Black Elk Energy Offshore Operations 10-Q 2012 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

or

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

For the transition period from          to         

Commission File Number: 333-174226

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

(Exact name of registrant as specified in its charter)

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

(281) 598-8600

Registrant’s telephone number, including area code

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

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

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

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

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

As of November 9, 2012, there were 136.13 Class A Units, 10,934.585 Class B Units, 1,203.125 Class C Units and 30,000,000 Class D Units issued and outstanding.

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2012

TABLE OF CONTENTS

		Page
Part I. Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011		1
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011		2
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011		3
	Notes to Consolidated Financial Statements		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		28
Item 4.	Controls and Procedures		32
Part II. Other Information
Item 1.	Legal Proceedings		33
Item 1A.	Risk Factors		33
Item 5.	Other Information		33
Item 6.	Exhibits		35
Signatures			37
Exhibit Index			38

(i)

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	September 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,647		$	17,260
Accounts receivable, net		41,785			52,299
Due from affiliates		164			163
Prepaid expenses and other		33,557			26,637
Derivative assets		7,257			4,216
TOTAL CURRENT ASSETS		100,410			100,575
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $156,980 and $114,056 at September 30, 2012 and December 31, 2011, respectively		217,385			238,702
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $1,485 and $870 at September 30, 2012 and December 31, 2011, respectively		1,882			2,245
OTHER ASSETS
Debt issue costs, net		8,293			8,726
Derivative assets		2,218			—
Asset retirement obligation escrow receivable		20,348			20,348
Escrow for abandonment costs		211,031			172,153
Other assets		3,157			3,257
TOTAL OTHER ASSETS		245,047			204,484
TOTAL ASSETS	$	564,724		$	546,006
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	75,046		$	72,309
Asset retirement obligations		19,609			15,238
Current portion of debt and notes payable		8,858			4,154
TOTAL CURRENT LIABILITIES		103,513			91,701
LONG-TERM LIABILITIES
Gas imbalance payable		1,885			1,362
Dividends payable		10,176			4,200
Derivative liabilities		—			2,116
Asset retirement obligations, net of current portion		282,682			273,448
Debt, net of current portion, net of unamortized discount of $942 and $1,113 at September 30, 2012 and December 31, 2011, respectively		205,558			172,887
TOTAL LONG-TERM LIABILITIES		500,301			454,013
TOTAL LIABILITIES		603,814			545,714
COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY (DEFICIT)		(39,090	)		292
TOTAL LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)	$	564,724		$	546,006

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

1

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
REVENUES:
Oil sales	$	50,721		$	56,470		$	165,441		$	147,038
Natural gas sales		13,289			22,398			36,754			57,388
Plant product sales and other revenue		5,960			5,500			19,141			13,614
Realized gain on derivative financial instruments		3,284			6,746			11,189			3,664
Unrealized (loss) gain on derivative financial instruments		(16,129	)		50,234			7,375			43,006
TOTAL REVENUES		57,125			141,348			239,900			264,710
OPERATING EXPENSES:
Lease operating		43,840			47,125			131,055			100,000
Production taxes		192			231			744			439
Workover		4,395			6,053			10,485			11,599
Exploration		311			—			1,249			—
Depreciation, depletion and amortization		12,302			14,411			36,546			32,018
Impairment		3,681			1,096			6,992			5,419
General and administrative		8,301			4,991			20,668			16,862
Accretion		9,256			9,089			27,228			18,471
Loss (gain) on sale of asset		—			—			120			(142	)
TOTAL OPERATING EXPENSES		82,278			82,996			235,087			184,666
(LOSS) INCOME FROM OPERATIONS		(25,153	)		58,352			4,813			80,044
OTHER INCOME (EXPENSE):
Interest income		11			131			305			358
Miscellaneous expense		(919	)		(496	)		(2,408	)		(6,086	)
Interest expense		(6,514	)		(6,873	)		(19,422	)		(19,275	)
TOTAL OTHER EXPENSE		(7,422	)		(7,238	)		(21,525	)		(25,003	)
NET (LOSS) INCOME		(32,575	)		51,114			(16,712	)		55,041
PREFERRED UNIT DIVIDENDS		2,232			1,800			5,976			2,400
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	(34,807	)	$	49,314		$	(22,688	)	$	52,641

