Black Elk Energy Offshore Operations, LLC - FORM 10-Q

Black Elk Energy Offshore Operations, LLC - FORM 10-Q - November 10, 2011

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file	filename
EXCEL - IDEA: XBRL DOCUMENT - Black Elk Energy Offshore Operations, LLC	Financial_Report.xls
EX-32.1 - SECTION 906 CERT OF CEO AND CFO - Black Elk Energy Offshore Operations, LLC	d231569dex321.htm
EX-31.1 - RULE 13A-14(A) CERT OF CEO - Black Elk Energy Offshore Operations, LLC	d231569dex311.htm
EX-31.2 - RULE 13A-14(A) CERT OF CFO - Black Elk Energy Offshore Operations, LLC	d231569dex312.htm
EX-10.1 - WAIVER - Black Elk Energy Offshore Operations, LLC	d231569dex101.htm

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 September 30, 2011

¨	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):

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

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC’S

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2011

TABLE OF CONTENTS


		Page

Part I. Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010		1
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010		2
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010		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		28
Item 4.	Controls and Procedures		31
Part II. Other Information
Item 1.	Legal Proceedings		32
Item 1A.	Risk Factors		32
Item 5.	Other Information		33
Item 6.	Exhibits		34
Signatures			35
Exhibit Index

(i)

PART I—FINANCIAL INFORMATION

Item 1.

Financial Statements

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)


	September 30, 2011		December 31, 2010
	(Unaudited)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	16,129	$	18,879
Accounts receivable, net		44,007		26,093
Due from affiliates		272		435
Prepaid expenses and other		31,639		13,123
Derivative assets		20,340		—

TOTAL CURRENT ASSETS		112,387		58,530


OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $91,504 and $55,119 at September 30, 2011 and December 31, 2010, respectively		257,125		123,783

OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $680 and $264 at September 30, 2011 and December 31, 2010, respectively		2,253		1,152

OTHER ASSETS
Debt issue costs, net		9,549		8,871
Derivative assets		7,211		—
Asset retirement obligation escrow receivable		20,348		—
Escrow for abandonment costs		160,986		114,168
Other assets		3,032		—

TOTAL OTHER ASSETS		201,126		123,039


TOTAL ASSETS	$	572,891	$	306,504


LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)

CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	67,329	$	34,111
Derivative liabilities		—		3,754
Asset retirement obligations		16,514		1,023
Current portion of debt and notes payable		10,357		2,069

TOTAL CURRENT LIABILITIES		94,200		40,957


LONG-TERM LIABILITIES
Gas imbalance payable		1,087		4,552
Derivative liabilities		—		11,702
Asset retirement obligations, net of current portion		266,344		121,219
Debt, net of current portion, net of unamortized discount of $1,166 and $1,316 at September 30, 2011 and December 31, 2010, respectively		162,834		148,684

TOTAL LONG-TERM LIABILITIES		430,265		286,157


TOTAL LIABILITIES		524,465		327,114

COMMITMENTS AND CONTINGENCIES

MEMBERS’ EQUITY (DEFICIT)		48,426		(20,610	)


TOTAL LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)	$	572,891	$	306,504

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

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010

REVENUES:
Oil sales	$	56,470		$	11,699		$	147,038		$	38,727
Natural gas sales		22,398			6,980			57,388			22,138
Plant product sales and other revenue		5,500			1,417			13,614			4,341
Realized gain on derivative financial instruments		6,746			2,272			3,664			6,312
Unrealized gain (loss) on derivative financial instruments		50,234			(1,578	)		43,006			5,796

TOTAL REVENUES		141,348			20,790			264,710			77,314

OPERATING EXPENSES:
Lease operating		47,125			11,634			100,000			28,909
Production taxes		231			77			439			464
Workover		6,053			961			11,599			2,004
Exploration		—			169			—			707
Depreciation, depletion and amortization		14,411			6,622			32,018			19,916
Impairment		1,096			—			5,419			—
General and administrative		4,991			2,651			16,862			7,025
Accretion		9,089			1,831			18,471			5,495
Gain on sale of asset		—			—			(142	)		—

TOTAL OPERATING EXPENSES		82,996			23,945			184,666			64,520


INCOME (LOSS) FROM OPERATIONS		58,352			(3,155	)		80,044			12,794

OTHER INCOME (EXPENSE):
Interest income		131			61			358			64
Miscellaneous expense		(496	)		(686	)		(6,086	)		(686	)
Interest expense		(6,873	)		(2,262	)		(19,275	)		(6,526	)

TOTAL OTHER EXPENSE		(7,238	)		(2,887	)		(25,003	)		(7,148	)


NET INCOME (LOSS)		51,114			(6,042	)		55,041			5,646

PREFERRED UNIT DIVIDENDS		1,800			—			2,400			—

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	49,314		$	(6,042	)	$	52,641		$	5,646

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

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)


	Nine Months Ended September 30,
	2011			2010

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	55,041		$	5,646

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		32,018			19,916
Impairment of oil and gas properties		5,419			—
Accretion of asset retirement obligations		18,471			5,495
Amortization of debt issue costs		1,999			187
Amortization of debt discount		150			—
Unrealized gain on derivative instruments		(43,006	)		(5,796	)
Gain on sale of asset		(142	)		—
Changes in operating assets and liabilities:
Accounts receivable		(17,914	)		(1,475	)
Due from affiliates, net		163			(115	)
Prepaid expenses and other assets		(18,516	)		(12,656	)
Accounts payable and accrued liabilities		30,818			14,129
Gas imbalance		(5,956	)		(405	)
Asset retirement obligations		(5,010	)		—

NET CASH PROVIDED BY OPERATING ACTIVITIES		53,535			24,926


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(20,056	)		(14,664	)
Acquisition of oil and gas properties		(23,509	)		19,751
Sale of oil and gas properties		150			—
Additions to property and equipment		(1,517	)		(714	)
Deposits		(540	)		—
Restricted cash		—			522
Escrow payments		(46,819	)		(64,297	)

NET CASH USED IN INVESTING ACTIVITIES		(92,291	)		(59,402	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on short term notes		8,288			—
Proceeds from issuance of long-term debt		—			73,619
Payments on long-term debt		—			(36,606	)
Borrowing on bank debt		134,410			—
Payments on bank debt		(120,410	)		—
Debt issuance costs		(2,677	)		—
Contributions from members		30,000			—
Distributions to members		(13,605	)		(1,598	)

NET CASH PROVIDED BY FINANCING ACTIVITIES		36,006			35,415


NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(2,750	)		939


CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD		18,879			6,236


CASH AND CASH EQUIVALENTS - END OF PERIOD	$	16,129		$	7,175


SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	11,476		$	5,549


NONCASH INVESTING AND FINANCING ACTIVITIES:
Increase in oil and gas properties for asset retirement obligations	$	147,155		$	62,911


Increase in asset retirement obligation escrow receivable	$	20,348		$	—


Paid-in-kind dividends on preferred equity and accrued distributions to members	$	2,400		$	—

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

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 for the year ended December 31, 2010, which is posted on our website.

