Black Elk Energy Offshore Operations 10-Q 2012 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

or

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

For the transition period from            to             

Commission File Number: 333-174226

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

(Exact name of registrant as specified in its charter)

Texas	38-3769404
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
11451 Katy Freeway, Suite 500 Houston, Texas	77079
(Address of principal executive offices)	(Zip Code)

(281) 598-8600

Registrant’s telephone number, including area code

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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	¨	Accelerated filer	¨
Non-accelerated filer	x  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

As of May 7, 2012, there were 136.13 Class A Units, 10,934.585 Class B Units, 1,203.125 Class C Units and 30,000,000 Class D Units issued and outstanding.

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC’S

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2012

TABLE OF CONTENTS

		Page
Part I. Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011		1
	Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011		2
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011		3
	Notes to Consolidated Financial Statements		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		27
Item 4.	Controls and Procedures		31
Part II. Other Information
Item 1.	Legal Proceedings		32
Item 1A.	Risk Factors		32
Item 6.	Exhibits		33
Signatures			34
Exhibit Index			35

(i)

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	March 31,			December 31,
	2012			2011
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,194		$	17,260
Accounts receivable, net		48,688			52,439
Due from affiliates		23			23
Prepaid expenses and other		20,169			26,637
Derivative assets		939			4,216
TOTAL CURRENT ASSETS		87,013			100,575
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $126,231 and $114,056 at March 31, 2012 and December 31, 2011, respectively		234,847			238,702
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $1,067 and $870 at March 31, 2012 and December 31, 2011, respectively		2,163			2,245
OTHER ASSETS
Debt issue costs, net		8,031			8,726
Asset retirement obligation escrow receivable		20,348			20,348
Escrow for abandonment costs		180,440			172,153
Other assets		1,870			3,257
TOTAL OTHER ASSETS		210,689			204,484
TOTAL ASSETS	$	534,712		$	546,006
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	75,557		$	76,509
Asset retirement obligations		14,093			15,238
Current portion of debt and notes payable		—			4,154
TOTAL CURRENT LIABILITIES		89,650			95,901
LONG-TERM LIABILITIES
Gas imbalance payable		600			1,362
Derivative liabilities		5,565			2,116
Asset retirement obligations, net of current portion		280,231			273,448
Debt, net of current portion, net of unamortized discount of $1,058 and $1,113 at March 31, 2012 and December 31, 2011, respectively		171,942			172,887
TOTAL LONG-TERM LIABILITIES		458,338			449,813
TOTAL LIABILITIES		547,988			545,714
COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY (DEFICIT)		(13,276	)		292
TOTAL LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)	$	534,712		$	546,006

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

1

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands)

	Three Months Ended March 31,
	2012			2011
REVENUES:
Oil sales	$	60,518		$	37,412
Natural gas sales		14,316			15,107
Plant product sales and other revenue		6,604			3,308
Realized gain (loss) on derivative financial instruments		1,469			(336	)
Unrealized loss on derivative financial instruments		(6,726	)		(30,978	)
TOTAL REVENUES		76,181			24,513
OPERATING EXPENSES:
Lease operating		43,242			23,060
Production taxes		343			29
Workover		2,569			3,163
Exploration		897			—
Depreciation, depletion and amortization		12,371			7,994
General and administrative		6,434			4,525
Accretion		9,080			3,938
TOTAL OPERATING EXPENSES		74,936			42,709
INCOME (LOSS) FROM OPERATIONS		1,245			(18,196	)
OTHER INCOME (EXPENSE):
Interest income		281			6
Miscellaneous expense		(645	)		(136	)
Interest expense		(6,535	)		(5,793	)
TOTAL OTHER EXPENSE		(6,899	)		(5,923	)
NET LOSS		(5,654	)		(24,119	)
PREFERRED UNIT DIVIDENDS		1,800			—
NET LOSS ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	(7,454	)	$	(24,119	)

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

2

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Three Months Ended March 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(5,654	)	$	(24,119	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization		12,371			7,994
Accretion of asset retirement obligations		9,080			3,938
Amortization of debt issue costs		1,015			544
Amortization of debt discount		55			48
Unrealized loss on derivative instruments		6,726			30,978
Changes in operating assets and liabilities:
Accounts receivable		3,751			(7,065	)
Due from affiliates, net		—			(85	)
Prepaid expenses and other assets		6,468			112
Accounts payable and accrued liabilities		(2,751	)		(3,560	)
Gas imbalance		650			761
Settlement of asset retirement obligations		(3,442	)		(1,014	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		28,269			8,532
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(5,487	)		(5,526	)
Acquisition of oil and gas properties		(2,833	)		2,219
Additions to property and equipment		(114	)		(291	)
Deposits		(25	)		(50	)
Restricted cash		—			(2,750	)
Escrow payments		(8,287	)		(856	)
NET CASH USED IN INVESTING ACTIVITIES		(16,746	)		(7,254	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on short term notes		(4,154	)		(2,033	)
Borrowing on bank debt		53,500			—
Payments on bank debt		(54,500	)		—
Debt issuance costs		(321	)		(698	)
Distributions to members		(6,114	)		(1,902	)
NET CASH USED IN FINANCING ACTIVITIES		(11,589	)		(4,633	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(66	)		(3,355	)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD		17,260			18,879
CASH AND CASH EQUIVALENTS - END OF PERIOD	$	17,194		$	15,524
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	376		$	17
NONCASH INVESTING AND FINANCING ACTIVITIES:
Increase in oil and gas properties for asset retirement obligations	$	—		$	10,037
Paid-in-kind dividends on preferred equity and accrued distributions to members	$	1,800		$	—

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

3

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(Unaudited)

NOTE 1—ORGANIZATION AND BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations: Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries (collectively, “Black Elk”, “we”, “our” or “us”) is a Houston-based oil and natural gas company engaged in the exploration, development, production and exploitation of oil and natural gas properties. We were formed on January 29, 2008 for the purpose of acquiring oil and natural gas producing properties within the Outer Continental Shelf of the United States in the Gulf of Mexico.

Basis of Presentation:The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation of our interim and prior period results have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for any other interim period or for the entire fiscal year. For further information, refer to the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”).

Principles of Consolidation: The consolidated financial statements include the accounts of Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries, Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corp. All material intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in Preparation of Financial Statements: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. We analyze our estimates based on historical experience, current factors and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates.

We account for business combinations using the purchase method, in accordance with authoritative guidance from the Financial Accounting Standards Board (“FASB”). We use estimates to record the fair value of assets acquired and liabilities assumed.

Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the impairment test, are based on assumptions that have inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

Recent Accounting Pronouncements:In May 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance which amends fair value measurements and disclosures. The amended guidance clarifies many requirements in U.S. generally accepted accounting principles (“GAAP”) for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on our consolidated financial statements.

In December 2011, the FASB issued accounting guidance which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards (“IFRS”) related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.

4

NOTE 2—OIL AND GAS PROPERTIES

We account for oil and natural gas properties using the successful efforts method of accounting. Under this method of accounting, costs relating to the acquisition of and development of proved properties are capitalized when incurred. The costs of development wells are capitalized, whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and natural gas producing activities are capitalized. Production costs are charged to expense as those costs are incurred to operate and maintain our wells and related equipment and facilities.

Depreciation, depletion and amortization (“DD&A”) of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by our independent petroleum engineer, and are subject to future revisions based on availability of additional information. DD&A is calculated each quarter based upon the latest estimated reserves data available. Asset retirement costs are recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural gas properties by field to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices. For the three months ended March 31, 2012 and 2011, we recorded no impairment charges.

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

The following table reflects capitalized costs related to our oil and gas properties:

	March 31,			December 31,
	2012			2011
	(in thousands)
Proved properties	$	361,078		$	352,758
Unproved properties, not subject to depletion		—			—
Total capitalized costs		361,078			352,758
Accumulated depreciation, depletion, amortization and impairment		(126,231	)		(114,056	)
Oil and gas properties, net	$	234,847		$	238,702

5

The following table describes the changes to our asset retirement obligations:

	(in thousands)
Balance at December 31, 2010	$	122,242
Liabilities incurred		147,442
Liabilities settled		(8,408	)
Accretion expense		27,410
Balance at December 31, 2011		288,686
Liabilities incurred		—
Liabilities settled		(3,442	)
Accretion expense		9,080
Balance at March 31, 2012	$	294,324

NOTE 3—ACQUISITIONS

Merit Energy Corp.

On May 31, 2011, we purchased certain properties from Merit Energy Corp. (the “Merit Acquisition”). We acquired interests in various properties across approximately 250,126 gross (127,894 net) acres in the Gulf of Mexico for a purchase price of $39 million and the assumption of $121.2 million in asset retirement obligations related to plugging and abandonment (“P&A”) obligations associated with acquired properties, subject to customary adjustments for a transaction of that type.

At closing, we were required to establish an escrow account to secure the performance of our P&A obligations and other indemnity obligations with respect to P&A and/or decommissioning of the acquired wells and facilities. We paid $33 million in surety bonds at closing and are required to, over time, deposit in the escrow account an aggregate principal amount equal to $60 million, which is to be paid in 30 equal monthly installments payable on the first day of each month commencing on June 1, 2011.

Prior to closing, we paid the sellers an earnest money deposit of $6 million. The earnest money was applied against the purchase price. We financed the remainder of the purchase price and related expenditures with existing available cash and approximately $35 million in borrowings under our Credit Facility (as defined in Note 6), together with equity financing from our members.

In order to consummate this acquisition, we commenced a consent solicitation to amend the maximum capital expenditures provision of the Indenture governing our outstanding 13.75% Senior Secured Notes due 2015 (the “Notes”). On May 31, 2011, we acquired the consents to (1) increase the amount of capital expenditures permitted by us on an annual basis, (2) enable us to obtain financial support from our majority equity holder in the amount of a $30 million investment, and (3) obligate us to make an offer to repurchase the Notes semi-annually at an offer price of 103% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest if we meet certain defined financial tests and as permitted by our credit facilities.