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

2

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(16,712	)	$	55,041
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, and amortization		36,546			32,018
Impairment of oil and gas properties		6,992			5,419
Accretion of asset retirement obligations		27,228			18,471
Amortization of debt issue costs		3,455			1,999
Accretion of debt discount		171			150
Unrealized gain on derivative instruments		(7,375	)		(43,006	)
Loss (gain) on sale of asset		120			(142	)
Changes in operating assets and liabilities:
Accounts receivable		10,514			(17,914	)
Due from affiliates, net		(1	)		163
Prepaid expenses and other assets		(6,920	)		(18,516	)
Accounts payable and accrued liabilities		2,737			30,818
Gas imbalance		896			(5,956	)
Settlement of asset retirement obligations		(13,623	)		(5,010	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		44,028			53,535
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(18,153	)		(20,056	)
Acquisition of oil and gas properties		(3,454	)		(23,509	)
Sale of oil and gas properties		(120	)		150
Additions to property and equipment		(252	)		(1,517	)
Deposits		(272	)		(540	)
Escrow payments		(38,878	)		(46,819	)
NET CASH USED IN INVESTING ACTIVITIES		(61,129	)		(92,291	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on short term notes		17,644			8,288
Payments on short term notes		(12,940	)		—
Borrowings on bank debt		145,000			134,410
Payments on bank debt		(112,500	)		(120,410	)
Debt issuance costs		(3,022	)		(2,677	)
Contributions from members		—			30,000
Distributions to members		(16,694	)		(13,605	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		17,488			36,006
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		387			(2,750	)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD		17,260			18,879
CASH AND CASH EQUIVALENTS - END OF PERIOD	$	17,647		$	16,129
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	12,603		$	11,476
NONCASH INVESTING AND FINANCING ACTIVITIES:
Increase in oil and gas properties for asset retirement obligations	$	—		$	147,155
Increase in asset retirement obligation escrow receivable	$	—		$	20,348
Paid-in-kind dividends on preferred equity and accrued distributions to members	$	5,976		$	2,400

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

3

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(Unaudited)

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

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

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

Reclassifications: Certain reclassifications have been made to conform 2011 balances to our 2012 presentation. Such reclassifications had no effect on net income or cash flow.

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

Use of Estimates in Preparation of Financial Statements: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the 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.

Revenue Recognition:Oil and natural gas revenues are recorded using the sales method whereby we recognize revenues based on the amount of oil and natural gas sold to purchasers. We produce plant products such as ethane, butane, propane and other product as part of processing our natural gas. These products are sold to certain gas processing plants. All natural gas revenues are reported net of the plant products.

We do not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exits; (ii) delivery has occurred or services have been rendered; (iii) the seller’s price to the buyer is fixed or determinable; and (iv) collectability is reasonable assured.

We record revenues based on physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create gas imbalances that we recognize as a receivable (payable) when there are not sufficient reserves to make up the gas imbalance. A gas imbalance receivable (payable) can also be a result of imbalances acquired in conjunction with the acquisition of oil and gas properties. At September 30, 2012 and December 31, 2011, our net gas receivable (payable) imbalances were $0.5 million and $1.4 million, respectively.

4

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

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

NOTE 2—OIL AND GAS PROPERTIES

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

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

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural gas properties by field to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices. For the three and nine months ended September 30, 2012, we recorded impairment charges of $3.7 million and $7.0 million, respectively. For the three and nine months ended September 30, 2011, we recorded impairment charges of $1.1 million and $5.4 million, respectively.

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.

5

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

	September 30,			December 31,
	2012			2011
	(in thousands)
Proved properties	$	374,365		$	352,758
Unproved properties, not subject to depletion		—			—
Total capitalized costs		374,365			352,758
Accumulated depreciation, depletion, amortization and impairment		(156,980	)		(114,056	)
Oil and gas properties, net	$	217,385		$	238,702

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

	(in thousands)
Balance at December 31, 2011	$	288,686
Liabilities settled		(13,623	)
Accretion expense		27,228
Balance at September 30, 2012	$	302,291

NOTE 3—ACQUISITIONS

Merit Energy Corp.

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

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

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

In order to consummate this acquisition, we commenced a Consent Solicitation that was completed on May 31, 2011 (the “Consent Solicitation”) to amend the maximum capital expenditures provision of the indenture (together with the amendments and supplements thereto, 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.