Principles of Consolidation: The consolidated financial statements include the accounts of Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries. 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 December 2010, the FASB issued new disclosure guidance for business combinations. The objective of the guidance is to address diversity in practice about the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. The updated accounting guidance requires a public entity to disclose pro forma information for business combinations that occurred in the current reporting period. The disclosures include pro forma revenue and earnings of the combined entity for the current reporting period as though the acquisition date for all business combinations that occurred during the year had been as of the beginning of the annual reporting period. Since comparative financial statements are presented, the pro forma revenue and earnings of the combined entity for the comparable prior reporting period are reported as though the acquisition date for all business combinations that occurred during the current year had been as of the beginning of the comparable prior annual reporting period. The amendments in this accounting guidance are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted. The impact of this change was immaterial to our consolidated financial statements.

In January 2010, the FASB issued authoritative guidance, which enhances the usefulness of fair value measurements. The amended guidance requires both the disaggregation of information in certain existing disclosures, as well as the inclusion of more robust disclosures about valuation techniques and inputs to recurring and nonrecurring fair value measurements.

The amended guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disaggregation requirement for the reconciliation disclosure of Level 3 measurements, which is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. We adopted this new guidance effective January 1, 2011, and the adoption did not have a material impact on our consolidated financial statements.

NOTE 2—OIL AND GAS PROPERTIES

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 and depletion 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. Depletion 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 and nine months ended September 30, 2011, we recorded an impairment charge of $1.1 million and $5.4 million, respectively. There were no impairment charges for the same periods in 2010.

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 natural gas properties:


	September 30, 2011			December 31, 2010
	(in thousands)
Proved properties	$	348,629		$	178,902
Unproved properties, not subject to depletion		—			—

Total capitalized costs		348,629			178,902
Accumulated depreciation, depletion, amortization and impairment		(91,504	)		(55,119	)

Oil and gas properties, net	$	257,125		$	123,783

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


	(in thousands)
Balance at December 31, 2010	$	122,242
Liabilities incurred		147,155
Liabilities settled		(5,010	)
Accretion expense		18,471

Balance at September 30, 2011	$	282,858

NOTE 3—ACQUISITIONS

Merit Energy Corp

On May 31, 2011, we completed our previously announced purchase of certain properties from Merit Energy Corp. (the “Merit Acquisition”). We acquired interests in various properties across approximately 236,218 gross (127,764 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 the first day of the first month following closing.

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	$	148,943
Inventory		96
Gas imbalances - receivable		1,487
Less:
Gas imbalances - payable		314
Asset retirement obligations		121,164

Cash paid	$	29,048

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.

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.

The following table presents the preliminary 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	)

Nippon Acquisition

On September 30, 2010, we acquired 27 properties in the Gulf of Mexico from Nippon Oil Exploration U.S.A. Limited (the “Nippon Acquisition”). The purchase included 19 fields, for a purchase price of $5 million before normal purchase price adjustments and the assumption of $57.4 million in asset retirement obligations related to P&A obligations associated with acquired properties. The Nippon Acquisition gave us an aggregate interest in 684 gross wells on 41 platforms located across 157 thousand gross acres offshore.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on September 30, 2010:


	(in thousands)
Oil and gas properties	$	35,989
Less:
Gas imbalances		2,041
Asset retirement obligations		57,416

Cash received	$	(23,468	)

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.

Merit and Nippon Pro Forma Information

The following unaudited pro forma combined, condensed financial information for the nine months ended September 30, 2011 and for the three and nine months ended September 30, 2010 was derived from our historical financial statements giving effect to the Merit Acquisition and Nippon Acquisition as if they had occurred on January 1, 2010. These 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 acquisitions as of January 1, 2010 or the results that will be attained in the future.


	Three Months Ended September 30,			Nine Months Ended September 30,
	2010			2011		2010
	(in thousands)
Revenues	$	72,811		$	317,912	$	240,334
Earnings (1)		(3,724	)		51,243		39,838

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

The revenues and earnings of the Merit Acquisition and the Nippon Acquisition included in our consolidated statements of operations for the three and nine months ended September 30, 2011 are as follows:


	Merit Acquisition				Nippon Acquisition
	Three Months Ended September 30, 2011		Nine Months Ended September 30, 2011		Three Months Ended September 30, 2011		Nine Months Ended September 30, 2011
	(in thousands)				(in thousands)
Revenues	$	25,276	$	35,160	$	30,335	$	90,788
Earnings (1)		2,630		8,260		14,448		43,968

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

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. 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 gain (loss) on derivative financial instruments” recorded in the consolidated statements of operations.