The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 31, 2011:

	(in thousands)
Oil and gas properties	$	152,782
Gas imbalances - receivable		1,487
Less:
Gas imbalances - payable		314
Asset retirement obligations		121,164
Cash paid	$	32,791

The preliminary fair values of evaluated oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (1) oil and natural gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Significant inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

6

Pro Forma Information

The following unaudited pro forma, condensed financial information for the three months ended March 31, 2011 was derived from our historical financial statements giving effect to the Merit Acquisition as if it had occurred on January 1, 2011. The unaudited pro forma financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if we had completed the acquisition as of January 1, 2011 or the results that will be attained in the future.

	Three Months Ended
	March 31, 2011
	(in thousands)
Revenues	$	55,967
Earnings(1)		(25,884	)

(1) Earnings include revenues less lease operating expenses, exploration, marketing and transportation, workover, DD&A, accretion, and general and administrative expenses.

Maritech Acquisition

On February 23, 2011, we acquired properties in the Gulf of Mexico from Maritech Resources Incorporated (the “Maritech Acquisition”), primarily located within federal offshore waters for a purchase price of $6 million before normal purchase price adjustments and the assumption of $12.8 million in asset retirement obligations related to P&A obligations associated with acquired properties. During the second quarter of 2011, we recorded an additional amount of P&A obligations of $13.0 million of which Tetra Technologies, Inc., the parent of Maritech Resources Incorporated, has guaranteed escrow accounts for certain fields in the amount of $20.3 million, which will not be refunded until the entire field is plugged and abandoned. The purchase included eight fields and adds interest in an additional 108 gross wells and an estimated 46 thousand gross acres to our portfolio. Upon closing on the Maritech Acquisition in February 2011, we entered into an irrevocable letter of credit (“ILOC”) with Capital One, N.A., in the amount of $2.8 million related to P&A obligations for interests in properties acquired. In May 2011, a separate deposit account was created for collateral related to the ILOC, including an increase of $0.1 million based on evaluation by the surety company, and funds related to this ILOC were moved from restricted cash to escrow for abandonment costs.

7

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on February 23, 2011:

	(in thousands)
Oil and gas properties	$	2,377
Escrow		20,348
Less:
Gas imbalances		14
Asset retirement obligations		25,726
Cash received	$	(3,015	)

The fair values of evaluated oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (1) oil and natural gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Significant inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

NOTE 4—DERIVATIVE INSTRUMENTS

In accordance with authoritative guidance on derivatives and hedging, all derivative instruments are measured at each period end and are recorded on the consolidated balance sheets at fair value. Derivative contracts that are designated as part of a qualifying cash flow hedge, per the accounting guidance, are granted hedge accounting thereby allowing us to treat the effective changes in the fair value of the derivative instrument in accumulated other comprehensive income, while recording the ineffective portion as an adjustment to unrealized gain (loss). Derivative contracts that are not designated as part of a valid qualifying hedge or fail to meet the requirements of the pronouncement as a highly effective hedge, are treated by recording the changes in the fair value from period to period, through earnings. The amounts paid or received upon each monthly settlement, are recorded as realized derivative gain (loss), as appropriate.

We enter into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of oil and natural gas. We use financially settled crude oil and natural gas swaps. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. We elected not to designate any of our derivative contracts as qualifying hedges for financial reporting purposes, therefore all of the derivative instruments are categorized as standalone derivatives and are being marked-to-market with “Unrealized loss on derivative financial instruments” recorded in the consolidated statements of operations.

8

At March 31, 2012, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss)):

	Crude Oil										Natural Gas								Total
Period	Volume (Bbls)		Contract Price ($/Bbl)		Asset (Liability)			Fair Value Gain (Loss)			Volume (MMBtu)		Contract Price ($/ MMBtu)		Asset (Liability)		Fair Value Gain (Loss)		Asset (Liability)			Fair Value Gain (Loss)
Swaps:					(in thousands)										(in thousands)				(in thousands)
4/12 - 10/12		23,000	$	96.90	$	(1,155	)	$	(1,155	)		227,000	$	4.60	$	3,452	$	3,452	$	2,297		$	2,297
11/12 - 11/12		22,080		96.90		(172	)		(172	)		227,000		4.60		375		375		203			203
12/12 - 12/12		23,000		96.90		(178	)		(178	)		227,000		4.60		295		295		117			117
1/13 - 10/13		27,750		96.90		(1,872	)		(1,872	)		104,000		4.60		1,077		1,077		(795	)		(795	)
11/13 - 11/13		26,800		96.90		(126	)		(126	)		104,000		4.60		80		80		(46	)		(46	)
12/13 - 12/13		27,750		96.90		(116	)		(116	)		104,000		4.60		61		61		(55	)		(55	)
1/14 - 2/14		19,000		96.90		(151	)		(151	)		82,000		4.60		81		81		(70	)		(70	)
4/12 - 12/12		17,050		81.22		(3,427	)		(3,427	)		—		—		—		—		(3,427	)		(3,427	)
4/12 - 12/12		1,900		81.14		(383	)		(383	)		112,000		5.00		2,425		2,425		2,042			2,042
4/12 - 7/12		—		—		—			—			5,250		5.89		75		75		75			75
4/12 - 7/12		200		83.50		(16	)		(16	)		53,000		5.70		722		722		706			706
8/12 - 12/12		—		—		—			—			53,000		5.70		746		746		746			746
4/12 - 12/12		27,500		85.90		(4,417	)		(4,417	)		26,838		5.89		787		787		(3,630	)		(3,630	)
4/12 - 5/12		—		—		—			—			318,958		4.94		1,765		1,765		1,765			1,765
6/12 - 6/12		—		—		—			—			303,880		4.94		798		798		798			798
4/12 - 6/12		22,125		100.80		(188	)		(188	)		—		—		—		—		(188	)		(188	)
7/12 - 7/12		12,048		100.80		(43	)		(43	)		106,638		4.94		263		263		220			220
8/12 - 8/12		8,296		100.80		(31	)		(31	)		90,586		4.94		215		215		184			184
9/12 - 9/12		3,998		100.80		(15	)		(15	)		56,141		4.94		130		130		115			115
10/12- 10/12		1,884		100.80		(7	)		(7	)		41,462		4.94		92		92		85			85
11/12 - 11/12		—		—		—			—			2,951		4.94		6		6		6			6
12/12 - 12/12		15,140		100.80		(63	)		(63	)		106,375		4.94		172		172		109			109
1/13 - 6/13		15,542		100.80		(317	)		(317	)		200,669		4.94		1,701		1,701		1,384			1,384
7/13 - 7/13		7,132		100.80		(16	)		(16	)		148,788		4.94		188		188		172			172
8/13 - 8/13		5,980		100.80		(11	)		(11	)		139,212		4.94		171		171		160			160
9/13 - 9/13		3,897		100.80		(6	)		(6	)		116,125		4.94		141		141		135			135
10/13 - 10/13		3,259		100.80		(5	)		(5	)		91,166		4.94		107		107		102			102
11/13 - 11/13		—		—		—			—			64,926		4.94		69		69		69			69
12/13 - 12/13		10,042		100.80		(7	)		(7	)		119,462		4.94		104		104		97			97
1/14 - 5/14		10,083		100.80		23			23			129,960		4.94		534		534		557			557
6/14 - 6/14		—		—		—			—			129,960		4.94		108		108		108			108
1/13 - 12/13		19,750		85.90		(3,968	)		(3,968	)		47,000		5.00		748		748		(3,220	)		(3,220	)
1/14 - 12/14		15,000		65.00		(5,765	)		(5,765	)		—		—		—		—		(5,765	)		(5,765	)
4/12 - 4/12		51,730		102.40		(40	)		(40	)		—		—		—		—		(40	)		(40	)
5/12 - 5/12		45,340		102.40		(57	)		(57	)		—		—		—		—		(57	)		(57	)
6/12 - 6/12		36,000		102.40		(62	)		(62	)		—		—		—		—		(62	)		(62	)
7/12 - 7/12		21,110		102.40		(43	)		(43	)		—		—		—		—		(43	)		(43	)
8/12 - 8/12		22,890		102.40		(51	)		(51	)		—		—		—		—		(51	)		(51	)
9/12 - 9/12		20,930		102.40		(50	)		(50	)		—		—		—		—		(50	)		(50	)
10/12 - 10/12		23,170		102.40		(59	)		(59	)		—		—		—		—		(59	)		(59	)
11/12 - 11/12		19,290		102.40		(51	)		(51	)		—		—		—		—		(51	)		(51	)
12/12 - 12/12		24,860		102.40		(67	)		(67	)		—		—		—		—		(67	)		(67	)
1/13 - 1/13		43,510		102.40		(114	)		(114	)		—		—		—		—		(114	)		(114	)
2/13 - 2/13		29,030		102.40		(71	)		(71	)		—		—		—		—		(71	)		(71	)
3/13 - 3/13		35,760		102.40		(78	)		(78	)		—		—		—		—		(78	)		(78	)
4/13 - 4/13		28,740		102.40		(54	)		(54	)		—		—		—		—		(54	)		(54	)
5/13 - 5/13		28,540		102.40		(44	)		(44	)		—		—		—		—		(44	)		(44	)
6/13 - 6/13		22,800		102.40		(27	)		(27	)		—		—		—		—		(27	)		(27	)
7/13 - 7/13		14,700		102.40		(12	)		(12	)		—		—		—		—		(12	)		(12	)
8/13 - 8/13		14,080		102.40		(8	)		(8	)		—		—		—		—		(8	)		(8	)
9/13 - 9/13		12,390		102.40		(4	)		(4	)		—		—		—		—		(4	)		(4	)
10/13 - 10/13		13,710		102.40		(1	)		(1	)		—		—		—		—		(1	)		(1	)
11/13 - 11/13		14,320		102.40		4			4			—		—		—		—		4			4
12/13 - 12/13		19,310		102.40		13			13			—		—		—		—		13			13
1/14 - 1/14		30,600		102.40		32			32			—		—		—		—		32			32
2/14 - 2/14		22,010		102.40		31			31			—		—		—		—		31			31
3/14 - 3/14		45,910		102.40		80			80			—		—		—		—		80			80
4/14 - 4/14		41,850		102.40		86			86			—		—		—		—		86			86
5/14 - 5/14		42,530		102.40		101			101			—		—		—		—		101			101
6/14 - 6/14		48,860		102.40		131			131			—		—		—		—		131			131
7/14 - 7/14		36,680		102.40		109			109			—		—		—		—		109			109
8/14 - 8/14		35,360		102.40		114			114			—		—		—		—		114			114
9/14 - 9/14		32,290		102.40		111			111			—		—		—		—		111			111
10/14 - 10/14		32,920		102.40		119			119			—		—		—		—		119			119
11/14 - 11/14		30,000		102.40		113			113			—		—		—		—		113			113
12/14 - 12/14		41,880		102.40		167			167			—		—		—		—		167			167
					$	(22,114	)	$	(22,114	)					$	17,488	$	17,488	$	(4,626	)	$	(4,626	)

