gains and losses are recorded by commodity type in oil and natural gas revenues in the Condensed Consolidated Statements of Operations. The effects on our oil and gas revenues from our hedging activities were as follows:


	Three Months Ended June 30,					Six Months Ended June 30,
	2010			2009		2010		2009
	(In thousands)
Cash Gain on Settlements (1)	$	13,798		$	63,547	$	11,913	$	121,004
Reclassification of Liquidated Swaps (2)		—			6,677		—		13,200
(Loss) Gain on Hedge Ineffectiveness (3)		(838	)		176		1,620		(3	)

Total	$	12,960		$	70,400	$	13,533	$	134,201


(1)		Designated as cash flow hedges pursuant to accounting for derivatives and hedging under GAAP.

(2)		Net gain realized in 2009 on liquidated crude oil fixed price swaps that do not qualify for hedge accounting.

(3)		Unrealized (loss) gain recognized in natural gas revenue related to the ineffective portion of open contracts designated as cash flow hedges that are not eligible for deferral under GAAP due primarily to the basis differentials between the contract price and the indexed price at the point of sale.

As of June 30, 2010, we had the following hedge contracts outstanding:


			Weighted Average		Fair Value
Fixed Price Swaps	Quantity		Fixed Price		Asset/(Liability)
					(In thousands)
Natural Gas (MMbtus)
July 1 — December 31, 2010		20,600,274	$	5.56	$	15,297
January 1 — December 31, 2011		29,389,843	$	5.79		13,430
January 1 — December 31, 2012		22,338,802	$	6.11		9,267
January 1 — December 31, 2013		5,840,000	$	6.76		4,795
Crude Oil (Bbls)
July 1 — December 31, 2010		1,595,280	$	73.64		(5,179	)
January 1 — December 31, 2011		1,978,364	$	79.33		(275	)
January 1 — December 31, 2012		494,100	$	80.76		(199	)
January 1 — December 31, 2013		408,800	$	82.81		204

Total					$	37,340

We have reviewed the financial strength of our counterparties and believe the credit risk associated with these swaps to be minimal. Hedges with counterparties that are lenders under our bank credit facility are secured under the bank credit facility.

As of June 30, 2010, we expect to realize within the next 12 months a net gain of approximately $18.2 million resulting from hedging activities that are currently recorded in accumulated other comprehensive income. The net hedging gain is expected to be realized as a decrease of $8.0 million to oil revenues and an increase of $26.2 million to natural gas revenues.

Interest Rate Market Risk — Borrowings under our bank credit facility, as discussed under the caption “Liquidity and Capital Resources”, mature on January 31, 2012, and bear interest at either a LIBOR-based rate or a prime-based rate, at our option, plus a specified margin. Both options expose us to risk of earnings loss due to changes in market rates. We have not entered into interest rate hedges that would mitigate such risk. As of June 30, 2010, the blended interest rate on our outstanding bank debt was 2.92%. If the balance of our bank debt at June 30, 2010 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.4 million per quarter.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Mariner, under the supervision and with the participation of its management, including Mariner’s principal executive officer and principal financial officer, evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report. Based on that evaluation, our principal executive officer and principal financial officer concluded that Mariner’s disclosure controls and procedures are effective as of June 30, 2010 to ensure that information required to be disclosed by Mariner in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls Over Financial Reporting

There were no changes that occurred during the quarter ended June 30, 2010 covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1A. Risk Factors.

Please refer to Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Various statements in this Quarterly Report on Form 10-Q (“Quarterly Report”), including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “may,” “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this Quarterly Report speak only as of the date of this Quarterly Report; we disclaim any obligation to update these statements unless required by law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. We disclose important factors that could cause our actual results to differ materially from our expectations described in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of Part I and elsewhere in this Quarterly Report. These risks, contingencies and uncertainties relate to, among other matters, the following:

	•		the volatility of oil and natural gas prices;

	•		discovery, estimation, development and replacement of oil and natural gas reserves;

	•		cash flow, liquidity and financial position;

	•		business strategy;

	•		amount, nature and timing of capital expenditures, including future development costs;

	•		availability and terms of capital;

	•		timing and amount of future production of oil and natural gas;

	•		availability of drilling and production equipment;

	•		operating costs and other expenses;

	•		prospect development and property acquisitions;

	•		risks arising out of our hedging transactions;

	•		marketing of oil and natural gas;

	•		competition in the oil and natural gas industry;

	•		the impact of weather and the occurrence of natural events and natural disasters such as loop currents, hurricanes, fires, floods and other natural events, catastrophic events and natural disasters;

	•		governmental regulation of the oil and natural gas industry;

	•		environmental liabilities;

	•		developments in oil-producing and natural gas-producing countries;

	•		uninsured or underinsured losses in our oil and natural gas operations;

	•		risks related to our level of indebtedness; and

	•		risks related to significant acquisitions or other strategic transactions, such as failure to realize expected benefits or objectives for future operations.