6

The following table presents the 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	$	153,404
Gas imbalances - receivable		1,487
Less:
Gas imbalances - payable		314
Asset retirement obligations		121,164
Cash paid	$	33,413

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.

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

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

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

NOTE 4—DERIVATIVE INSTRUMENTS

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

7

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

8

At September 30, 2012, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss)):

	Crude Oil											Natural Gas									Total
Period	Volume (Bbls)		Contract Price ($/Bbl)		Asset (Liability)				Fair Value Gain (Loss)			Volume (MMBtu)		Contract Price ($/MMBtu)		Asset (Liability)			Fair  Value Gain (Loss)		Asset (Liability)			Fair Value Gain (Loss)
					(in thousands)											(in thousands)					(in thousands)
Swaps:
10/12 - 10/12		23,000	$	96.90	$	106			$	106			227,000	$	4.60	$	357		$	357	$	463		$	463
11/12 - 11/12		22,080		96.90		92				92			227,000		4.60		289			289		381			381
12/12 - 12/12		23,000		96.90		86				86			227,000		4.60		222			222		308			308
1/13 - 10/13		27,750		96.90		852				852			104,000		4.60		824			824		1,676			1,676
11/13 - 11/13		26,800		96.90		97				97			104,000		4.60		63			63		160			160
12/13 - 12/13		27,750		96.90		107				107			104,000		4.60		44			44		151			151
1/14 - 2/14		19,000		96.90		164				164			82,000		4.60		54			54		218			218
10/12 - 12/12		17,050		81.22		(589	)			(589	)		26,838		5.89		207			207		(382	)		(382	)
10/12 - 12/12		1,900		81.14		(66	)			(66	)		112,000		5.00		565			565		499			499
10/12 - 12/12		—		—		—				—			53,000		5.70		378			378		378			378
10/12 - 12/12		27,500		85.90		(564	)			(564	)		—		—		—			—		(564	)		(564	)
10/12 - 10/12		1,884		100.80		16				16			41,462		4.94		80	��		80		96			96
11/12 - 11/12		—		—		—				—			2,951		4.94		5			5		5			5
12/12 - 12/12		15,140		100.80		116				116			106,375		4.94		141			141		257			257
1/13 - 6/13		15,542		100.80		638				638			200,669		4.94		1,412			1,412		2,050			2,050
7/13 - 7/13		7,132		100.80		49				49			148,788		4.94		164			164		213			213
8/13 - 8/13		5,980		100.80		42				42			139,212		4.94		151			151		193			193
9/13 - 9/13		3,897		100.80		28				28			116,125		4.94		126			126		154			154
10/13 - 10/13		3,259		100.80		24				24			91,166		4.94		96			96		120			120
11/13 - 11/13		—		—		—				—			64,926		4.94		62			62		62			62
12/13 - 12/13		10,042		100.80		78				78			119,462		4.94		91			91		169			169
1/14 - 5/14		10,083		100.80		426				426			129,960		4.94		498			498		924			924
6/14 - 6/14		—		—		—				—			129,960		4.94		110			110		110			110
1/13 - 12/13		19,750		85.90		(1,842	)			(1,842	)		47,000		5.00		648			648		(1,194	)		(1,194	)
1/14 - 12/14		15,000		65.00		(4,750	)			(4,750	)		—		—		—			—		(4,750	)		(4,750	)
10/12 - 10/12		23,170		102.40		234				234			—		—		—			—		234			234
11/12 - 11/12		19,290		102.40		186				186			—		—		—			—		186			186
12/12 - 12/12		24,860		102.40		230				230			—		—		—			—		230			230
1/13 - 1/13		43,510		102.40		385				385			—		—		—			—		385			385
2/13 - 2/13		29,030		102.40		248				248			—		—		—			—		248			248
3/13 - 3/13		35,760		102.40		299				299			—		—		—			—		299			299
4/13 - 4/13		28,740		102.40		237				237			—		—		—			—		237			237
5/13 - 5/13		28,540		102.40		236				236			—		—		—			—		236			236
6/13 - 6/13		22,800		102.40		190				190			—		—		—			—		190			190
7/13 - 7/13		14,700		102.40		124				124			—		—		—			—		124			124
8/13 - 8/13		14,080		102.40		121				121			—		—		—			—		121			121
9/13 - 9/13		12,390		102.40		108				108			—		—		—			—		108			108
10/13 - 10/13		13,710		102.40		122				122			—		—		—			—		122			122
11/13 - 11/13		14,320		102.40		129				129			—		—		—			—		129			129
12/13 - 12/13		19,310		102.40		180				180			—		—		—			—		180			180
1/14 - 1/14		30,600		102.40		293				293			—		—		—			—		293			293
2/14 - 2/14		22,010		102.40		216				216			—		—		—			—		216			216
3/14 - 3/14		45,910		102.40		461		��		461			—		—		—			—		461			461
4/14 - 4/14		41,850		102.40		429				429			—		—		—			—		429			429
5/14 - 5/14		42,530		102.40		447				447			—		—		—			—		447			447
6/14 - 6/14		48,860		102.40		525				525			—		—		—			—		525			525
7/14 - 7/14		36,680		102.40		402				402			—		—		—			—		402			402
8/14 - 8/14		35,360		102.40		395				395			—		—		—			—		395			395
9/14 - 9/14		32,290		102.40		365				365			—		—		—			—		365			365
10/14 - 10/14		32,920		102.40		376				376			—		—		—			—		376			376
11/14 - 11/14		30,000		102.40		346				346			—		—		—			—		346			346
12/14 - 12/14		41,880		102.40		494				494			—		—		—			—		494			494
					$	2,888			$	2,888						$	6,587		$	6,587	$	9,475		$	9,475