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The following table quantifies the fair values, on a gross basis, of all of our derivative contracts and identifies the balance sheet locations as of March 31, 2012 (in thousands):

	Asset Derivatives				Liability Derivatives
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location		Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts		Derivative financial instruments			Derivative financial instruments
		Current	$	13,755	Current	$	(12,816	)
		Non-current		4,967	Non-current		(10,532	)
Total derivative instruments			$	18,722		$	(23,348	)

NOTE 5—FAIR VALUE MEASUREMENTS

Accounting guidance for fair value measurements clarifies the definition of fair value, prescribes methods for measuring fair value, establishes a fair value hierarchy based on the inputs used to measure fair value, and expands disclosures about fair value measurements. The three-tier fair value hierarchy, which prioritizes the inputs used in the valuation methodologies, is:

• Level 1—Valuations based on quoted prices for identical assets and liabilities in active markets.

• Level 2—Valuations based on observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data.

• Level 3—Valuations based on unobservable inputs reflecting our own assumptions, consistent with reasonably available assumptions made by other market participants. These valuations require significant judgment.

As required by accounting guidance for fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents information about our assets and liabilities measured at fair value on a recurring basis as of March 31, 2012, and indicates the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands):

	Fair Value Measurements at March 31, 2012 Using Fair Value Hierarchy
	Fair Value as of March 31, 2012			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	18,722		$	—	$	18,722		$	—
	$	18,722		$	—	$	18,722		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(23,348	)	$	—	$	(23,348	)	$	—
	$	(23,348	)	$	—	$	(23,348	)	$	—

At March 31, 2012, management estimates that the derivative contracts had a fair value of $(4.6) million. We estimated the fair value of derivative instruments using internally-developed models that use as their basis, readily observable market parameters.

The determination of the fair values above incorporates various factors required under accounting guidance for fair value measurements. These factors include not only the impact of our nonperformance risk but also the credit standing of the counterparties involved in our derivative contracts.

As of March 31, 2012, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities approximated their carrying value due to their short-term nature. The estimated fair value of our debt was primarily based on quoted market prices as well as prices for similar debt based on recent market transactions. The fair value of debt at March 31, 2012 was $173.0 million.

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NOTE 6—DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:

	March 31, 2012		December 31, 2011
	(in thousands)
Senior Secured Revolving Credit Facility	$	23,000	$	24,000
13.75% Senior Secured Notes, net of discount		148,942		148,887
First Insurance - note payable		—		4,154
Total debt		171,942		177,041
Less: current portion		—		(4,154	)
Total long-term debt	$	171,942	$	172,887

Senior Secured Revolving Credit Facility

On December 24, 2010, we entered into an aggregate $110 million credit facility (“the Credit Facility”) comprised of a senior secured revolving credit facility of up to $35 million and a $75 million secured letter of credit to be used exclusively for the issuance of letters of credit in support of our future P&A liabilities relating to our oil and natural gas properties. The Credit Facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 2.75% to 3.5%, or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The applicable margin is computed based on the grid when the borrowing based utilization percentage is at its highest level. On May 31, 2011, we entered into an amendment to the Credit Facility, which increased the revolving credit facility available thereunder from $35 million to $70 million and the secured letter of credit from $75 million to $125 million, based primarily on the reserves provided by the Merit Acquisition. At March 31, 2012, we had an aggregate amount of $131.8 million of indebtedness outstanding under our Credit Facility, $108.8 million that was drawn as a letter of credit in support of our P&A obligations and $23.0 million of borrowings under the revolver. We currently have $63.2 million available for additional borrowing.

A commitment of 0.5% per annum is computed based on the unused borrowing base and paid quarterly. For the three months ended March 31, 2012, we recognized $33,292 in commitment fees, which have been included in “Interest expense” on the consolidated statements of operations. A letter of credit fee is computed based on the same applicable margin used to determine the interest rate to Eurodollar loans times the stated face amount of each letter of credit.

The Credit Facility is secured by mortgages on at least 80% of the total value of the proved oil and gas reserves. The borrowing base is re-determined semi-annually on or around April 1^st and October 1^st of each year. We and the administrative agent may each elect to cause the borrowing base to be re-determined one time between scheduled semi-annual redetermination periods.

The Credit Facility requires us and our subsidiaries to maintain certain financial covenants. Specifically, we may not permit, in each case as calculated as of the end of each fiscal quarter, our total leverage ratio to be more than 2.5 to 1.0, our interest rate coverage ratio to be less than 3.0 to 1.0, or our current ratio (in each case as defined in our revolving Credit Facility) to be less than 1.0 to 1.0. In addition, we and our subsidiaries are subject to various covenants, including those limiting distributions and other payments, making certain investments, margin, consolidating, modifying certain agreements, transactions with affiliates, the incurrence of debt, changes in control, asset sales, liens on properties, sale leaseback transactions, entering into certain leases, the allowance of gas imbalances, take or pay or other prepayments. As of March 31, 2012, we were in compliance with all covenants.

13.75% Senior Secured Notes

On November 23, 2010, we issued $150 million face value of 13.75% Notes discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under our revolving credit facility, to fund Bureau of Ocean Energy Management, Regulation and Enforcement collateral requirements, and to prefund our escrow accounts. We pay interest on the Notes semi-annually, on June 1 and December 1 of each year, in arrears which commenced on June 1, 2011. The Notes will mature on December 1, 2015, of which all principal then outstanding will be due. As of March 31, 2012, the recorded value of the Notes was $148.9 million, which includes the unamortized discount of $1.1 million. We incurred underwriting and debt issue costs of $7.2 million, which have been capitalized and will be amortized over the life of the Notes.

The Notes are secured by a security interest in the issuers’ and the guarantors’ assets (excluding the W&T Escrow Accounts (as defined below)) to the extent they constitute collateral under our existing unused Credit Facility and derivative contract obligations. The liens securing the Notes will be subordinated and junior to any first lien indebtedness, including our derivative contracts obligations and Credit Facility.

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We have the right to redeem the Notes under various circumstances. If we experience a change of control, the holders of the Notes may require us to repurchase the Notes at 101% of the principal amount thereof, plus accrued unpaid interest. In addition, within 90 days after December 2011 for which excess cash flow, as defined, exceeds $5.0 million to the extent permitted by our Notes, we will offer to purchase the Notes at an offer price equal to 100% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest. We also have an optional redemption in which we may redeem up to 35% of the aggregate principal amount of the Notes at a price equal to 110.0% of the principal amount, plus accrued interest and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings until December 1, 2013. From December 1, 2013 until December 1, 2014, we may redeem some or all of the Notes at an initial redemption price equal to par value plus one-half the coupon which equals 106.875% plus accrued and unpaid interest to the date of the redemption. On or after December 1, 2014, we may redeem some or all of the Notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption.

On May 23, 2011, we commenced a Consent Solicitation that was completed on May 31, 2011 and resulted in our entry into the First Supplemental Indenture. We paid a consent solicitation fee of $4.5 million. The First Supplemental Indenture amended the Indenture, among other things, to: (1) increase the amount of capital expenditures permitted to be made by us on an annual basis, (2) enable us to obtain financial support from our majority equity holder by way of a $30 million investment in Sponsor Preferred Stock, which can be repaid over time, and (3) obligate us to make an offer to repurchase the Notes semi-annually at an offer price equal to 103% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest to the extent we meet certain defined financial tests and as permitted by our credit facilities.

The Notes require us to maintain certain financial covenants. Specifically, we may not permit our SEC PV-10 to consolidated leverage to be less than 1.4 to 1.0 as of the last day of each fiscal year. In addition, we and our subsidiaries are subject to various covenants, including restricted payments, incurrence of indebtedness and issuance of preferred stock, liens, dividends and other payments, merger, consolidation or sale of assets, transactions with affiliates, designation of restricted and unrestricted subsidiaries, and a maximum limit for capital expenditures. Our capital expenditure requirement was amended in conjunction with the Consent Solicitation on May 31, 2011 to a maximum limit of $60 million for the fiscal year ending December 31, 2011 and 30% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expense for any year thereafter. As of March 31, 2012, we were in compliance with our covenants under the Indenture.