At September 30, 2011, 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)
					(in thousands)										(in thousands)						(in thousands)
Swaps:
10/11 - 10/11		40,103	$	96.90	$	708		$	708			—	$	—	$	—		$	—		$	708		$	708
11/11 - 11/11		35,663		96.90		624			624			—		—		—			—			624			624
12/11 - 12/11		45,000		96.90		781			781			—		—		—			—			781			781
1/12 - 10/12		23,000		96.90		3,702			3,702			227,000		4.60		957			957			4,659			4,659
11/12 - 11/12		22,080		96.90		322			322			227,000		4.60		36			36			358			358
12/12 - 12/12		23,000		96.90		331			331			227,000		4.60		(29	)		(29	)		302			302
1/13 - 10/13		27,750		96.90		3,775			3,775			104,000		4.60		(168	)		(168	)		3,607			3,607
11/13 - 11/13		26,800		96.90		341			341			104,000		4.60		(34	)		(34	)		307			307
12/13 - 12/13		27,750		96.90		352			352			104,000		4.60		(58	)		(58	)		294			294
1/14 - 2/14		19,000		96.90		479			479			82,000		4.60		(110	)		(110	)		369			369
10/11 - 12/11		25,400		81.22		139			139			350,000		4.60		839			839			978			978
1/12 - 12/12		17,050		81.22		30			30			—		—		—			—			30			30
10/11 - 12/11		2,600		81.14		14			14			6,250		5.89		39			39			53			53
1/12 - 12/12		1,900		81.14		2			2			112,000		5.00		1,020			1,020			1,022			1,022
1/12 - 7/12		—		—		—			—			5,250		5.89		64			64			64			64
10/11 - 12/11		200		83.50		3			3			78,500		5.70		448			448			451			451
1/12 - 7/12		200		83.50		4			4			53,000		5.70		579			579			583			583
8/12 - 12/12		—		—		—			—			53,000		5.70		349			349			349			349
10/11 - 12/11		41,500		85.90		810			810			93,569		5.89		588			588			1,398			1,398
1/12 - 12/12		27,500		85.90		1,593			1,593			26,838		5.89		531			531			2,124			2,124
10/11 - 12/11		—		—		—			—			321,000		5.00		1,160			1,160			1,160			1,160
12/11 - 12/11		14,582		100.80		310			310			—		—		—			—			310			310
1/12 - 6/12		22,125		100.80		2,724			2,724			318,958		4.94		1,554			1,554			4,278			4,278
7/12 - 7/12		12,048		100.80		236			236			223,682		4.94		163			163			399			399
8/12 - 8/12		8,296		100.80		160			160			231,361		4.94		163			163			323			323
9/12 - 9/12		3,998		100.80		76			76			176,860		4.94		124			124			200			200
10/12 - 10/12		1,884		100.80		35			35			156,968		4.94		104			104			139			139
11/12 - 11/12		—		—		—			—			125,000		4.94		63			63			63			63
12/12 - 12/12		15,140		100.80		277			277			241,659		4.94		53			53			330			330
1/13 - 6/13		15,542		100.80		1,657			1,657			200,669		4.94		227			227			1,884			1,884
7/13 - 7/13		7,132		100.80		124			124			185,649		4.94		37			37			161			161
8/13 - 8/13		5,980		100.80		103			103			171,076		4.94		31			31			134			134
9/13 - 9/13		3,897		100.80		66			66			154,569		4.94		27			27			93			93
10/13 - 10/13		3,259		100.80		55			55			154,144		4.94		23			23			78			78
11/13 - 11/13		—		—		—			—			134,298		4.94		2			2			2			2
12/13 - 12/13		10,041		100.80		167			167			200,669		4.94		(44	)		(44	)		123			123
1/14 - 5/14		10,083		100.80		827			827			129,960		4.94		(124	)		(124	)		703			703
6/14 - 6/14		—		—		—			—			129,960		4.94		(9	)		(9	)		(9	)		(9	)
1/13 - 12/13		19,750		85.90		581			581			47,000		5.00		111			111			692			692
1/14 - 12/14		15,000		65.00		(3,551	)		(3,551	)		—		—		—			—			(3,551	)		(3,551	)
10/11 - 10/11		—		—		—			—			264,232		4.94		312			312			312			312
11/11 - 11/11		—		—		—			—			198,668		4.94		253			253			253			253
12/11 - 12/11		—		—		—			—			422,042		4.94		413			413			413			413

					$	17,857		$	17,857						$	9,694		$	9,694		$	27,551		$	27,551

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 September 30, 2011 (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	$	20,354	Current	$	(14	)
	Non-current		11,407	Non-current		(4,196	)

Total derivative instruments		$	31,761		$	(4,210	)

NOTE 5—FAIR VALUE MEASUREMENTS

We adopted authoritative guidance for fair value measurements, which 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 September 30, 2011, and indicates the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands):


	Fair Value Measurements at September 30, 2011 Using Fair Value Hierarchy
	Fair Value as of September 30, 2011			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	31,761		$	—	$	31,761		$	—

	$	31,761		$	—	$	31,761		$	—


Liabilities
Oil and Natural Gas Derivatives	$	(4,210	)	$	—	$	(4,210	)	$	—

	$	(4,210	)	$	—	$	(4,210	)	$	—

At September 30, 2011, management estimates that the derivative contracts had a fair value of $27.6 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 September 30, 2011, 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 September 30, 2011 was $171.3 million.

Fair Value on a Non-Recurring Basis

As of September 30, 2011, oil and gas properties with a carrying value of $262.5 million were written down to their fair value of $257.1 million, resulting in an impairment charge, which is recognized under “Impairments” in the consolidated statements of operations, of $1.1 million and $5.4 million for the three and nine months ended September 30, 2011, respectively. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

NOTE 6—DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:


	September 30, 2011			December 31, 2010
	(in thousands)
Senior Secured Revolving Credit Facility	$	14,000		$	—
13.75% Senior Secured Notes, net of discount		148,834			148,684
First Insurance - note payable		10,357			2,016
Synergy Bank - note payable		—			53

Total debt		173,191			150,753
Less: current portion		(10,357	)		(2,069	)

Total long-term debt	$	162,834		$	148,684

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 September 30, 2011, we had an aggregate amount of $122.7 million of indebtedness outstanding under our Credit Facility, $108.7 million that was drawn as a letter of credit in support of our P&A obligations and $14.0 million of borrowings under the revolver. We currently have $72.3 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 and nine months ended September 30, 2011, we recognized $40,829 and $0.1 million 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. In June 2011, we received a waiver related to our hedging requirements for the period ending June 30, 2011. Absent this waiver, we would not have been in compliance with this covenant. As of September 30, 2011, we were not in compliance with our hedging requirement as our notional volumes exceeded 60% for the months of July through November for the years 2011, 2012, and 2013 by 3%, 8%, and 5%, respectively, of the reasonably anticipated total volume of projected production from proved, developed, and producing oil and gas properties. In November 2011, we received a waiver related to our hedging requirements for the period ending September 30, 2011. We intend to unwind certain natural gas swap agreements by December 31, 2011 and crude oil swap agreements by June 30, 2012 to comply with hedge production levels in the covenant.

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, commencing on June 1, 2011. The Notes will mature on December 1, 2015, of which all principal then outstanding will be due. As of September 30, 2011, the recorded value of the Notes was $148.8 million, which includes the unamortized discount of $1.2 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.