9

The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):

	Asset Derivatives			Liability Derivatives
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at September 30, 2012		Balance Sheet Location	Fair Value at September 30, 2012
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	9,887	Current	$	(2,630	)
	Non-current		7,399	Non-current		(5,181	)
Total derivative instruments		$	17,286		$	(7,811	)
	Asset Derivatives			Liability Derivatives
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at December 31, 2011		Balance Sheet Location	Fair Value at December 31, 2011
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	12,990	Current	$	(8,774	)
	Non-current		5,203	Non-current		(7,319	)
Total derivative instruments		$	18,193		$	(16,093	)

The effect of derivate instruments on our consolidated statements of operations was as follows (in thousands):

Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Statements of Operations Location	Three Months Ended September 30,					Nine Months Ended September 30,
		2012			2011		2012		2011
Commodity Contracts	Realized gain on derivative financial instruments	$	3,284		$	6,746	$	11,189	$	3,664
Commodity Contracts	Unrealized (loss) gain on derivative financial instruments		(16,129	)		50,234		7,375		43,006
Total derivative instruments		$	(12,845	)	$	56,980	$	18,564	$	46,670

NOTE 5—FAIR VALUE MEASUREMENTS

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

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

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

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

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

10

The following tables present information about our assets and liabilities measured at fair value on a recurring basis as of September 30, 2012 and December 31, 2011, and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands):

	Fair Value Measurements at September 30, 2012 Using Fair Value Hierarchy
	Fair Value as of September 30, 2012			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	17,286		$	—	$	17,286		$	—
	$	17,286		$	—	$	17,286		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(7,811	)	$	—	$	(7,811	)	$	—
	$	(7,811	)	$	—	$	(7,811	)	$	—
	Fair Value Measurements at December 31, 2011 Using Fair Value Hierarchy
	Fair Value as of December 31, 2011			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	18,193		$	—	$	18,193		$	—
	$	18,193		$	—	$	18,193		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(16,093	)	$	—	$	(16,093	)	$	—
	$	(16,093	)	$	—	$	(16,093	)	$	—

At September 30, 2012 and December 31, 2011, management estimates that the derivative contracts had a fair value of $9.5 million and $2.1 million, respectively. 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, 2012, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities approximated their carrying value due to their short-term nature. The estimated fair value of our debt was primarily based on quoted market prices as well as prices for similar debt based on recent market transactions. The fair value of debt at September 30, 2012 was $215.4 million.

Fair Value on a Non-Recurring Basis

As of September 30, 2012, oil and gas properties with a carrying value of $224.4 million were written down to their fair value of $217.4 million, resulting in an impairment charge of $3.7 million and $7.0 million for the three and nine months ended September 30, 2012, respectively, which is recognized under “Impairments” in the consolidated statements of operations. 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 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.