We were obligated to file a registration statement with the SEC to exchange these Notes for new publicly tradable notes having substantially identical terms within 180 days of the November 23, 2010 issue date and use reasonable efforts to have the registration statement declared effective within 270 days after the issue date. In May 2011, we prepared a Registration Statement on Form S-4, which was filed with the SEC. We amended the Form S-4 in June 2011 and it was declared effective by the SEC on July 18, 2011. The exchange offer was commenced on or about July 20, 2011 and expired on August 19, 2011, with all of the outstanding Notes being tendered.

The amounts of required principal payments based on our outstanding debt amounts as of March 31, 2012, were as follows:

Period Ending March 31,	(in thousands)
2013	$	—
2014		23,000
2015		—
2016		150,000
2017		—
		173,000
Unamortized discount on 13.75% Senior Secured Notes		(1,058	)
Total debt	$	171,942

NOTE 7—PREFERRED EQUITY CONTRIBUTION

On May 31, 2011, Platinum Partners Value Arbitrage Fund L.P., and/or its affiliates (collectively “Platinum”) entered into a contribution agreement with us, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million units of our Class D Preferred Units (the “Class D Units”), having such rights, preferences and privileges as set forth in our Second Amendment and Restated Operating Agreement, as amended. The Class D Units were issued in the name of Platinum’s wholly owned subsidiary, PPCA Black Elk (Equity) LLC.

The newly issued Class D Units are non-voting units having an aggregate liquidation preference of $30 million and accruing dividends payable in kind at a rate per annum of 24%. As of March 31, 2012 and December 31, 2011, we have accrued dividends in the amounts of $6.0 million and $4.2 million, respectively, that are included in “Members’ Equity (Deficit)” on the consolidated balance sheets.

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NOTE 8—COMMITMENTS AND CONTINGENCIES

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessment of the property would be necessary to adequately determine remediation costs, if any. Management does not consider the amounts that would result from any environmental site assessments to be significant to the consolidated financial position or results of our operations. Accordingly, no provision for potential remediation costs is reflected in the accompanying consolidated financial statements.

We are subject to claims and lawsuits that arise primarily in the ordinary course of business. It is the opinion of management that the disposition or ultimate resolution of such claims and lawsuits will not have a material adverse effect on our consolidated financial position or results of operations.

We lease office space and certain equipment under non-cancelable operating lease agreements that expire on various dates through 2020. On April 29, 2011, we entered into an amendment to the current office lease agreement for expansion to an additional floor with rental space of approximately 11,000 square feet. The move occurred in June 2011. The termination date of the agreement is December 31, 2020.

Approximate future minimum lease payments for operating leases at March 31, 2012 were as follows:

Period Ending March 31,	(in thousands)
2013	$	2,737
2014		2,402
2015		2,104
2016		1,909
2017		1,703
Thereafter		5,743
	$	16,598

Pursuant to the purchase agreement from W&T Offshore, Inc. (the “W&T Acquisition”), we are required to fund two escrow accounts (the “W&T Escrow Accounts”), relating to the operating and non-operating properties that were acquired, respectively, in maximum aggregate principal amount of $63.8 million ($32.6 million operated and $31.2 million non-operated) for future P&A costs that may be incurred on such properties. As of November 2010, we fully funded the operating escrow account in the amount of $32.6 million and the payment schedule for the Non-Operated Properties Escrow Account was amended and commenced on December 2011. As of March 31, 2012, we have funded $10.3 million into the non-operating escrow account, leaving $20.9 million to be funded through May 1, 2017.

The obligations under the W&T Escrow Accounts are fully guaranteed by an affiliate of Platinum. W&T Offshore Inc. (“W&T”) has a first lien on the entirety of the W&T Escrow Accounts, and BP Corporation North America Inc. and Platinum are pari passu second lien holders. Once P&A obligations with respect to the interest in properties acquired from the W&T Acquisition have been fully satisfied, the lien on the W&T Escrow Accounts will be automatically extinguished. W&T also has a second priority lien with respect to the interest in properties acquired from the W&T Acquisition (with Platinum and BNP Paribas sharing a first priority lien), which lien will be released once the W&T Escrow Accounts have been fully funded.

Pursuant to the purchase agreement for the Maritech Acquisition, we are required to fund an escrow account (the “Maritech Escrow Account”), relating to the properties that were acquired, the principal amount of $13.1 million for future P&A costs that may be incurred on such properties. As of March 31, 2012, we have funded $4.7 million, leaving $8.4 million to be funded through February 2014.

In regards to the Merit Acquisition, we are required to establish an escrow account to secure the performance of our P&A obligations and other indemnity obligations with respect to P&A and/or decommissioning of the acquired wells and facilities. We paid $33 million in surety bonds at closing and are required to, over time, deposit in the escrow account an aggregate principal amount equal to $60 million, which is to be paid in 30 equal monthly installments payable on the first day of each month commencing on June 1, 2011. As of March 31, 2012, we have funded $20.0 million, leaving $40.0 million to be funded through November 2013.

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NOTE 9—RELATED PARTY TRANSACTIONS

We paid for certain operating and general and administration expenses on behalf of Black Elk Energy, LLC, the parent company of Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corp. At March 31, 2012 and December 31, 2011, we had receivables from Black Elk Energy, LLC in the amount of $22,430 and $22,430, respectively.

For the three months ended March 31, 2012, we paid $0.1 million to Up and Running Solutions, LLC, for IT consulting services. Up and Running Solutions, LLC is owned by the wife of an employee, David Cantu (a member of our management team). At March 31, 2012 and December 31, 2011, the outstanding amount due to Up and Running Solutions, LLC was ($26,875) and $0.1 million, respectively.

During 2011, we entered into a contribution agreement with Platinum. See Note 7.

In October 2010, Freedom Logistics LLC (“Freedom”) was formed by Platinum, our majority equity holder, and Freedom HHC Management, LLC, the members of which are Messers. John Hoffman (our President and Chief Executive Officer), James Hagemeier (our Chief Financial Officer) and David Cantu (a member of our management), to hold two helicopters. We guaranteed the purchase of the two helicopters by Freedom in the aggregate principal amount of $3.2 million. As of March 31, 2012 and December 31, 2011, the balance of the loan was $2.9 and $3.0 million, respectively.

In April 2011, Freedom Well Services (“FWS”) was formed by us, certain members of our management, Freedom Well Services Employee Incentive, LLC and Platinum, our majority equity holder, to provide well P&A services, slick line and electronic line operations and platform decommissioning and removal of consulting services. Although we did not contribute capital for start-up costs, we funded the purchase of equipment as a prepayment for services rendered with the expectation that the prepayment will be reimbursed as the business continues to grow and generate cash flows. As of March 31, 2012 and December 31, 2011, we have advanced $7.6 million and $6.6 million, respectively, to FWS which is included in “Prepaid expenses and other” on our balance sheet.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Form 10-Q”) contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

• Financial data, including production, costs, revenues and operating income;

• Future financial and operating performance and results;

• Business strategy and budgets;

• Market prices;

• Expected plugging and abandonment obligations and other expected asset retirement obligations;

• Technology;

• Financial strategy;

• Amount, nature and timing of capital expenditures;

• Drilling of wells and the anticipated results thereof;

• Oil and natural gas reserves;

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

• Competition and government regulations;

• Operating costs and other expenses;

• Cash flow and anticipated liquidity;

• Prospect development;

• Property acquisitions and sales; and

• Plans, forecasts, objectives, expectations and intentions.

These forward-looking statements are based on our current expectations and assumptions about future events and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisition. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are described in “Item 1A. Risk Factors” in this Form 10-Q and in our 2011 Form 10-K.

These factors include risks summarized below

• Low and/or declining prices for oil and natural gas;

• Oil and natural gas price volatility;

• Risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes;

• Ability to raise additional capital to fund future capital expenditures;

• Cash flow and liquidity;

15

• Ability to find, acquire, market, develop and produce new oil and natural gas properties;

• Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;

• Geological concentration of our reserves;

• Discovery, acquisition, development and replacement of oil and natural gas reserves;

• Operating hazards attendant to the oil and natural gas business;

• Down hole drilling and completion risks that are generally not recoverable from third parties or insurance;

• Potential mechanical failure or underperformance of significant wells or pipeline mishaps;

• Potential increases in plugging and abandonment and other asset retirement costs as a result of new regulations;

• Weather conditions;

• Availability and cost of material and equipment;

• Delays in anticipated start-up dates;

• Actions or inactions of third-party operators of our properties;

• Ability to find and retain skilled personnel;

• Strength and financial resources of competitors;

• Potential defects in title to our properties;

• Federal and state regulatory developments and approvals, including the adoption of new regulatory requirements;

• Losses possible from future litigation;

• Environmental risks;

• Changes in interest rates;

• Developments in oil and natural gas-producing countries;

• Events similar to those of September 11, 2001, Hurricanes Katrina, Rita, Gustav and Ike and the Deepwater Horizon explosion; and

• Worldwide political and economic conditions.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this Form 10-Q. We undertake no responsibility to publicly release the results of any revisions of our forward-looking statements after the date they are made.

Should one or more of the risks or uncertainties described in “Item 1A. Risk Factors” in our 2011 Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statement.

All forward-looking statements, express or implied, included in this Form 10-Q are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as required by law, we undertake no obligations to update, revise or release any revisions to any forward-looking statements to reflect events or circumstances occurring after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factors, or combination of factors, may cause actual results to be materially different from those contained in any forward-looking statement.

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

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Form 10-Q. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are an oil and gas company engaged in the acquisition, exploitation, development and production of oil and natural gas properties. We seek to acquire and exploit properties with proved developed reserves, proved developed non-producing reserves and proved undeveloped reserves. Our strategy is to acquire and economically maximize properties that are currently producing or have the potential to produce given additional attention and capital resources. We are engaged in a continual effort to monitor and reduce operating expenses by finding opportunities to safely increase efficiencies related to staffing, transportation and operational procedures. Moreover, our ability to accurately estimate and manage plugging and abandonment costs associated with potential acquisitions increases the likelihood of achieving our target returns on investment. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation. As of March 31, 2012, we held an aggregate net interest in approximately 624,500 gross (285,100 net) acres under lease and had an interest in 1,214 gross wells, 359 of which are producing.