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 under the First Supplemental Indenture to the 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 expenditures are not to exceed $30 million for the fiscal year ending December 31, 2011 and 25% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expenses for any fiscal year after. The 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 December 31, 2010, we were in compliance with all covenants except that we did not furnish an Annual Report for the year ended December 31, 2010 on our website that complies in all material respects with all of the rules and regulations applicable to such reports pursuant to the Notes. In May 2011, we prepared and posted an Annual Report for the year ended December 31, 2010 on our website that complies in all material respects with all of the rules and regulations applicable to such reports and included the financial statements for the year ended December 31, 2010. As of September 30, 2011, we were in compliance with our covenants related to the Notes.

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. Under certain circumstances, we may be required to pay additional cash interest beginning at 0.25% escalating to a maximum of 1% if the registration of the Notes does not occur. 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 September 30, 2011, were as follows:


Period Ending September 30,	(in thousands)
2012	$	10,357
2013		—
2014		14,000
2015		—
2016		150,000

		174,357
Unamortized discount on 13.75% Senior Secured Notes		(1,166	)


Total debt	$	173,191

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 September 30, 2011, we have accrued dividends in the amount of $2.4 million that are included in “Members’ Equity (Deficit)” on the consolidated balance sheets.

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 September 30, 2011 were as follows:


Period Ending September 30,	(in thousands)
2012	$	1,131
2013		1,244
2014		1,026
2015		1,005
2016		1,023
Thereafter		4,263

	$	9,692

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 will commence on December 2011. As of September 30, 2011, we have funded $9.1 million into the non-operating escrow account, leaving $22.1 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 September 30, 2011, we have funded $2.5 million, leaving $10.6 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 the first day of the first month following closing. As of September 30, 2011, we have funded $8.0 million, leaving $52.0 million to be funded through November 2013.

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 September 30, 2011 and December 31, 2010, we had receivables from Black Elk Energy, LLC in the amount of $22,430 and $22,430, respectively.

For the three and nine months ended September 30, 2011, we paid $0.4 million and $0.9 million, respectively, 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 September 30, 2011 and December 31, 2010, the outstanding amount due to Up and Running Solutions, LLC was $0.1 million and $0.1 million, respectively.

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, 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. As of September 30, 2011, we had accrued dividends in the amount of $2.4 million that were included in “Members’ Equity (Deficit)” on the consolidated balance sheets.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements made in this Quarterly Report on Form 10-Q (this “Form 10-Q”) that are not historical facts are “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements may include statements that relate to, among other things:

•

Forward-looking 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.

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,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from the anticipated future results or financial condition expressed or implied by the forward-looking statements. These risks, uncertainties and other factors include, but are not limited to:

•

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;

•

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.

Other factors that could cause our actual results to differ materially from those indicated by our forward-looking statements are those discussed in (1) “Item 1A—Risk Factors” in this Form 10-Q; (2) “Risk Factors” in our Registration Statement on Form S-4/A (Amendment No. 1), which was filed with the SEC on June 29, 2011 (the “Form S-4/A”); (3) our reports and registration statements filed from time to time with the SEC; and (4) other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this filing. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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 a privately held 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 economically maximize properties that are currently producing or have the potential to produce given the needed attention and capital resources. We believe that our strategy provides assets to develop and produce with minimal risk, cost or time of traditional exploration. 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.

We have financed our acquisitions to date through a combination of cash flows provided by operating activities, borrowings under lines of credit, 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 the Indenture governing the Notes, 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 if we believe that the reservoirs still 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, West Cameron 66.

In the fourth quarter of 2009, we completed the W&T Acquisition, purchasing over 35 fields and 350 wells primarily located on the Gulf of Mexico Shelf and encompassing an approximate 71,000 net (195,000 gross) acres.

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 6,400 net (13,900 gross) acres to our portfolio. On September 30, 2010, we acquired 27 properties in the Gulf of Mexico from Nippon Oil Exploration U.S.A. The Nippon Acquisition included 223 wellbores, 41 platforms, and 19 producing fields.

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 43 (105 gross) wells and approximately 22,200 net (45,500 gross) 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 236,218 gross (127,764 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 Class D Units.

As of September 30, 2011, we held an aggregate net interest in approximately 294,400 (655,100 gross) acres under lease and had an interest in 1,235 gross wells, 384 of which are producing.

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 and nine months ended September 30, 2011 and 2010 are shown in the table below.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Oil:
Average price before effects of hedges ($/Bbl)⁽¹⁾	$	102.56	$	76.36	$	105.44	$	76.39
Average price after effects of hedges ($/Bbl)		107.64		81.07		102.51		79.20
Average price differentials⁽²⁾		13.05		0.27		10.05		(1.19	)

Gas:
Average price before effects of hedges ($/Mcf)⁽¹⁾	$	4.28	$	4.37	$	4.43	$	4.60
Average price after effects of hedges ($/Mcf)		5.03		5.34		5.03		5.61
Average price differentials⁽²⁾		0.16		0.09		0.21		0.04

(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 lasting well into 2010 and economic conditions continue to remain uncertain. These uncertain economic conditions reduced demand for oil and natural gas, resulting in a decline in oil and natural gas prices received for our production in 2010. While oil prices have strengthened over the past few months, they 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.

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 Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) of the U.S. Department of the Interior 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, 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. Only recently, 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 the newly 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.

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 and nine months ended September 30, 2011 and 2010:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
Average daily sales:
Oil (Boepd)		5,985		1,665			5,108		1,857
Natural gas (Mcfpd)		56,917		17,366			47,451		17,638
Plant products (Gal/d)		29,090		9,926			28,393		8,172
Oil equivalents (Boepd)		16,164		4,796			13,693		4,991
Average realized prices⁽¹⁾
Oil ($/Bbl)	$	107.64	$	81.07		$	102.51	$	79.20
Natural gas ($/Mcf)		5.03		5.34			5.03		5.61
Plant products ($/Gallon)		1.40		1.03			1.25		1.02
Oil equivalents ($/Boe)		60.09		49.61			58.26		50.97
Lease operating expense ($/Boe)		31.69		26.36			26.75		21.22
Production tax expense ($/Boe)		0.16		0.17			0.12		0.34
General and administrative expense ($/Boe)		3.36		6.01			4.51		5.16
Net income (loss) (in thousands)		51,114		(6,042	)		55,041		5,646
Adjusted EBITDA⁽²⁾ (in thousands)		32,349		6,251			87,076		31,787