On April 14, 2010, we entered into a definitive merger agreement pursuant to which we would be acquired by Apache Corporation.

Failure to complete the merger or delays in completing the merger could negatively affect our stock price and future businesses and operations.

There is no assurance that we will be able to consummate the merger. If the merger is not completed for any reason, we may be subject to a number of risks, including the following:

	•		we will not realize the benefits expected from the merger, including a potentially enhanced financial and competitive position;

	•		the current market price of our common stock may reflect a market assumption that the merger will occur and a failure to complete the merger could result in a negative perception of us by the stock market and cause a decline in the market price of our common stock;

	•		certain costs relating to the merger, including certain investment banking, financing, legal and accounting fees and expenses, must be paid even if the merger is not completed, and we may be required to pay substantial fees to Apache if the merger agreement is terminated under specified circumstances; and

	•		we would continue to face the risks that we currently face as an independent company.

Delays in completing the merger could exacerbate uncertainties concerning the effect of the merger, which may have an adverse effect on our business following the merger and could defer or detract from the realization of the benefits expected to result from the merger.

There may be substantial disruption to our business and distraction of our management and employees as a result of the merger.

There may be substantial disruption to our business and distraction of our management and employees from day-to-day operations because matters related to the merger may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to us.

Business uncertainties and contractual restrictions while the merger is pending may have an adverse effect on us.

Uncertainty about the effect of the merger on employees, suppliers, partners, regulators, and customers may have an adverse effect on us. These uncertainties may impair our ability to attract, retain, and motivate key personnel until the merger is consummated and could cause suppliers, customers and others that deal with us to defer purchases or other decisions concerning us or seek to change existing business relationships with us. In addition, the merger agreement restricts us from making certain acquisitions and taking other specified actions without Apache’s approval. These restrictions could prevent us from pursuing attractive business opportunities that may arise prior to the completion of the merger.

The merger agreement restricts our ability to pursue alternatives to the merger.

The merger agreement contains “no shop” provisions that, subject to limited fiduciary exceptions, restrict our ability to initiate, solicit, encourage or facilitate, discuss, negotiate or accept a competing third party proposal to acquire all or a significant part of us. Further, there are only a limited number of exceptions that would allow our board of directors to withdraw or change its recommendation to holders of our common stock that they vote in favor of the adoption of the merger agreement. If our board of directors were to take such actions as permitted by the merger agreement, doing so in specified situations could entitle Apache to terminate the merger agreement and to be paid a termination fee of $67.0 million. These restrictions could deter a potential acquiror from proposing an alternative transaction.

Gulf of Mexico Oil Spill

On April 22, 2010, a deepwater drilling rig, the Deepwater Horizon, operating in the Gulf of Mexico on Mississippi Canyon Block 252 sank after an apparent blowout and fire, resulting in a significant spill of hydrocarbons. Neither Apache nor Mariner owns an interest in the field. As a result of the incident and spill, the U.S. Department of the Interior (DOI) issued a series of reforms to the oversight and management of offshore exploration drilling activities on the federal Outer Continental Shelf (OCS). On May 30, 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOE, formerly the Minerals Management Service) of the DOI announced, as a result of the Deepwater Horizon incidents, a Moratorium Notice to Lessees and Operators (Moratorium NTL), which directed oil and gas lessees and operators to cease drilling new deepwater (depths greater than 500 feet) wells on the OCS, and put oil and gas lessees and operators on notice that, with certain exceptions, the BOE would not consider drilling permits for deepwater wells and related activities for a period of six months. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana issued a preliminary injunction prohibiting the enforcement of the moratorium, which the DOI appealed to the Fifth Circuit Court of Appeals. On July 8, 2010, the court of appeals denied the government’s request that the district court’s order be stayed while the appeal is pending. On July 12, 2010, the Secretary of the DOI directed the BOE to issue a suspension until November 30, 2010 of drilling activities that use subsea blowout preventers or surface blowout preventers on floating facilities, rather than a moratorium based on water depths.

In addition, on June 8, 2010, the BOE issued a Notice to Lessees focusing on safety measures, which among other things, requires an OCS operator’s Chief Executive Officer to certify that such operator is conducting its operations in compliance with applicable operating regulations found at 30 C.F.R. 250.