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NOTE 6—DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:

	September 30, 2012			December 31, 2011
	(in thousands)
Senior Secured Revolving Credit Facility	$	56,500		$	24,000
13.75% Senior Secured Notes, net of discount		149,058			148,887
AFCO Credit Corporation-insurance note payable		8,858			—
First Insurance note payable		—			4,154
Total debt		214,416			177,041
Less: current portion		(8,858	)		(4,154	)
Total long-term debt	$	205,558		$	172,887

Senior Secured Revolving Credit Facility

On December 24, 2010, we entered into an aggregate $110 million credit facility (the “Credit Facility”) comprised of a senior secured revolving credit facility of up to $35 million (the “Revolving Credit Facility”) 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 “Letter of Credit Facility”). 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 borrowing based utilization percentage in effect from time to time.

On May 31, 2011, we entered into an amendment to the Credit Facility, which increased the Revolving Credit Facility available thereunder to $70 million and the Letter of Credit Facility to $125 million, based primarily on the reserves provided by the Merit Acquisition. On June 30, 2011, we entered into a waiver and second amendment to the Revolving Credit Facility to amend certain provisions governing our swap agreements. On December 30, 2011, we entered into the second amendment to the Letter of Credit Facility to update the fees on the letters of credit to 2% on a go-forward basis. On May 24, 2012, we entered into the third amendment to the Letter of Credit Facility to increase the secured letter of credit to $135 million. In November 2012, we entered into a third amendment to the Credit Facility to update the “change in control” definition, confirm the amount available of $70 million under the Revolving Credit Facility and amend the definition of debt included in the calculation of the covenants. In November 2012, we entered into the fourth amendment to the Letter of Credit Facility to increase the secured letter of credit to $200 million, update the “change of control” definition, and amend the definition of debt included in the calculation of the covenants.

As of September 30, 2012, letters of credit in the aggregate amount of $126.8 million were outstanding under the Letter of Credit Facility. We had $56.5 million in borrowings under the Revolving Credit Facility of which $13.5 million was available for additional borrowings.

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, 2012, we recognized $10,097 and $63,292 in commitment fees, respectively, 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 our 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. The October 1, 2012 redetermination was completed in November 2012 with no changes to the Revolving Credit Facility and will remain in effect until January 31, 2013, at which time the borrowing base shall be re-determined. 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 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, but not limited to, restrictions on our and our subsidiaries’ ability to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets subject to their security interests, pay dividends, make acquisitions, loans, advances or investments, sell or otherwise transfer assets, enter into transactions with affiliates or change our line of business. As of

12

September 30, 2012, we were not in compliance with our total leverage ratio and our interest coverage ratios. Our total leverage ratio was calculated to be 2.7 to 1.0 which was higher than the required 2.5 to 1.0. Our interest coverage ratio was 2.7 to 1.0 which was lower than the required 3.0 to 1.0. In November 2012, we received a waiver related to our total leverage and interest coverage ratios which allowed us to exclude preferred stock from the debt definition as long as no dividends were paid and the preferred stock is not redeemable within six months following the maturity date. Based on the revised debt definition, the leverage ratio was recalculated to be 2.3 to 1.0 and the interest coverage ratio was calculated to be 3.6 to 1.0 which were in compliance under our Credit Facility.

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 prior 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 in arrears, on June 1 and December 1 of each year, which commenced on June 1, 2011. The Notes will mature on December 1, 2015, of which all principal then outstanding will be due. As of September 30, 2012, the recorded value of the Notes was $149.1 million, which includes the unamortized discount of $0.9 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. We also have an optional redemption in which we may redeem up to 35% of the aggregate principal amount of the Notes at a price equal to 110.0% of the principal amount, plus accrued interest and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings until December 1, 2013. From December 1, 2013 until December 1, 2014, we may redeem some or all of the Notes at an initial redemption price equal to par value plus one-half the coupon which equals 106.875% plus accrued and unpaid interest to the date of the redemption. On or after December 1, 2014, we may redeem some or all of the Notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption.