We have financed our acquisitions to date through a combination of cash flows provided by operating activities, borrowings under lines of credit and Notes, and capital contributions from our members. Our use of capital for acquisitions, exploitation and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. In addition, our willingness to acquire non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.

Black Elk Energy, LLC was incorporated on November 20, 2007 to act as a holding company for its then operating subsidiaries, Black Elk Energy Offshore Operations, LLC and Black Elk Energy Land Operations, LLC. Black Elk Energy, LLC subsequently assigned its interests in Black Elk Energy Land Operations, LLC to Black Elk Energy Offshore Operations, LLC. Black Elk Energy Offshore Operations, LLC currently has two wholly-owned domestic subsidiaries: Black Elk Energy Land Operations, LLC, which is a guarantor under our Indenture, and Black Elk Energy Finance Corp., which is the co-issuer of the Notes. Neither Black Elk Energy Land Operations, LLC nor Black Elk Energy Finance Corp have any material assets or operations.

We seek to acquire assets in our areas of focus from oil and gas companies that have determined that such assets are noncore and desire to remove them from their producing property portfolio or have made strategic decisions to deemphasize their offshore operations. Prior to an acquisition, we perform stringent structural engineering tests to determine whether the reservoirs possess potential upside. Each opportunity is presented, catalogued and graded by our management and risked appropriately for the overall impact to our company.

In 2008, we acquired our first field, South Timbalier 8, located in Louisiana state waters in the Gulf of Mexico. This acquisition was followed by an additional field acquisition in U.S. federal waters in the Gulf of Mexico, West Cameron 66.

On October 29, 2009, we completed the W&T Acquisition, purchasing interests in approximately 35 fields and 350 wells across approximately 195,000 gross (71,000 net) acres primarily located in U.S. federal waters in the Outer Continental Shelf.

In 2010, we completed two acquisitions, which increased the geographic diversity of our portfolio. During the first quarter of 2010, we acquired properties in the Gulf of Mexico, primarily located within Texas state waters from Chroma Oil & Gas, LP. This acquisition consisted of six fields and added interests in an additional 40 wells and approximately 13,900 gross (6,400) net acres to our portfolio. On September 30, 2010, we acquired 27 properties across approximately 195,944 gross (103,130 net) acres in the Gulf of Mexico from Nippon Oil Exploration U.S.A. The Nippon Acquisition included 90 producing wells, 223 wellbores, 41 platforms, and 19 producing fields.

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In February 2011, we acquired additional properties in the Gulf of Mexico, strategically located among our existing assets from Maritech Resources Incorporated. The Maritech Acquisition consisted of eight fields and added interests in 105 gross (43 net) wells and approximately 45,500 gross (22,200 net) acres.

On May 31, 2011, we completed our purchase of certain properties from Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P. (the “Merit Entities”). We acquired interests in various properties across approximately 250,126 gross (127,894 net) acres in the Gulf of Mexico. In connection with the Merit Acquisition, we entered into a contribution agreement with Platinum, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million of our Class D Units.

Our revenue, profitability and future growth rate depend significantly on factors beyond our control, such as economic, political and regulatory developments, and environmental hazards, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since our inception, commodity prices have experienced significant fluctuations.

From time to time, we use derivative financial instruments to economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. Our average prices that reflect both the before and after effects of our realized commodity hedging transactions for the three months ended March 31, 2012 and 2011 are shown in the table below.

	Three Months Ended
	March 31,
	2012		2011
Oil:
Average price before effects of hedges ($/Bbl) (1)	$	114.42	$	99.49
Average price after effects of hedges ($/Bbl)		107.92		93.15
Average price differentials (2)		11.43		5.03
Gas:
Average price before effects of hedges ($/Mcf)(1)	$	2.55	$	4.52
Average price after effects of hedges ($/Mcf)		3.43		5.13
Average price differentials(2)		0.11		0.34

(1) Realized oil and natural gas prices do not include the effect of realized derivative contract settlements.

(2) Price differential compares realized oil and natural gas prices, without giving effect to realized derivative contract settlements, to West Texas Intermediate crude index prices and Henry Hub natural gas prices, respectively.

The United States and other world economies suffered a severe recession extending into 2012 and economic conditions continue to remain uncertain. These uncertain economic conditions reduced demand for oil and natural gas, resulting in a decline in natural gas prices received for our production in 2011 and 2012. While oil prices have strengthened over the past year, both oil and natural gas prices remain unstable and we expect them to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to continue entering into such transactions in the future to reduce the effect of oil and natural gas price volatility on our cash flows. Currently, our risk management program is designed to hedge a significant portion of our production to assure adequate cash flow to meet our obligations. If the global economic instability continues, commodity prices may be depressed for an extended period of time, which could alter our development plans and adversely affect our growth strategy and our ability to access additional funding in the capital markets.

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The primary factors affecting our production levels are capital availability, the success of our drilling program and our portfolio of well work projects. In addition, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline primarily through drilling our existing undeveloped reserves and enhancing our current asset base. Our future growth will depend on our ability to continue to add reserves in excess of production and to bring back to production or increase production on wellbores that are currently not productive or not being optimized. Our ability to add reserves through drilling and well work projects is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flows from operations are dependent upon our ability to manage our overall cost structure.

Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium

In April 2010, the Deepwater Horizon, a drilling platform operated by British Petroleum PLC in ultra deepwater in the U.S. Gulf of Mexico, sank after an apparent blowout and fire. The resulting leak caused a significant oil spill. In response to the explosion and spill, the U.S. Department of the Interior, initially through its federal Mineral Management Services (“MMS”) and subsequently through the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) implemented a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that effectively shut down deepwater drilling sidetracks and bypasses of wells beginning in May 2010 until the moratorium was lifted by the Department of the Interior in October 2010.

In addition, while the moratorium was in place, the BOEMRE issued a series of notices to lessees and operators (“NTLs”) or regulatory requirements imposing new standards and permitting procedures for new wells to be drilled in federal waters of the Outer Continental Shelf (“OCS”). These requirements include the following:

• the Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;

• the Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers;

• the Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and

• the Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system (“SEMS”) in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

The Deepwater Horizon incident is likely to have a significant and lasting effect on the U.S. offshore energy industry, and will likely result in a number of fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards, changes in equipment requirements and the availability and cost of insurance, as well as increased politicization of the industry. On September 14, 2011, the BOEMRE issued proposed rules that would amend the Workplace Safety Rule by requiring the imposition of certain added safety procedures to a company’s SEMS not covered by the original rule and revising existing obligations that a company’s SEMS be audited by requiring the use of an independent third party auditor who has been pre-approved by the agency to perform the auditing task. As a result of the issuance of these adopted and proposed regulatory requirements, the BOEMRE has been taking much longer than in the past to review and approve permits for new wells. These new requirements also increase the cost of preparing each permit application and will increase the cost of each new well, particularly for wells drilled in deeper waters on the OCS.

Moreover, because of BOEMRE’s separation into two federal bureaus, the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”), on October 1, 2011, we are now interacting with two newly formed federal bureaus to obtain approval of our exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays and increased exploratory and production costs as the functions of the former BOEMRE are fully divested from the former agency and implemented in the two federal bureaus. These delays and costs could have a significant adverse effect on our results of operations.

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We are unsure what long-term effect, if any, the BOEM’s or BSEE’s additional regulatory requirements and permitting procedures will have on our offshore operations. Consequently, we may be subject to a variety of unforeseen adverse consequences arising directly or indirectly from the Deepwater Horizon incident.

How We Evaluate Our Operations

We use a variety of financial and operational measures to assess our overall performance. Among these measures are (1) volumes of oil and natural gas produced, (2) oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) Adjusted EBITDA (as defined in the following table).

The following table contains certain financial and operational data for each of the three months ended March 31, 2012 and 2011:

	Three Months Ended
	March 31,
	2012			2011
Average daily sales:
Oil (Boepd)		5,812			4,178
Natural gas (Mcfpd)		61,682			37,165
Plant products (Galpd)		39,491			23,760
Oil equivalents (Boepd)		17,033			10,938
Average realized prices (1):
Oil ($/Bbl)	$	107.92		$	93.15
Natural gas ($/Mcf)		3.43			5.13
Plant products ($/Gallon)		1.19			1.01
Oil equivalents ($/Boe)		51.99			55.20
Costs and Expenses:
Lease operating expense ($/Boe)		27.90			23.43
Production tax expense ($/Boe)		0.22			0.03
General and administrative expense ($/Boe)		4.15			4.60
Net income (loss) (in thousands)		(5,654	)		(24,119	)
Adjusted EBITDA(2) (in thousands)		29,058			24,584

(1) Average realized prices presented give effect to our hedging.

(2) Adjusted EBITDA is defined as net income (loss) before interest expense, unrealized gain/loss on derivative instruments, accretion and depreciation, depletion and amortization. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP, and should not be considered as an alternative to net income (loss), operating income (loss) or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as a measure of our liquidity. We present Adjusted EBITDA because it is frequently used by securities analysts, investors and other interested parties in the evaluation of high-yield issuers, many of whom present Adjusted EBITDA when reporting their results. Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results or cash flows as reported under GAAP. Because of these limitations, Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. Our presentation of Adjusted EBITDA should not be construed as an inference that our future results will be unaffected by unusual or nonrecurring items. A reconciliation table is provided below to illustrate how we derive Adjusted EBITDA.