The Gulf of Mexico offshore operations of Mariner have been impacted, and likely may be impacted in the future, by increased regulatory oversight, which may increase the cost of OCS wells and delay drilling and production therefrom. There may be reinstitution of the currently enjoined Moratorium NTL, changes in laws and regulations, increases in insurance costs or decreases in insurance availability, as well as further delays in offshore exploration and drilling activities in the Gulf of Mexico. Any of the aforementioned changes could have a material effect on the financial condition or results of operations of Mariner.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Issuer Purchases of Equity Securities


							Maximum Number (or
					Total Number of		Approximate Dollar
					Shares		Value) of
	Total				(or Units)		Shares (or Units)
	Number of		Average		Purchased as		that May Yet Be
	Shares (or		Price Paid		Part of Publicly		Purchased Under the
	Units)		per Share		Announced Plans or		Plans or
Period	Purchased		(or Unit)		Programs		Programs
April 1, 2010 to April 30, 2010 (1)		35,346	$	24.80		—		—
May 1, 2010 to May 31, 2010 (1)		111,128	$	22.99		—		—
June 1, 2010 to June 30, 2010 (1)		1,517	$	22.42		—		—

Total		147,991	$	23.42		—		—


(1)		These shares were withheld upon the vesting of employee restricted stock grants in connection with payment of required withholding taxes.

Item 6. Exhibits


Number		Description

2.1*		Agreement and Plan of Merger dated as of April 14, 2010 by and among Apache Corporation, ZMZ Acquisitions LLC and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Mariner’s Form 8-K filed on April 16, 2010).

2.2*		Amendment No. 1 dated as of August 2, 2010 to the Agreement and Plan of Merger dated as of April 14, 2010 by and among Apache Corporation, ZMZ Acquisitions LLC and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.2 to Mariner’s Form 8-K filed on August 2, 2010).

2.3*		Purchase and Sale Agreement, dated as of December 9, 2009, by and between Edge Petroleum Corporation, Edge Petroleum Exploration Company, Miller Exploration Company, Edge Petroleum Operating Company, Inc., Edge Petroleum Production Company, Miller Oil Corporation, and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Mariner’s Form 8-K filed on January 5, 2010).

3.1*		Second Amended and Restated Certificate of Incorporation of Mariner Energy, Inc., as amended (incorporated by reference to Exhibit 3.1 to Mariner’s Registration Statement on Form S-8 (File No. 333-132800) filed on March 29, 2006).

3.2*		Certificate of Designations of Series A Junior Participating Preferred Stock of Mariner Energy, Inc. (incorporated by reference to Exhibit 3.1 to Mariner’s Form 8-K filed on October 14, 2008).

3.3*		Fourth Amended and Restated Bylaws of Mariner Energy, Inc. (incorporated by reference to Exhibit 3.2 to Mariner’s Registration Statement on Form S-4 (File No. 333-129096) filed on October 18, 2005).

4.1*		Indenture, dated as of June 10, 2009, among Mariner Energy, Inc., the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on June 16, 2009).

4.2*		First Supplemental Indenture, dated as of June 10, 2009, among Mariner Energy, Inc., the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.2 to Mariner’s Form 8-K filed on June 16, 2009).

4.3*		Indenture, dated as of April 30, 2007, among Mariner Energy, Inc., the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on May 1, 2007).

4.4*		Indenture, dated as of April 24, 2006, among Mariner Energy, Inc., the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 25, 2006).

4.5*		Exchange and Registration Rights Agreement, dated as of April 24, 2006, among Mariner Energy, Inc., the guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to Mariner’s Form 8-K filed on April 25, 2006).

4.6*		Rights Agreement, dated as of October 12, 2008, between Mariner Energy, Inc. and Continental Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on October 14, 2008).

4.7*		Amendment to Rights Agreement dated as of April 14, 2010, between Mariner Energy, Inc. and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 16, 2010).

4.8*		Amended and Restated Credit Agreement, dated as of March 2, 2006, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto from time to time, as Lenders, and Union Bank of California, N.A., as Administrative Agent and as Issuing Lender (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on March 3, 2006).

4.9*		Amendment No. 1 and Consent, dated as of April 7, 2006, among Mariner Energy, Inc. and Mariner


Number		Description

		Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 13, 2006).

4.10*		Amendment No. 2, dated as of October 13, 2006, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on October 18, 2006).

4.11*		Amendment No. 3 and Consent, dated as of April 23, 2007, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 24, 2007).

4.12*		Amendment No. 4, dated as of August 24, 2007, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on August 27, 2007).