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

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

13

The amounts of required principal payments based on our outstanding debt amounts as of September 30, 2012, were as follows:

Period Ending September 30,	(in thousands)
2013	$	8,858
2014		56,500
2015		—
2016		150,000
2017		—
		215,358
Unamortized discount on 13.75% Senior Secured Notes		(942	)
Total debt	$	214,416

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 Class D Units are non-voting units, have an aggregate liquidation preference of $30 million and accrue dividends payable in kind at a rate per annum of 24%, compounded annually to the extent they are not distributed. As of September 30, 2012 and December 31, 2011, we have accrued dividends in the amounts of $10.2 million and $4.2 million, respectively, which are included in “Long-Term Liabilities” on the consolidated balance sheets. The dividends were reclassed to a long-term liability in the second quarter of 2012, as they are expected to be repaid after the Notes mature.

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. Approximate future minimum lease payments for operating leases at September 30, 2012 were as follows:

Period Ending September 30,	(in thousands)
2013	$	2,920
2014		2,387
2015		2,005
2016		1,842
2017		1,557
Thereafter		4,991
	$	15,702

In September 2012, we entered into a drilling unit contract. We intend to commence drilling operations in December 2012. The lease is for a term of 90 days in addition to the demobilization being completed.

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 in maximum aggregate amount of $63.8 million ($32.6 million operated and $31.2 million non-operated) for future P&A costs that may be incurred on such properties. As of November 2010, we fully funded the operating escrow account in the amount of $32.6 million and the payment schedule for the Non-Operated Properties Escrow Account was amended and commenced on December 2011. As of September 30, 2012, we have funded $12.4 million into the non-operating escrow account, leaving $18.8 million to be funded through May 1, 2017.

14

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 of $13.1 million to be used for future P&A costs that may be incurred on such properties. As of September 30, 2012, we have funded $6.9 million, leaving $6.2 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 amount equal to $60 million, which is to be paid in 30 equal monthly installments payable on the first day of each month commencing on June 1, 2011. As of September 30, 2012, we have funded $32.1 million, leaving $27.9 million to be funded through November 2013.

NOTE 9—RELATED PARTY TRANSACTIONS

We pay 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, 2012 and December 31, 2011, we had receivables from Black Elk Energy, LLC in the amount of $22,430 and $22,430, respectively.

For the three and nine months ended September 30, 2012, we paid $59,614 and $131,837 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, 2012 and December 31, 2011, the outstanding amount due to Up and Running Solutions, LLC was $29,738 and $72,222, respectively.

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

In October 2010, Freedom Logistics LLC (“Freedom”) was formed by Platinum, our majority equity holder, and Freedom HHC Management, LLC, the members of which are Messrs. John Hoffman (our President and Chief Executive Officer) and David Cantu (a member of our management), for the purpose of holding certain aircraft equipment, including two helicopters. On October 8, 2010, we guaranteed the loan that Freedom used to purchase two helicopters in the aggregate principal amount of $3.2 million. As of September 30, 2012 and December 31, 2011, the balance of the loan was $2.8 million and $3.0 million, respectively. On August 1, 2012, Freedom entered into a purchase agreement with Gulf State Aviation, whereby Gulf State Aviation will purchase certain aircraft equipment from Freedom, including the two helicopters. The proceeds of the sale will be applied to the balance of the guaranteed loan once the sale has been finalized, which is expected to occur in December 2012.

In April 2011, Freedom Well Services (“FWS”) was formed by certain members of our management, Freedom Well Services Employee Incentive, LLC and Platinum, our majority equity holder, to provide well P&A, slick line and electronic line services as well as consulting services around platform decommissioning and removal. Although we did not contribute capital for start-up costs, we funded the purchase of equipment as a prepayment for services rendered with the expectation that the prepayment will be reimbursed as the business continues to grow and generate cash flows. As of September 30, 2012 and December 31, 2011, prepayments were $8.7 million and $6.6 million, respectively, to FWS which is included in “Prepaid expenses and other” on our consolidated balance sheet.

15

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

• Future financial and operating performance and results;

• Business strategy and budgets;

• Market prices;

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

• Technology;

• Financial strategy;

• Amount, nature and timing of capital expenditures;

• Drilling of wells and the anticipated results thereof;

• Oil and natural gas reserves;

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

• Competition and government regulations;

• Operating costs and other expenses;

• Cash flow and anticipated liquidity;

• Prospect development;

• Property acquisitions and sales; and

• Plans, forecasts, objectives, expectations and intentions.