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

(2)

Adjusted EBITDA is defined as net income (loss) before interest expense, income taxes, depreciation and amortization, impairment, accretion, unrealized gain/loss on derivative instruments, and gain on sale of asset. 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.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Net income (loss)	$	51,114		$	(6,042	)	$	55,041		$	5,646
Adjusted EBITDA	$	32,349		$	6,251		$	87,076		$	31,787

Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss)	$	51,114		$	(6,042	)	$	55,041		$	5,646
Interest expense		6,873			2,262			19,275			6,526
Unrealized (gain) loss on derivative instruments		(50,234	)		1,578			(43,006	)		(5,796	)
Accretion		9,089			1,831			18,471			5,495
Depreciation, depletion, amortization and impairment		15,507			6,622			37,437			19,916
Gain on sale of asset		—			—			(142	)		—


Adjusted EBITDA	$	32,349		$	6,251		$	87,076		$	31,787

Set forth below is an explanation of certain of the expenses and other financial items that we disclose in our financial statements. We utilize the successful efforts method of accounting for our oil and natural gas properties.

Derivative (losses) gains. We utilize certain commodity-derivative contracts to manage our exposure to oil and gas price volatility. The oil and gas reference prices of these commodity-derivatives contracts were based upon futures that have a high degree of correlation with actual prices we receive. Under this method, realized gains and losses from our price risk management activities were recognized in operating revenue when the associated production occurred and the resulting cash flows were reported as cash flows from operations.

Lease operating costs. Lease operating costs consists of costs and expenses incurred to manage our production facilities and development operations, overhead, well control expenses and repairs and maintenance charges.

Workover costs. Workover costs are expenses incurred during the operations of a producing well to restore or increase production.

Depreciation, depletion, amortization and impairment. All capitalized costs of proved oil and natural gas properties are depleted through depreciation, depletion and amortization (“DD&A”) using the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental wells and productive leases are capitalized into the appropriate groups based on geographical and geophysical similarities. These capitalized costs are depleted using the units-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of depletion base is sold or abandoned.

We follow the provisions of authoritative guidance for impairment or disposal of long-lived assets. This guidance requires that long lived assets, including oil and gas properties, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Impairment is determined to have occurred when the estimated undiscounted cash flows of the asset are less than its carrying value. Any such impairment is recognized and recorded based on the differences in carrying value and estimated fair value of the impaired asset.

Unevaluated properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to accumulated amortization.

General and administrative expenses. General and administrative expenses (“G&A expense”) include payroll and benefits for our corporate staff, costs of maintaining our headquarters, certain data processing charges, property taxes, audit and other professional fees and legal compliance.

Accretion expense. Accretion expense is associated with our asset retirement obligation liability and is recognized each period using the interest method of allocation. The capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon our interim review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate.

Interest expense. Interest expense reflects interest incurred on our outstanding debt instruments.

Income tax provision. We report as a partnership for federal income tax purposes. Our taxable income or loss is therefore passed through to our members and reported on their respective tax returns. Accordingly, no provision for federal income taxes has been recorded in these financial statements. We are subject to the Texas Gross Margin Tax. The Texas Gross Margin Tax generally is calculated as 1% of gross margin.

Results of Operations

The following table sets forth certain information with respect to oil and gas operations for the three and nine months ended September 30, 2011 and 2010:


	Three Months Ended September 30,												Nine Months Ended September 30,
	2011			2010			Change			% Change			2011			2010			Change			% Change

PRODUCTION:
Oil (MBbl)		551			153			398			260	%		1,395			507			888			175	%
Natural gas (MMcf)		5,236			1,598			3,638			228	%		12,954			4,815			8,139			169	%
Plant products (MGal)		2,676			913			1,763			193	%		7,751			2,231			5,520			247	%
Total (Mboe)		1,487			441			1,046			237	%		3,738			1,363			2,375			174	%

REVENUES:
Oil sales	$	56,470		$	11,699		$	44,771			383	%	$	147,038		$	38,727		$	108,311			280	%
Natural gas sales		22,398			6,980			15,418			221	%		57,388			22,138			35,250			159	%
Plant product sales and other revenue		5,500			1,417			4,083			288	%		13,614			4,341			9,273			214	%
Realized gain on derivative financial instruments		6,746			2,272			4,474			197	%		3,664			6,312			(2,648	)		-42	%
Unrealized gain (loss) on derivative financial instruments		50,234			(1,578	)		51,812			-3283	%		43,006			5,796			37,210			642	%

TOTAL REVENUES		141,348			20,790			120,558			580	%		264,710			77,314			187,396			242	%

OPERATING EXPENSES:
Lease operating		47,125			11,634			35,491			305	%		100,000			28,909			71,091			246	%
Production taxes		231			77			154			200	%		439			464			(25	)		-5	%
Workover		6,053			961			5,092			530	%		11,599			2,004			9,595			479	%
Exploration		—			169			(169	)		-100	%		—			707			(707	)		-100	%
Depreciation, depletion and amortization		14,411			6,622			7,789			118	%		32,018			19,916			12,102			61	%
Impairment		1,096			—			1,096			100	%		5,419			—			5,419			100	%
General and administrative		4,991			2,651			2,340			88	%		16,862			7,025			9,837			140	%
Accretion		9,089			1,831			7,258			396	%		18,471			5,495			12,976			236	%
Gain on sale of asset		—			—			—			0	%		(142	)		—			(142	)		-100	%

TOTAL OPERATING EXPENSES		82,996			23,945			59,051			247	%		184,666			64,520			120,146			186	%


INCOME (LOSS) FROM OPERATIONS		58,352			(3,155	)		61,507			-1950	%		80,044			12,794			67,250			526	%

OTHER INCOME (EXPENSE):
Interest income		131			61			70			115	%		358			64			294			459	%
Miscellaneous expense		(496	)		(686	)		190			-28	%		(6,086	)		(686	)		(5,400	)		787	%
Interest expense		(6,873	)		(2,262	)		(4,611	)		204	%		(19,275	)		(6,526	)		(12,749	)		195	%

TOTAL OTHER EXPENSE		(7,238	)		(2,887	)		(4,351	)		151	%		(25,003	)		(7,148	)		(17,855	)		250	%


NET INCOME (LOSS)	$	51,114		$	(6,042	)	$	57,156			-946	%	$	55,041		$	5,646		$	49,395			875	%

Production

Oil and natural gas production. Total oil, natural gas and plant product production of 1,487 MBoe and 3,738 MBoe increased 1,046 MBoe, or 237%, and 2,375 MBoe, or 174%, during the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010. The increase in production during 2011 was primarily a result of properties acquired in the Nippon Acquisition in September 2010, the Maritech Acquisition in February 2011 and the Merit Acquisition in May 2011.