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	Three Months Ended March 31,
	2012			2011
	(in thousands)
Net loss	$	(5,654	)	$	(24,119	)
Adjusted EBITDA	$	29,058		$	24,584
Reconciliation of Net loss to Adjusted EBITDA
Net loss	$	(5,654	)	$	(24,119	)
Interest expense		6,535			5,793
Unrealized loss on derivative instruments		6,726			30,978
Accretion		9,080			3,938
Depreciation, depletion and amortization		12,371			7,994
Adjusted EBITDA	$	29,058		$	24,584

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Results of Operations

The following table sets forth certain information with respect to oil and gas operations for the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31,
	2012			2011			Change			% Change
PRODUCTION:
Oil (MBbl)		529			376			153			41	%
Natural gas (MMcf)		5,613			3,345			2,268			68	%
Plant products (MGal)		3,594			2,138			1,456			68	%
Total (Mboe)		1,550			984			566			58	%
REVENUES:
Oil sales	$	60,518		$	37,412		$	23,106			62	%
Natural gas sales		14,316			15,107			(791	)		-5	%
Plant product sales and other revenue		6,604			3,308			3,296			100	%
Realized gain (loss) on derivative financial instruments		1,469			(336	)		1,805			-537	%
Unrealized loss on derivative financial instruments		(6,726	)		(30,978	)		24,252			-78	%
TOTAL REVENUES		76,181			24,513			51,668			211	%
OPERATING EXPENSES:
Lease operating		43,242			23,060			20,182			88	%
Production taxes		343			29			314			1083	%
Workover		2,569			3,163			(594	)		-19	%
Exploration		897			—			897			100	%
Depreciation, depletion and amortization		12,371			7,994			4,377			55	%
General and administrative		6,434			4,525			1,909			42	%
Accretion		9,080			3,938			5,142			131	%
TOTAL OPERATING EXPENSES		74,936			42,709			32,227			75	%
INCOME (LOSS) FROM OPERATIONS		1,245			(18,196	)		19,441			-107	%
OTHER INCOME (EXPENSE):
Interest income		281			6			275			4583	%
Miscellaneous expense		(645	)		(136	)		(509	)		374	%
Interest expense		(6,535	)		(5,793	)		(742	)		13	%
TOTAL OTHER EXPENSE		(6,899	)		(5,923	)		(976	)		16	%
NET LOSS	$	(5,654	)	$	(24,119	)	$	18,465			-77	%

Production

Oil and natural gas production.Total oil, natural gas and plant product production of 1,550 MBoe increased 566 MBoe, or 58%, during the three months ended March 31, 2012, compared to the same period in 2011. The increase in production during 2012 was primarily a result of properties acquired in the Maritech Acquisition in February 2011 (32 MBoe) and the Merit Acquisition in May 2011 (558 MBoe).

Revenues

Total revenues.Total revenues for the three months ended March 31, 2012 of $76.2 million increased $51.7 million, or 211%, over the comparable period in 2011. The increase in revenues during 2012 was a result of increased production related to the properties acquired in the Maritech Acquisition ($2.1 million) and the Merit Acquisition ($28.7 million) and higher oil prices which were partially offset by lower natural gas prices.

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We entered into certain oil and natural gas commodity derivative contracts in 2012 and 2011. We realized a gain on these derivative contracts in the amount of $1.5 million for the three months ended March 31, 2012 and realized a loss of $0.3 million for the three months ending March 31, 2011. We recognized an unrealized loss of $6.7 million for the three months ended March 31, 2012 and an unrealized loss of $31.0 million in the same period in 2011. Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, increased $25.6 million, or 46% for the three months ended March 31, 2012 compared to the same period in 2011 as a result of increased oil, natural gas and plant products production from the acquisitions and higher oil prices.

Excluding hedges, we realized average oil prices of $114.42 per barrel and $99.49 per barrel and gas prices of $2.55 per Mcf and $4.52 per Mcf for the three months ended March 31, 2012 and 2011, respectively. Although average prices realized from the sale of oil reflected the economic turnaround that began during 2011, economic conditions continue to remain uncertain. Oil and natural gas prices will remain unstable and we expect them to be volatile in the future.

Operating Expenses

Lease operating costs.Our lease operating costs for the three months ended March 31, 2012 increased to $43.2 million, or $27.90 per Boe. For the three months ended March 31, 2011, our lease operating costs were $23.1 million, or $23.43 per Boe. The increase in lease operating costs during 2012 is directly related to the increase in properties from the Maritech and the Merit Acquisitions. The increase in cost per Boe during 2012 is primarily attributable to a mix of increased properties and certain non-recurring safety and regulatory costs on the newly acquired properties.

Workover costs.Our workover costs for the three months ended March 31, 2012 were $2.6 million, a decrease of $0.6 million compared to the same period in 2011. For the three months ended March 31, 2012, Galveston 389/424, High Island A443, Eugene Island 331, Eugene Island 240 and West Delta 31/32 were the primary workover expense projects.

Depreciation, depletion and amortization.DD&A expense was $12.4 million, or $7.98 per Boe, for the three months ended March 31, 2012 and $8.0 million, or $8.12 per Boe, for the three months ended 2011. In 2012, the increase in DD&A was a result of increased production associated with the properties acquired in 2011. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations.

General and administrative expenses.G&A expense was $6.4 million, or $4.15 per Boe, for the three months ended March 31, 2012 and $4.5 million, or $4.60 per Boe, for the same period in 2011. The increase in G&A expense in 2012 resulted principally from costs associated with the increase in staff and related administrative costs attributable to our growth in 2011.

Accretion expense.We recognized accretion expense of $9.1 million for the three months ended March 31, 2012 compared to $3.9 million for the three months ended March 31, 2011. The increase in accretion expense in 2012 was attributable to assumed asset retirement obligations related to our acquisitions in 2011.

Interest expense. Interest expense of $6.5 million increased $0.7 million for the three months ended March 31, 2012 compared to the same period in 2011. The increase of interest expense in 2012 compared to 2011 was a result of borrowing on the Credit Facility to fund the Merit P&A obligation.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from our members, proceeds from the offering of our senior notes, which closed in November 2010, borrowings under our lines of credit and cash flows from operations. We believe that our working capital requirements, contractual obligations and expected capital expenditures discussed below, as well as our other liquidity needs for the next twelve months, can be met from cash flows provided by operations and from amounts available under our revolving Credit Facility. Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our P&A obligations. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Senior Secured Revolving Credit Facility

On December 24, 2010, we entered into an aggregate $110 million Credit Facility with Capital One, N.A., as administrative agent and a lender thereunder. The Credit Facility is comprised of (1) a senior secured reserve-based revolver, under which our initial borrowing base was set at $35 million and (2) a $75 million secured letter of credit facility, which is to be used exclusively for the issuance of letters of credit in support of our future P&A obligations relating to our oil and gas properties. The borrowing base under our revolving credit facility is subject to redetermination on a semi-annual basis, effective April 1 and October 1, and up to one

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additional time during any six month period, as may be requested by either us or the administrative agent, acting at the direction of the majority of the lenders. The borrowing base will be determined by the administrative agent in its sole discretion and consistent with its normal oil and gas lending criteria in existence at that particular time. Our obligations under the Credit Facility are guaranteed by our existing subsidiaries and are secured on a first-priority basis by all of our and our subsidiaries’ assets, in the case of the revolver, and by cash collateral, in the case of the letter of credit facility. The Credit Facility has a maturity date of December 31, 2013.

The Credit Facility is subject to certain customary fees and expenses of the lenders and administrative agent thereunder.

The Credit Facility contains customary covenants, including, but not limited to, restrictions on our and our subsidiaries’ ability to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets subject to their security interests, pay dividends, make acquisitions, loans, advances or investments, sell or otherwise transfer assets, enter into transactions with affiliates or change our line of business.

The Credit Facility requires that the ratio of our consolidated current assets to our consolidated current liabilities never be less than 1.0 to 1.0. In addition, our Credit Facility requires that as of the end of each quarter, our ratio of consolidated EBITDA to our consolidated interest charges for the four immediately preceding consecutive fiscal quarters never be less than 3.0 to 1.0.

The Credit Facility provides that, upon the occurrence of certain events of default, our obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include payment defaults to the lenders, material inaccuracies of representations and warranties, covenant defaults, cross defaults to other material indebtedness, including the notes, voluntary and involuntary bankruptcy proceedings, material money judgments, certain change of control events and other customary events of default.

On May 31, 2011, we entered into an amendment to the Credit Facility that (1) increased the amount available for borrowing thereunder from $35 million to $70 million and (2) increased the secured letter of credit from $75 million to $125 million.

As of March 31, 2012, we were in compliance with all covenants.

As of March 31, 2012, letters of credit in the aggregate amount of $108.8 million were outstanding under this facility and we had $23.0 million in borrowings under the revolver. As of May 7, 2012, $27.8 million was available for additional borrowings, including $21.5 million under the revolver.

13.75% Senior Secured Notes

On November 23, 2010, we issued $150 million in aggregate principal amount of the Notes discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under our lines of credit, to fund BOEMRE collateral requirements, and to prefund our P&A escrow accounts. We pay interest on the Notes semi-annually, on June 1st and December 1st of each year, in arrears, commencing June 1, 2011. The Notes mature on December 1, 2015.

The Notes are secured by a security interest in the issuers’ and the guarantors’ assets (excluding the escrow accounts set up for the future P&A obligations of the properties acquired in the W&T Acquisition). The liens securing the Notes are subordinated and junior to any first lien indebtedness, including our derivative contracts obligation and Credit Facility.