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

These factors include risks summarized below:

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

• Oil and natural gas price volatility;

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

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

• Cash flow and liquidity;

• 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;

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• 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 drilling start-up dates;

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

• Ability to find and retain skilled personnel;

• Strength and financial resources of competitors;

• Potential defects in title to our properties;

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

• Losses possible from future litigation;

• Environmental risks;

• Changes in interest rates;

• Developments in oil and natural gas-producing countries;

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

• Worldwide political and economic conditions.

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

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

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

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

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

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Form 10-Q. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed, particularly in “Item 1A. Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are an oil and gas company engaged in the acquisition, exploitation, development and production of oil and natural gas properties. We seek to acquire and exploit properties with proved developed reserves, proved developed non-producing reserves and proved undeveloped reserves. Our strategy is to acquire and economically maximize properties that are currently producing or have the potential to produce given additional attention and capital resources. We are engaged in a continual effort to monitor and reduce operating expenses by finding opportunities to safely increase efficiencies related to staffing, transportation and operational procedures. Moreover, our ability to accurately estimate and manage plugging and abandonment costs associated with potential acquisitions increases the likelihood of achieving our target returns on investment. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation. As of September 30, 2012, we held an aggregate net interest in approximately 569,762 gross (273,717 net) acres under lease and had an interest in 1,167 gross wells, 351 of which are producing.

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

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

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

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

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

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

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

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

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

From time to time, we use derivative financial instruments to economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. Our average prices that reflect both the before and after effects of our realized commodity hedging transactions for the three and nine months ended September 30, 2012 and 2011 are shown in the table below.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Oil:
Average price before effects of hedges ($/Bbl)(1)	$	102.92	$	102.56	$	107.93	$	105.44
Average price after effects of hedges ($/Bbl)		103.06		107.64		105.99		102.51
Average price differentials(2)		10.76		13.05		11.81		10.05
Gas:
Average price before effects of hedges ($/Mcf)(1)	$	3.06	$	4.28	$	2.63	$	4.43
Average price after effects of hedges ($/Mcf)		3.80		5.03		3.64		5.03
Average price differentials(2)		0.18		0.16		0.09		0.21

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

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

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

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to continue entering into such transactions in the future to reduce the effect of

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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.

Recent Event

On September 27, 2012, an incident occurred on our High Island 443 A-2 ST well which required the closing of the blind/shear rams to properly shut in and maintain control of the well due to several days of unsuccessful attempts to repair a small hydrocarbon leak on a conductor riser. Additional surface diagnostics found the inner casing strings to be most likely compromised. On October 12, 2012, the Bureau of Safety and Environmental Enforcement (“BSEE”) advised us to plug and abandon the well. We have well control insurance and are pursuing reimbursement for this incident. Currently, a claims adjuster has been assigned and is gathering the necessary information. We have not recorded a receivable for reimbursement under our insurance policy.

Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium

In April 2010, the Deepwater Horizon, a drilling platform operated by British Petroleum PLC in ultra deepwater in the U.S. Gulf of Mexico, sank after an apparent blowout and fire. The resulting leak caused a significant oil spill. In response to the explosion and spill, the U.S. Department of the Interior (“DOI”) 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 DOI in October 2010.

In addition, while the moratorium was in place, the DOI, through its Bureau of Ocean Energy Management, Regulation and Enforcement (“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, with amendments proposed on September 14, 2011, but not yet finalized, that would impose certain added safety procedures to a company’s SEMS not covered by the original rule and revise certain existing obligations.

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Compliance with these requirements issued by the DOI or its implementing agencies, including the BSEE and the Bureau of Ocean Energy Management (“BOEM”), which two agencies are successors to BOEMRE, effective November 1, 2011, may prevent us from obtaining new drilling permits and approvals in a timely manner, which could materially adversely impact our business, financial position or results of operations. Since early 2011, there has been gradual improvement in the number of approved drilling permits issued per month for the U.S. Gulf of Mexico, however, it is possible that the improvement of this pace could slow or reverse as a result of uncertainties with respect to implementation and interpretation of NTLs and other regulatory initiatives, the ability of the BSEE to timely review submissions and issue drilling permits, or potential third party challenges to industry drilling operations in the U.S. Gulf of Mexico.