4.13*		Amendment No. 5 and Agreement, dated as of January 31, 2008, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on February 5, 2008).

4.14*		Master Assignment, Agreement and Amendment No. 6, dated as of June 2, 2008, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on June 3, 2008).

4.15*		Amendment No. 7, dated as of December 12, 2008, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on December 15, 2008).

4.16*		Amendment No. 8 and Consent, dated as of March 24, 2009, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on March 27, 2009).

4.17*		Amendment No. 9, dated as of June 2, 2009, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on June 2, 2009).

4.18*		Amendment No. 10, dated as of August 25, 2009, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on August 27, 2009).

4.19*		Amendment No. 11, dated as of April 8, 2010, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank, N.A. (f/k/a Union Bank of California, N.A.), as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 8, 2010).

10.1*		Underwriting Agreement, dated June 4, 2009, among Credit Suisse Securities (USA) LLC, J.P. Morgan Securities Inc., and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Representatives of the several Underwriters named in Schedule A thereto, and Mariner Energy, Inc. (incorporated by reference to Exhibit 1.1 to Mariner’s Form 8-K filed on June 9, 2009).

10.2*		Underwriting Agreement, dated June 4, 2009, among Credit Suisse Securities (USA) LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC and Citigroup Global Markets Inc., as Representatives of the several Underwriters named in Schedule A thereto, and Mariner Energy, Inc., Mariner Energy Resources, Inc., Mariner Gulf of Mexico LLC, MC Beltway 8 LLC and Mariner LP LLC (incorporated by reference to Exhibit 1.2 to Mariner’s Form 8-K filed on June 9, 2009).


Number		Description

10.3*		Underwriting Agreement, dated April 25, 2007, among J.P. Morgan Securities Inc., as Representative of the several Underwriters listed in Schedule 1 thereto, Mariner Energy, Inc., Mariner Energy Resources, Inc., Mariner LP LLC, and Mariner Energy Texas LP (incorporated by reference to Exhibit 1.1 to Mariner’s Form 8-K filed on April 26, 2007).

10.4*		Purchase Agreement, dated as of April 19, 2006, among Mariner Energy, Inc., Mariner LP LLC, Mariner Energy Resources, Inc., Mariner Energy Texas LP and the initial purchasers party thereto (incorporated by reference to Exhibit 10.1 to Mariner’s Form 8-K filed on April 25, 2006).

10.5*		Mariner Energy, Inc. Third Amended and Restated Stock Incentive Plan, effective as of May 11, 2009 (incorporated by reference to Exhibit 10.1 to Mariner’s Form 8-K filed on May 12, 2009).

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Incorporated by reference as indicated.

In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Mariner Energy, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 6, 2010.


	Mariner Energy, Inc.
	By:	/s/ Scott D. Josey
		Scott D. Josey,
		Chairman of the Board, Chief Executive Officer and President


	By:	/s/ Jesus G. Melendrez
		Jesus G. Melendrez,
		Senior Vice President, Chief Commercial Officer, Acting Chief Financial Officer and Treasurer

Exhibit Index


Number		Description

2.1*		Agreement and Plan of Merger dated as of April 14, 2010 by and among Apache Corporation, ZMZ Acquisitions LLC and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Mariner’s Form 8-K filed on April 16, 2010).

2.2*		Amendment No. 1 dated as of August 2, 2010 to the Agreement and Plan of Merger dated as of April 14, 2010 by and among Apache Corporation, ZMZ Acquisitions LLC and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.2 to Mariner’s Form 8-K filed on August 2, 2010).

2.3*		Purchase and Sale Agreement, dated as of December 9, 2009, by and between Edge Petroleum Corporation, Edge Petroleum Exploration Company, Miller Exploration Company, Edge Petroleum Operating Company, Inc., Edge Petroleum Production Company, Miller Oil Corporation, and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Mariner’s Form 8-K filed on January 5, 2010).

3.1*		Second Amended and Restated Certificate of Incorporation of Mariner Energy, Inc., as amended (incorporated by reference to Exhibit 3.1 to Mariner’s Registration Statement on Form S-8 (File No. 333-132800) filed on March 29, 2006).

3.2*		Certificate of Designations of Series A Junior Participating Preferred Stock of Mariner Energy, Inc. (incorporated by reference to Exhibit 3.1 to Mariner’s Form 8-K filed on October 14, 2008).

3.3*		Fourth Amended and Restated Bylaws of Mariner Energy, Inc. (incorporated by reference to Exhibit 3.2 to Mariner’s Registration Statement on Form S-4 (File No. 333-129096) filed on October 18, 2005).