Revenues

Total revenues. Total revenues for the three and nine months ended September 30, 2011 of $141.3 million and $264.7 million increased $120.6 million, or 580%, and $187.4 million, or 242%, over the comparable periods in 2010. The increase in revenues during 2011 was a result of increased production related to the properties acquired in the Nippon Acquisition, the Maritech Acquisition, and the Merit Acquisition as well as higher oil prices. Total revenues were also higher due to a $50.2 million and $43.0 million unrealized gain on derivative financial instruments for the three and nine months ended September 30, 2011, respectively.

We entered into certain oil and natural gas commodity derivative contracts in 2011 and 2010. We realized gains on these derivative contracts in the amounts of $6.7 million and $3.7 million for the three and nine months ended September 30, 2011, respectively. For the three and nine months ended September 30, 2010, we realized gains of $2.3 million and $6.3 million, respectively. We recognized unrealized gains of $50.2 million and $43.0 million for the three and nine months ended September 30, 2011. For the three and nine months ended September 30, 2010, we recognized an unrealized (loss) gain of ($1.6) million and $5.8 million, respectively. Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, increased $64.3 million and $152.8 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010 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 $102.56 per barrel and $76.36 per barrel and gas prices of $4.28 per Mcf and $4.37 per Mcf for the three months ended September 30, 2011 and 2010, respectively. Excluding hedges, for the nine months ended September 30, 2011 and 2010, we realized average oil prices of $105.44 per barrel and $76.39 per barrel and gas prices of $4.43 per Mcf and $4.60 per Mcf, respectively. Although average prices realized from the sale of oil reflected the economic turnaround that began during 2010, 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 and nine months ended September 30, 2011 increased to $47.1 million, or $31.69 per Boe, and $100.0 million, or $26.75 per Boe, respectively. For the three and nine months ended September 30, 2010, our lease operating costs were $11.6 million, or $26.36 per Boe, and $28.9 million, or $21.22 per Boe, respectively. The increase in lease operating costs during 2011 is directly related to the increase in properties from the Nippon Acquisition, the Maritech Acquisition and the Merit Acquisition. The increase in cost per Boe during 2011 is primarily attributable to a mix of increased properties and the related workover activities.

Workover costs. Our workover costs for the three and nine months ended September 30, 2011 increased $5.1 million and $9.6 million, respectively, compared to the same periods in 2010. For the three months ended September 30, 2011, High Island 571, High Island 370 and East Cameron 148/160 were the primary workover expense projects. For the nine months ended September 30, 2011, the primary workover expense projects were High Island 571, South Timbalier 8 and South Pass 89.

Depreciation, depletion, amortization and impairment. DD&A expense was $14.4 million, or $9.69 per Boe, and $32.0 million, or $8.57 per Boe, for the three and nine months ended September 30, 2011, respectively, and $6.6 million, or $15.01 per Boe, and $19.9 million, or $14.62 per Boe, for the three and nine months ended 2010, respectively. In 2011, the increase in DD&A was the result of increased production associated with the properties acquired in 2011 and 2010. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded $1.1 million and $5.4 million in impairments for the three and nine months ended September 30, 2011, respectively, as the estimated undiscounted cash flows of oil and gas properties are less than its carrying value. We did not recognize impairments in 2010 for the same periods.

General and administrative expenses. G&A expense was $5.0 million, or $3.36 per Boe, and $16.9 million, or $4.51 per Boe, for the three and nine months ended September 30, 2011, respectively, and $2.7 million, or $6.01 per Boe, and $7.0 million, or $5.16 per Boe, for the three and nine months ended 2010, respectively. The increase in G&A expense in 2011 resulted principally from costs associated with the increase in staff and related administrative costs attributable to our growth in 2011 and 2010.

Accretion expense. We recognized accretion expense of $9.1 million and $18.5 million for the three and nine months ended September 30, 2011, respectively, compared to $1.8 million and $5.5 million for the three and nine months ended September 30, 2010, respectively. The increase in accretion expense in 2011 was attributable to assumed asset retirement obligations related to our acquisitions in 2011 and 2010.

Miscellaneous expense. Miscellaneous expense decreased $0.2 million and increased $5.4 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010. The significant year-to-date increase was a result of the consent solicitation fee paid under the First Supplemental Indenture to the Indenture.

Interest expense. Interest expense increased $4.6 million and $12.7 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010. The increase of interest expense in 2011 compared to 2010 was a result of borrowing on the Credit Facility to fund the Merit P&A obligation, the issuance of the Notes in November 2010, the proceeds of which were used to fund the Nippon Acquisition and associated escrow deposits for future P&A costs, and amortization of credit debt issuance costs as a result of the repayment of loans with proceeds from the Notes, which was partially offset by lower fixed interest rates.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from our members, proceeds from the senior notes, 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 a (1) $35 million senior secured revolver and a (2) $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. 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.

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.

In June 2011, we received a waiver related to our hedging requirements for the period ending June 30, 2011. Absent this waiver, we would not have been in compliance with this covenant. As of September 30, 2011, we were not in compliance with our hedging requirement as our notional volumes exceeded 60% for the months of July through November for the years 2011, 2012, and 2013 by 3%, 8%, and 5%, respectively, of the reasonably anticipated total volume of projected production from proved, developed, and producing oil and gas properties. In November 2011, we received a waiver related to our hedging requirements for the period ending September 30, 2011. We intend to unwind certain natural gas swap agreements by December 31, 2011 and crude oil swap agreements by June 30, 2012 to comply with hedge production levels in the covenant.

As of September 30, 2011, letters of credit in the aggregate amount of $108.7 million were outstanding under this facility and we had $14.0 million in borrowings under the revolver. As of November 1, 2011, $62.3 million was available for additional borrowings, including $46.0 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, exceeds $5.0 million to the extent permitted by our 13.75% Senior Secured 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 under the First Supplemental Indenture to the Indenture. 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 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.