We have the right or the obligation to redeem the Notes under various conditions. If we experience a change of control, the holders of the Notes may require us to repurchase the Notes at 101% of the principal amount thereof, plus accrued unpaid interest. In addition, within 90 days after December 2011 for which excess cash flow, as defined in the Indenture, exceeds $5.0 million to the extent permitted by our Notes, we will offer to purchase the Notes at an offer price equal to 100% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest. We also have an optional redemption in which we may redeem up to 35% of the aggregate principal amount of the Notes at a price equal to 110.0% of the principal amount, plus accrued and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings until December 1, 2013. From December 1, 2013 until December 1, 2014, we may redeem some or all of the Notes at an initial redemption price equal to par value plus one-half the coupon which equals 106.875% plus accrued and unpaid interest to the date of the redemption. On or after December 1, 2014, we may redeem some or all of the Notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption.

On May 31, 2011, we amended the Indenture, among other things, to: (1) increase the amount of capital expenditures permitted to be made by us on an annual basis, (2) enable us to obtain financial support from our majority equity holder by way of a $30 million investment in Class D Units that can be repaid over time and (3) obligate us to make an offer to repurchase the Notes semiannually at an offer price equal to 103% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest to the extent it meets certain defined financial tests and as permitted by our credit facilities.

As of March 31, 2012, we were in compliance with our covenants under the Indenture.

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Member Contributions

On May 31, 2011, Platinum entered into a contribution agreement with us, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivable, in exchange for 30 million of our Class D Units. The Class D Units are non-voting units having an aggregate liquidation preference of $30 million and accruing dividends payable in kind at a rate per annum of 24%.

At March 31, 2012, Platinum has contributed a total of $15.1 million in cash and $14.9 million remains in financial instruments deemed by us to be a cash equivalent.

Capital Expenditure Budget

We expect total capital expenditures to be $49.9 million for 2012 (excluding expenditures directly related to any acquisitions). Approximately $8.4 million was expended in the first three months of 2012 for various projects including recompletions and drilling, and the remaining $41.5 million will be used for drilling and development during the remainder of the year. The capital expenditure limitation set forth in the Indenture was amended in conjunction with the Consent Solicitation on May 31, 2011 to a maximum limit of 30% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expense for any year after December 31, 2011.

Our expected capital expenditures may be adjusted as business conditions warrant and the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. The amount, timing and allocation of capital expenditures are largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our expected capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

To date, our 2012 capital expenditures have been funded from borrowings under our line of credit and cash flows from operations. We believe the borrowings under our Credit Facility, together with cash flows from operations, should be sufficient to fund the remainder of our 2012 capital expenditures.

We expect that our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. We actively review acquisition opportunities on an ongoing basis. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Cash Flows

The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the three months ended March 31, 2012 and 2011:

	Three Months Ended
	March 31,
	2012			2011
	(in thousands)
Net cash provided by operating activities	$	28,269		$	8,532
Net cash used in investing activities		(16,746	)		(7,254	)
Net cash used in financing activities		(11,589	)		(4,633	)
Net decrease in cash and equivalents	$	(66	)	$	(3,355	)

Cash flows provided by operating activities.Cash provided by operating activities totaling $28.3 million during the three months ended March 31, 2012 compared to $8.5 million during the three months ended March 31, 2011. The increase in operating cash flows was principally attributable to higher net income as a result of the 2011 acquisitions.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and natural gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk” below.

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Cash flows used in investing activities. Cash used in investing activities totaling $16.7 million in the three months ended March 31, 2012 was primarily attributable to oil and gas property additions, the assets purchased in the Merit Acquisition and the funding of the future P&A obligations through escrow; cash used in investing activities in the comparable period of 2011 totaling $7.3 million was attributable to the assets purchased in the Maritech Acquisition and the funding of the future P&A obligations through escrow and restricted cash.

Cash flows used in financing activities.Cash flows used in financing activities of $11.6 million in the three months ended March 31, 2012 were attributable to payments on the Credit Facility and short term notes, tax distributions to members and debt issue costs partially offset by borrowings on the Credit Facility. Cash used in financing activities of $4.6 million during the three months ended March 31, 2011 related primarily to the repayment of short term notes payable, tax distributions to members and debt issuance costs of the Notes.

Asset Retirement Obligations

As many as four times per year we review, and, to the extent necessary, revise our asset retirement obligation estimates. In 2011, we increased our asset retirement obligations by $166.4 million, primarily as a result of the Maritech Acquisition and the Merit Acquisition, and recognized $27.4 million in accretion expense. As of March 31, 2012, we increased our asset retirement obligations by $5.6 million and for the three months ended March 31, 2012, we recognized $9.1 million in accretion expense.

At March 31, 2012 and December 31, 2011, we recorded total asset retirement obligations of $294.3 million and $288.7 million, respectively, and have funded approximately $180.4 million and $172.2 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds. As of March 31, 2012 and December 31, 2011, we also have a guaranteed escrow amount of $20.3 million for certain fields which will be refunded to us once we have completed our P&A obligations on the entire field. The escrow is guaranteed by TETRA Technologies, Inc.

Contractual Obligations

We have various contractual obligations in the normal course of our operations and financing activities. The following schedule summarizes our contractual obligations and other contractual commitments at March 31, 2012:

	Payments Due by Period
	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		After 5 Years
	(in thousands)
Contractual Obligations
Total debt and notes payable	$	173,000	$	—	$	23,000	$	150,000	$	—
Interest on debt and notes payable		77,239		21,555		41,934		13,750		—
Operating leases(1)		16,598		2,737		4,506		3,612		5,743
Total contractual obligations		266,837		24,292		69,440		167,362		5,743
Other Obligations
Asset retirement obligations(2)		294,324		14,093		203,617		35,228		41,386
Total obligations	$	561,161	$	38,385	$	273,057	$	202,590	$	47,129

(1) Consists of office space leases for our Houston, Texas offices and services provided in the office.

(2) Asset retirement obligations will be partially funded via the escrow.

Off-Balance Sheet Arrangements

In October 2010, we guaranteed a loan in the aggregate principal amount of $3.2 million for a related party which is not consolidated in our financials as the entity is not material to us. At March 31, 2012, the balance of the loan was $2.9 million and has a maturity date of October 8, 2013. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Oil and Gas Hedging

As part of our risk management program, we hedge a portion of our anticipated oil and natural gas production to reduce our exposure to fluctuations in oil and natural gas prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions.

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While the use of these hedging arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions.

At March 31, 2012, commodity derivative instruments were in place covering approximately 67% of our projected oil sales volumes and 40% of our projected natural gas volumes through 2012.

Please see “Notes to Consolidated Financial Statements—Note 4—Derivative Instruments” for additional discussion regarding the accounting applicable to our hedging program.

Critical Accounting Policies

“Management’s Discussion and Analysis of Financial Condition” is based upon our consolidated financial statements, which have been prepared in conformity with GAAP. The preparation of these statements requires that we make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. We base these estimates on historical experience and on assumptions that we consider reasonable under the circumstances; however, reported results could differ from the current estimates under different assumptions and/or conditions. We have disclosed the areas requiring the use of management’s estimates in Note 2 to our consolidated financial statements as well as in “Management’s Discussion and Analysis of Financial Condition” included in our 2011 Form 10-K.

Inflation and Changes in Prices

Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the three months ended March 31, 2012, we received an average of $114.42 per barrel of oil and $2.55 per Mcf of natural gas, respectively, before consideration of commodity derivative contracts compared to $99.49 per barrel of oil and $4.52 per Mcf of natural gas, respectively, in the three months ended March 31, 2011. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through the first six months of 2008, commodity prices for oil and natural gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs but also on capital costs. We expect these costs to reflect upward pressure during 2012 as a result of the improvements in oil prices in 2011 and 2012.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks including commodity price risk, credit risk and interest rate risk. We address these risks through a program of risk management, which may include the use of derivative instruments.

The following quantitative and qualitative information is provided about financial instruments to which we are a party, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit.

Hypothetical changes in interest rates and commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Commodity Price Risk

Our primary market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our annualized production for the three months ended March 31, 2012, our annual revenue would increase or decrease by approximately $21.2 million for each $10.00 per barrel change in oil prices and $22.5 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging. Based on our total annual production for the year ended December 31, 2011, our revenues would have increased or decreased by approximately $19.9 million for each $10.00 per barrel change in oil prices and $18.2 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging.

To partially reduce price risk caused by these market fluctuations, we hedge a significant portion of our anticipated oil and natural gas production as part of our risk management program. Reducing our exposure to price volatility helps ensure that we have

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adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based, in part, on our view of current and future market conditions. While hedging limits the downside risk of adverse price movements, it also may limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions.

At March 31, 2012, the fair value of our commodity derivatives were included in the consolidated balance sheets for approximately $0.9 million as current assets and $5.6 million as long-term liabilities. At December 31, 2011, the fair value of our commodity derivatives were approximately $4.2 million as current assets and $2.1 million as long-term liabilities. For the three months ended March 31, 2012, we realized a net increase in oil and natural gas revenues related to hedging transactions of approximately $1.5 million and a decrease for the same period in 2011 of $0.3 million.