4.1*		Indenture, dated as of June 10, 2009, among Mariner Energy, Inc., the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on June 16, 2009).

4.2*		First Supplemental Indenture, dated as of June 10, 2009, among Mariner Energy, Inc., the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.2 to Mariner’s Form 8-K filed on June 16, 2009).

4.3*		Indenture, dated as of April 30, 2007, among Mariner Energy, Inc., the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on May 1, 2007).

4.4*		Indenture, dated as of April 24, 2006, among Mariner Energy, Inc., the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 25, 2006).

4.5*		Exchange and Registration Rights Agreement, dated as of April 24, 2006, among Mariner Energy, Inc., the guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to Mariner’s Form 8-K filed on April 25, 2006).

4.6*		Rights Agreement, dated as of October 12, 2008, between Mariner Energy, Inc. and Continental Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on October 14, 2008).

4.7*		Amendment to Rights Agreement dated as of April 14, 2010, between Mariner Energy, Inc. and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 16, 2010).

4.8*		Amended and Restated Credit Agreement, dated as of March 2, 2006, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto from time to time, as Lenders, and Union Bank of California, N.A., as Administrative Agent and as Issuing Lender (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on March 3, 2006).


Number		Description

4.9*		Amendment No. 1 and Consent, dated as of April 7, 2006, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 13, 2006).

4.10*		Amendment No. 2, dated as of October 13, 2006, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on October 18, 2006).

4.11*		Amendment No. 3 and Consent, dated as of April 23, 2007, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 24, 2007).

4.12*		Amendment No. 4, dated as of August 24, 2007, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on August 27, 2007).

4.13*		Amendment No. 5 and Agreement, dated as of January 31, 2008, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on February 5, 2008).

4.14*		Master Assignment, Agreement and Amendment No. 6, dated as of June 2, 2008, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on June 3, 2008).

4.15*		Amendment No. 7, dated as of December 12, 2008, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on December 15, 2008).

4.16*		Amendment No. 8 and Consent, dated as of March 24, 2009, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on March 27, 2009).

4.17*		Amendment No. 9, dated as of June 2, 2009, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on June 2, 2009).

4.18*		Amendment No. 10, dated as of August 25, 2009, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank of California, N.A., as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on August 27, 2009).

4.19*		Amendment No. 11, dated as of April 8, 2010, among Mariner Energy, Inc. and Mariner Energy Resources, Inc., as Borrowers, the Lenders party thereto, and Union Bank, N.A. (f/k/a Union Bank of California, N.A.), as Administrative Agent for such Lenders and as Issuing Lender for such Lenders (incorporated by reference to Exhibit 4.1 to Mariner’s Form 8-K filed on April 8, 2010).

10.1*		Underwriting Agreement, dated June 4, 2009, among Credit Suisse Securities (USA) LLC, J.P. Morgan Securities Inc., and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Representatives of the several Underwriters named in Schedule A thereto, and Mariner Energy, Inc. (incorporated by reference to Exhibit 1.1 to Mariner’s Form 8-K filed on June 9, 2009).

10.2*		Underwriting Agreement, dated June 4, 2009, among Credit Suisse Securities (USA) LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC and Citigroup Global Markets Inc., as Representatives of the several Underwriters named in Schedule A thereto, and Mariner Energy, Inc., Mariner Energy Resources, Inc., Mariner Gulf of Mexico LLC, MC Beltway 8 LLC and Mariner LP LLC (incorporated by reference to Exhibit 1.2 to Mariner’s Form 8-K filed on June 9, 2009).


Number		Description

10.3*		Underwriting Agreement, dated April 25, 2007, among J.P. Morgan Securities Inc., as Representative of the several Underwriters listed in Schedule 1 thereto, Mariner Energy, Inc., Mariner Energy Resources, Inc., Mariner LP LLC, and Mariner Energy Texas LP (incorporated by reference to Exhibit 1.1 to Mariner’s Form 8-K filed on April 26, 2007).

10.4*		Purchase Agreement, dated as of April 19, 2006, among Mariner Energy, Inc., Mariner LP LLC, Mariner Energy Resources, Inc., Mariner Energy Texas LP and the initial purchasers party thereto (incorporated by reference to Exhibit 10.1 to Mariner’s Form 8-K filed on April 25, 2006).

10.5*		Mariner Energy, Inc. Third Amended and Restated Stock Incentive Plan, effective as of May 11, 2009 (incorporated by reference to Exhibit 10.1 to Mariner’s Form 8-K filed on May 12, 2009).

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Incorporated by reference as indicated.

In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.

MARINER ENERGY INC 10-Q