On July 20, 2011, pursuant to the terms of a registration rights agreement, we initiated an offer to exchange our outstanding Notes for a new issue of debt securities on substantially identical terms that are registered under the Securities and Exchange Act of 1934. The exchange offer expired on August 19, 2011 with all of the outstanding Notes being tendered.

As of September 30, 2011, we were in compliance with our covenants as they are related to the Notes.

Member Contributions

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%.

Capital Expenditure Budget

We expect total capital expenditures to be $50.3 million for 2011 (excluding expenditures directly related to any acquisitions, including the Merit Acquisition, which closed on May 31, 2011 for a purchase price of approximately $39 million). Approximately $20.2 million was expended in the first nine months of 2011 for various projects including recompletions and drilling, and the remaining $30.1 million will be used for drilling and development during the remainder of the year. The 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.

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 2011 capital expenditures have been funded from contributions from our members, 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 2011 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 nine months ended September 30, 2011 and 2010:


	Nine Months Ended September 30,
	2011			2010
	(in thousand)
Net cash provided by operating activities	$	53,535		$	24,926
Net cash used in investing activities		(92,291	)		(59,402	)
Net cash provided by financing activities		36,006			35,415

Net increase (decrease) in cash and equivalents	$	(2,750	)	$	939

Cash flows provided by operating activities. Cash provided by operating activities totaling $53.5 million during the nine months ended September 30, 2011 compared to $24.9 million during the nine months ended September 30, 2010. The increase in operating cash flows was principally attributable to higher net income as a result of the 2010 and 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.

Cash flows used in investing activities. Cash used in investing activities totaling $92.3 million in the nine months ended September 30, 2011 is primarily attributable to the assets purchased in the Maritech Acquisition and Merit Acquisition and the funding of the future P&A obligations through escrow; cash used in investing activities in the comparable period of 2010 totaling $59.4 million is attributable to the assets purchased in the period and the funding of the escrow for future P&A obligations. The Nippon assets were purchased on September 30, 2010.

Cash flows provided by financing activities. Cash flows provided by financing activities of $36.0 million in the nine months ended September 30, 2011 were attributable to borrowings on the Credit Facility and short term notes as well as a $30 million contribution from Platinum, which were partially offset by payments on the Credit Facility, debt issuance costs of the Notes, and distributions to members. Cash flows provided by financing of $35.4 million during the nine months ended September 30, 2010 related primarily to the borrowing and repayment of debt as well as distributions to members.

Asset Retirement Obligations

As many as four times per year we review, and, to the extent necessary, revise our asset retirement obligation estimates. In 2010, we increased our asset retirement obligations by $70.9 million, primarily as a result of the Nippon Acquisition, and recognized $9.2 million in accretion expense. As of September 30, 2011, we increased our asset retirement obligation by $160.6 million primarily as a result of the Maritech Acquisition and Merit Acquisition and for the three and nine months ended September 30, 2011, we recognized $9.1 million and $18.5 million in accretion expense, respectively.

At September 30, 2011 and December 31, 2010, we recorded total asset retirement obligations of $282.8 million and $122.2 million, respectively, and have funded approximately $161.0 million and $114.2 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds. As of September 30, 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.

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 September 30, 2011:


	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	$	174,357	$	10,357	$	14,000	$	150,000	$	—
Interest on debt and notes payable		87,475		21,344		42,068		24,063		—
Operating leases (1)		9,692		1,131		2,270		2,028		4,263

Total contractual obligations		271,524		32,832		58,338		176,091		4,263
Other Obligations
Asset retirement obligations (2)		282,858		16,514		178,584		46,652		41,108

Total obligations	$	554,382	$	49,346	$	236,922	$	222,743	$	45,371

(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. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future. At September 30, 2011, the balance of the loan was $3.0 million and has a maturity date of October 8, 2013.

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.

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.

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 Annual Report, located on our website.

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 and nine months ended September 30, 2011, we received an average of $102.56 and $105.44 per barrel of oil and $4.28 and $4.43 per Mcf of natural gas, respectively, before consideration of commodity derivative contracts compared to $76.36 and $76.39 per barrel of oil and $4.37 and $4.60 per Mcf of natural gas, respectively, in the three and nine months ended September 30, 2010. 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 2011 as a result of the improvements in oil prices in 2010 and 2011.

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 average daily production for the nine months ended September 30, 2011, our annual revenue would increase or decrease by approximately $18.6 million for each $10.00 per barrel change in oil prices and $17.3 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging. Based on our average daily production for the year ended December 31, 2010, our revenues would have increased or decreased by approximately $13.3 million for each $10.00 per barrel change in oil prices and $14.6 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 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 September 30, 2011, the fair value of our commodity derivatives were included in the consolidated balance sheets for approximately $20.3 million as current assets and $7.2 million as long-term assets. At December 31, 2010, the fair value of our commodity derivatives were $3.8 million as current liabilities and $11.7 million as long-term liabilities. For the three and nine months ended September 30, 2011, we realized a net increase in oil and natural gas revenues related to hedging transactions of approximately $6.7 million and $3.7 million, respectively, and an increase for the same periods in 2010 of $2.3 million and $6.3 million, respectively.

As September 30, 2011, we maintained the following commodity derivative contracts:


Remaining Contract Term: Oil	Contract Type	Notational Volume in Bbls/Month		NYMEX Strike Price
January 2014 - December 2014	Swap		15,000	$	65.00
January 2012 - December 2012	Swap		1,900	$	81.14
October 2011- December 2011	Swap		2,600	$	81.14
January 2012 - December 2012	Swap		17,050	$	81.22
October 2011 - December 2011	Swap		25,400	$	81.22
January 2012 - July 2012	Swap		200	$	83.50
October 2011 - December 2011	Swap		200	$	83.50
January 2013 - December 2013	Swap		19,750	$	85.90
January 2012 - December 2012	Swap		27,500	$	85.90
October 2011 - December 2011	Swap		41,500	$	85.90
January 2014 - February 2014	Swap		19,000	$	96.90
November 2012 - November 2012	Swap		22,080	$	96.90
December 2012 - December 2012	Swap		23,000	$	96.90
January 2012 - October 2012	Swap		23,000	$	96.90
November 2013 - November 2013	Swap		26,805	$	96.90
December 2013 - December 2013	Swap		27,750	$	96.90
January 2013 - October 2013	Swap		27,750	$	96.90
November 2011- November 2011	Swap		35,663	$	96.90
October 2011 - October 2011	Swap		40,103	$	96.90
December 2011 - December 2011	Swap		45,000	$	96.90
October 2012 - October 2012	Swap		1,884	$	100.80
October 2013 - October 2013	Swap		3,259	$	100.80
September 2013 - September 2013	Swap		3,897	$	100.80
September 2012 - September 2012	Swap		3,998	$	100.80
August 2013 - August 2013	Swap		5,980	$	100.80
July 2013 - July 2013	Swap		7,132	$	100.80
August 2012 - August 2012	Swap		8,296	$	100.80
December 2013 - December 2013	Swap		10,042	$	100.80
January 2014 - May 2014	Swap		10,083	$	100.80
July 2012 - July 2012	Swap		12,048	$	100.80
December 2011 - December 2011	Swap		14,582	$	100.80
December 2012 - December 2012	Swap		15,140	$	100.80
January 2013 - June 2013	Swap		15,542	$	100.80
January 2012 - June 2012	Swap		22,125	$	100.80


Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month		NYMEX Strike Price
January 2014 - February 2014	Swap		82,000	$	4.60
January 2013 - October 2013	Swap		104,000	$	4.60
January 2012 - October 2012	Swap		227,000	$	4.60
December 2011 - December 2011	Swap		350,000	$	4.60
November 2012 - November 2012	Swap		125,000	$	4.94
January 2014 - May 2014	Swap		129,960	$	4.94
June 2014 - June 2014	Swap		129,960	$	4.94
November 2013 - November 2013	Swap		134,298	$	4.94
October 2013 - October 2013	Swap		154,144	$	4.94
September 2013 - September 2013	Swap		154,569	$	4.94
October 2012 - October 2012	Swap		156,968	$	4.94
August 2013 - August 2013	Swap		171,076	$	4.94
September 2012 - September 2012	Swap		176,860	$	4.94
July 2013 - July 2013	Swap		185,649	$	4.94
November 2011 - November 2011	Swap		198,668	$	4.94
January 2013 - June 2013	Swap		200,669	$	4.94
December 2013 - December 2013	Swap		200,669	$	4.94
July 2012 - July 2012	Swap		223,682	$	4.94
August 2012 - August 2012	Swap		231,361	$	4.94
December 2012 - December 2012	Swap		241,659	$	4.94
October 2011 - October 2011	Swap		264,232	$	4.94
January 2012 - June 2012	Swap		318,958	$	4.94
December 2011 - December 2011	Swap		422,042	$	4.94
January 2013 - December 2013	Swap		47,000	$	5.00
January 2012 - December 2012	Swap		112,000	$	5.00
October 2011 - December 2011	Swap		321,000	$	5.00
January 2012 - July 2012	Swap		53,000	$	5.70
October 2011 - December 2011	Swap		78,500	$	5.70
January 2012 - July 2012	Swap		5,250	$	5.89
October 2011 - December 2011	Swap		6,250	$	5.89
January 2012 - December 2012	Swap		26,838	$	5.89
October 2011 - December 2011	Swap		93,569	$	5.89

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 $7.7 million at September 30, 2011 and $4.2 million at December 31, 2010. 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 $30.0 million at September 30, 2011 and $21.8 million at December 31, 2010.

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.

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 $122.7 million outstanding under the Credit Facility as of September 30, 2011, an increase of 100 basis points in the underlying interest rate would have had a $1.2 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 September 30, 2011.

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 September 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 greater than $0.1 million of which we are in the process of an appeal to the Interior Board of Land Appeals (“IBLA”).

We are also subject to other environmental matters and regulation. For a discussion of these items, see “Environmental Matters and Regulation” in our Form S-4/A.

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 Form S-4/A. The risks described in the Form S-4/A could materially and adversely affect our business, financial condition, cash flows, and results of operations. Except as set forth below, there have been no material changes to the risks described in the Form S-4/A. 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.

Recently Proposed Rules Regulating Air Emissions from Oil and Gas Operations Could Cause Us to Incur Increased Capital Expenditures and Operating Costs.

On July 28, 2011, the Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. EPA’s proposal would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

The BOEMRE’s separation into two separate bureaus may result in significant added delays and expense in connection with the performance of our operations.

Effective October 1, 2011, BOEMRE was split into two federal bureaus, the Bureau of Ocean Energy Management (“BOEM”), which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies, and the Bureau of Safety and Environmental Enforcement (“BSEE”), which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, we are 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.

Item 5. Other Information

As of September 30, 2011, we were not in compliance with the hedging requirement contained in Section 9.17 of Credit Agreement dated December 24, 2010 (as amended by that First Amendment dated May 31, 2011 and as further amended, restated, supplemented or modified from time to time, the “Credit Agreement”) as our notional volumes exceeded 60% for the months of July through November for the years 2011, 2012, and 2013 by 3%, 8%, and 5%, respectively, of the reasonably anticipated total volume of projected production from proved, developed, and producing oil and gas properties. We received a waiver dated to be effective as of September 30, 2011 for the relevant period of non-compliance of the natural gas hedging requirement until December 31, 2011 and the crude oil hedging requirement until June 30, 2012. In return for the waiver, we have agreed to unwind some of our hedges by the stated periods to be in compliance.

In connection with the above, we entered into the Waiver, dated to be effective as of September 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, as the Borrower, Black Elk Energy Finance Corp. and Black Elk Energy Land Operations, LLC, as Guarantors, and Capital One, N.A., as Administrative Agent, Issuing Bank and Lender (the “Waiver ”). Pursuant to the Waiver, the Administrative Agent and Lenders waived compliance with the covenant contained in Section 9.17 of the Credit Agreement to the extent required to avoid an Event of Default until December 31, 2011 for the natural gas swap agreements and June 30, 2012 for the crude oil swap agreements at which time we will comply with such covenants and unwind all swap agreements necessary for such compliance.

The foregoing description of the Waiver, is qualified in its entirety by the full text of such agreement which is filed as Exhibit 10.1 to this Quarterly Report on Form 10-Q and incorporated by reference herein.

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)).

*10.1		Waiver, dated to be effective as of September 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders.

*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

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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.

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: November 10, 2011	By:	/s/ James Hagemeier
		James Hagemeier
		Vice President, Chief Financial Officer and Manager (Duly Authorized Officer and Principal Financial Officer)

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)).

*10.1		Waiver, dated to be effective as of September 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders.

*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

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