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As of March 31, 2012, we maintained the following commodity derivative contracts:

Remaining Contract Term: Oil	Contract Type		Notational Volume in Bbls/Month		NYMEX Strike Price
April 2012 - April 2012		Swap		51,730	$	102.40
June 2014 - June 2014		Swap		48,860	$	102.40
March 2014 - March 2014		Swap		45,910	$	102.40
May 2012 - May 2012		Swap		45,340	$	102.40
January 2013 - January 2013		Swap		43,510	$	102.40
May 2014 - May 2014		Swap		42,530	$	102.40
December 2014 - December 2014		Swap		41,880	$	102.40
April 2014 - April 2014		Swap		41,850	$	102.40
July 2014 - July 2014		Swap		36,680	$	102.40
June 2012 - June 2012		Swap		36,000	$	102.40
March 2013 - March 2013		Swap		35,760	$	102.40
August 2014 - August 2014		Swap		35,360	$	102.40
October 2014 - October 2014		Swap		32,920	$	102.40
September 2014 - September 2014		Swap		32,290	$	102.40
January 2014 - January 2014		Swap		30,600	$	102.40
November 2014 - November 2014		Swap		30,000	$	102.40
February 2013 - February 2013		Swap		29,030	$	102.40
April 2013 - April 2013		Swap		28,740	$	102.40
May 2013 - May 2013		Swap		28,540	$	102.40
December 2013 - December 2013		Swap		27,750	$	96.90
January 2013 - October 2013		Swap		27,750	$	96.90
April 2012 - December 2012		Swap		27,500	$	85.90
November 2013 - November 2013		Swap		26,800	$	96.90
December 2012 - December 2012		Swap		24,860	$	102.40
October 2012 - October 2012		Swap		23,170	$	102.40
December 2012 - December 2012		Swap		23,000	$	96.90
April 2012 - October 2012		Swap		23,000	$	96.90
August 2012 - August 2012		Swap		22,890	$	102.40
June 2013 - June 2013		Swap		22,800	$	102.40
April 2012 - June 2012		Swap		22,125	$	100.80
November 2012 - November 2012		Swap		22,080	$	96.90
February 2014 - February 2014		Swap		22,010	$	102.40
July 2012 - July 2012		Swap		21,110	$	102.40
September 2012 - September 2012		Swap		20,930	$	102.40
January 2013 - December 2013		Swap		19,750	$	85.90
December 2013 - December 2013		Swap		19,310	$	102.40
November 2012 - November 2012		Swap		19,290	$	102.40
January 2014 - February 2014		Swap		19,000	$	96.90
April 2012 - December 2012		Swap		17,050	$	81.22
January 2013 - June 2013		Swap		15,542	$	100.80
December 2012 - December 2012		Swap		15,140	$	100.80
January 2014 - December 2014		Swap		15,000	$	65.00
July 2013 - July 2013		Swap		14,700	$	102.40
November 2013 - November 2013		Swap		14,320	$	102.40
August 2013 - August 2013		Swap		14,080	$	102.40
October 2013 - October 2013		Swap		13,710	$	102.40
September 2013 - September 2013		Swap		12,390	$	102.40
July 2012 - July 2012		Swap		12,048	$	100.80
January 2014 - May 2014		Swap		10,083	$	100.80
December 2013 - December 2013		Swap		10,042	$	100.80
August 2012 - August 2012		Swap		8,296	$	100.80
July 2013 - July 2013		Swap		7,132	$	100.80
August 2013 - August 2013		Swap		5,980	$	100.80
September 2012 - September 2012		Swap		3,998	$	100.80
September 2013 - September 2013		Swap		3,897	$	100.80
October 2013 - October 2013		Swap		3,259	$	100.80
April 2012 - December 2012		Swap		1,900	$	81.14
October 2012 - October 2012		Swap		1,884	$	100.80
April 2012 - July 2012		Swap		200	$	83.50

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Remaining Contract Term: Natural Gas	Contract Type		Notational Volume in MMBtus/Month		NYMEX Strike Price
April 2012 - May 2012		Swap		318,958	$	4.94
June 2012 - June 2012		Swap		303,880	$	4.94
April 2012 - December 2012		Swap		227,000	$	4.60
January 2013 - June 2013		Swap		200,669	$	4.94
July 2013 - July 2013		Swap		148,788	$	4.94
August 2013 - August 2013		Swap		139,212	$	4.94
January 2014 - June 2014		Swap		129,960	$	4.94
December 2013 - December 2013		Swap		119,462	$	4.94
September 2013 - September 2013		Swap		116,125	$	4.94
April 2012 - December 2012		Swap		112,000	$	5.00
July 2012 - July 2012		Swap		106,638	$	4.94
December 2012 - December 2012		Swap		106,375	$	4.94
January 2013 - December 2013		Swap		104,000	$	4.60
October 2013 - October 2013		Swap		91,166	$	4.94
August 2012 - August 2012		Swap		90,586	$	4.94
January 2014 - February 2014		Swap		82,000	$	4.60
November 2013 - November 2013		Swap		64,926	$	4.94
September 2012 - September 2012		Swap		56,141	$	4.94
April 2012 - December 2012		Swap		53,000	$	5.70
January 2013 - December 2013		Swap		47,000	$	5.00
October 2012 - October 2012		Swap		41,462	$	4.94
April 2012 - December 2012		Swap		26,838	$	5.89
April 2012 - July 2012		Swap		5,250	$	5.89
November 2012 - November 2012		Swap		2,951	$	4.94

For a further discussion of our hedging activities, please see “Notes to Consolidated Financial Statements—Note 4—Derivative Instruments.”

Credit Risk

We monitor our risk of loss associated with non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through joint interest receivables, which totaled $8.5 million at March 31, 2012 and $10.5 million at December 31, 2011. Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have an interest. We also have exposure to credit risk from the sale of our oil and natural gas production that we market to energy marketing companies and refineries, the receivables which totaled $34.4 million at March 31, 2012 and $35.9 million at December 31, 2011.

In order to minimize our exposure to credit risk, we request prepayment of costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. We also have the right to place a lien on our co-owners interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. In addition, we monitor our exposure to counterparties on oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We historically have not required our counterparties to provide collateral to support oil and natural gas sales receivables owed to us.

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Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility, which bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 2.75% to 3.5%, or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The applicable margin is computed based on the grid when the borrowing based utilization percentage is at its highest level. Based on the $131.8 million outstanding under the Credit Facility as of March 31, 2012, an increase of 100 basis points in the underlying interest rate would have had a $1.3 million impact on our annual interest expense. However, there is no guarantee that we will not borrow additional amounts under the Credit Facility in the future, and, in the event we borrow amounts and interest rates significantly increase, the interest that we would be required to pay would be more significant. We do not believe our variable interest rate exposure warrants entry into interest rate hedges and, therefore, we have not hedged our interest rate exposure. However, to reduce our exposure to changes in interest rates for our borrowings under the Credit Facility, we may in the future enter into interest rate risk management arrangements for a portion of our outstanding debt to alter our interest rate exposure.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2012.

Changes in Internal Control Over Financial Reporting.There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We received a Notice of Proposed Civil Penalty Assessment dated April 5, 2011 (“Notice”) from the BOEMRE for an Incident of Noncompliance (“INC”) arising from a particular well’s alleged exceedance of certain testing time limits and alleged need for certain corrective actions. The INC was issued by BOEMRE during its on-site inspection of Vermilion Area Block 124, Platform F on July 30, 2010. The Notice includes a proposed penalty of greater than $0.1 million. We requested and attended a mitigation hearing with BOEMRE on the matter as we believe that a significant threat to safety or the environment did not exist, and are seeking a reduced civil penalty based on the mitigating circumstances presented in the hearing. We have received a final decision from BOEMRE on the matter and have been assessed a penalty of approximately $0.3 million of which we appealed to the Interior Board of Land Appeals (“IBLA”). We received notice on December 19, 2011 that the civil penalty would remain as assessed by the Reviewing Officer’s final decision. The decision of the IBLA is subject to review in the U.S. District Court before payment is required. We are waiting on notification that payment is due.

We are also subject to other environmental matters and regulation. For a discussion of these items, see “Business—Environmental Matters and Regulation” in our 2011 Form 10-K.

We are party to various other litigation matters arising in the ordinary course of business. We do not believe the outcome of these disputes or legal actions will have a material adverse effect on our financial statements.

Item 1A. Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Risk Factors” in our 2011 Form 10-K. The risks described in the 2011 Form 10-K could materially and adversely affect our business, financial condition, cash flows, and results of operations. There have been no material changes to the risks described in the 2011 Form 10-K. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

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Item 6. Exhibits

The exhibits marked with the asterisk symbol (*) are filed (or furnished in the case of Exhibits 32.1 and 32.2) with this Form 10-Q.

Exhibit Number	Description
3.1	Certificate of Formation of Black Elk Energy Offshore Operations, LLC, dated as of November 20, 2007 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.2	Certificate of Amendment of Black Elk Energy Offshore Operations, LLC, dated as of January 29, 2008 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.3	Second Amended and Restated Limited Liability Company Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of July 13, 2009 (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.4	First Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated August 19, 2010 (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.5	Second Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 31, 2011 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011 (SEC File No. 333-174226)).
*31.1	Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS§	XBRL Instance Document
101.SCH§	XBRL Taxonomy Extension Schema Document
101.CAL§	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE§	XBRL Taxonomy Extension Presentation Linkbase Document

§ - Furnished with this Form 10-Q. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC (Registrant)
	By:	Black Elk Energy, LLC, its sole member
Date: May 10, 2012	By:	/s/ James Hagemeier
		James Hagemeier
		Vice President, Chief Financial Officer and Manager (Duly Authorized Officer and Principal Financial Officer)

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EXHIBIT INDEX

The exhibits marked with the asterisk symbol (*) are filed (or furnished in the case of Exhibits 32.1 and 32.2) with this Form 10-Q.

Exhibit Number	Description
3.1	Certificate of Formation of Black Elk Energy Offshore Operations, LLC, dated as of November 20, 2007 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.2	Certificate of Amendment of Black Elk Energy Offshore Operations, LLC, dated as of January 29, 2008 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.3	Second Amended and Restated Limited Liability Company Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of July 13, 2009 (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.4	First Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated August 19, 2010 (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.5	Second Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 31, 2011 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011 (SEC File No. 333-174226)).
*31.1	Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS§	XBRL Instance Document
101.SCH§	XBRL Taxonomy Extension Schema Document
101.CAL§	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE§	XBRL Taxonomy Extension Presentation Linkbase Document

§- Furnished with this Form 10-Q. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

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