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, 2012 and 2011:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Average daily sales:
Oil (Boepd)		5,357			5,985		5,595			5,108
Natural gas (Mcfpd)		47,177			56,917		51,075			47,451
Plant products (Galpd)		34,206			29,090		38,900			28,393
Oil equivalents (Boepd)		14,034			16,164		15,033			13,693
Average realized prices(1):
Oil ($/Bbl)	$	103.06		$	107.64	$	105.99		$	102.51
Natural gas ($/Mcf)		3.80			5.03		3.64			5.03
Plant products ($/Gallon)		0.91			1.40		1.04			1.25
Oil equivalents ($/Boe)		54.35			60.09		54.49			58.26
Costs and Expenses:
Lease operating expense ($/Boe)		33.95			31.69		31.82			26.75
Production tax expense ($/Boe)		0.15			0.16		0.18			0.12
General and administrative expense ($/Boe)		6.43			3.36		5.02			4.51
Net (loss) income (in thousands)		(32,575	)		51,114		(16,712	)		55,041
Adjusted EBITDA(2) (in thousands)		15,307			32,349		66,221			87,076

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

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

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Net (loss) income	$	(32,575	)	$	51,114		$	(16,712	)	$	55,041
Adjusted EBITDA	$	15,307		$	32,349		$	66,221		$	87,076
Reconciliation of Net loss (income) to Adjusted EBITDA
Net (loss) income	$	(32,575	)	$	51,114		$	(16,712	)	$	55,041
Interest expense		6,514			6,873			19,422			19,275
Unrealized loss (gain) on derivative instruments		16,129			(50,234	)		(7,375	)		(43,006	)
Accretion		9,256			9,089			27,228			18,471
Depreciation, depletion, amortization and impairment		15,983			15,507			43,538			37,437
Loss (gain) on sale of asset		—			—			120			(142	)
Adjusted EBITDA	$	15,307		$	32,349		$	66,221		$	87,076

The following table sets forth certain information with respect to oil and gas operations for the three and nine months ended September 30, 2012 and 2011:

	Three Months Ended September 30,												Nine Months Ended September 30,
	2012			2011			Change			% Change			2012			2011			Change			% Change
PRODUCTION:
Oil (MBbl)		493			551			(58	)		-11	%		1,533			1,395			138			10	%
Natural gas (MMcf)		4,340			5,236			(896	)		-17	%		13,995			12,954			1,041			8	%
Plant products (MGal)		3,147			2,676			471			18	%		10,659			7,751			2,908			38	%
Total (Mboe)		1,291			1,487			(196	)		-13	%		4,119			3,738			381			10	%
REVENUES:
Oil sales	$	50,721		$	56,470		$	(5,749	)		-10	%	$	165,441		$	147,038		$	18,403			13	%
Natural gas sales		13,289			22,398			(9,109	)		-41	%		36,754			57,388			(20,634	)		-36	%
Plant product sales and other revenue		5,960			5,500			460			8	%		19,141			13,614			5,527			41	%
Realized gain on derivative financial instruments		3,284			6,746			(3,462	)		-51	%		11,189			3,664			7,525			205	%
Unrealized (loss) gain on derivative financial instruments		(16,129	)		50,234			(66,363	)		-132	%		7,375			43,006			(35,631	)		-83	%
TOTAL REVENUES		57,125			141,348			(84,223	)		-60	%		239,900			264,710			(24,810	)		-9	%
OPERATING EXPENSES:
Lease operating		43,840			47,125			(3,285	)		-7	%		131,055			100,000			31,055			31	%
Production taxes		192			231			(39	)		-17	%		744			439			305			69	%
Workover		4,395			6,053			(1,658	)		-27	%		10,485			11,599			(1,114	)		-10	%
Exploration		311			—			311			100	%		1,249			—			1,249			100	%
Depreciation, depletion and amortization		12,302			14,411			(2,109	)		-15	%		36,546			32,018			4,528			14	%
Impairment		3,681			1,096			2,585			236	%		6,992			5,419			1,573			29	%
General and administrative		8,301			4,991			3,310			66	%		20,668			16,862			3,806			23	%
Accretion		9,256			9,089			167			2	%		27,228			18,471			8,757			47	%
Loss (gain) on sale of asset		—			—			—			0	%		120			(142	)		262			-185	%
TOTAL OPERATING EXPENSES		82,278			82,996			(718	)		-1	%		235,087			184,666			50,421			27	%
(LOSS) INCOME FROM OPERATIONS		(25,153	)		58,352			(83,505	)		-143	%		4,813			80,044			(75,231	)		-94	%
OTHER INCOME (EXPENSE):
Interest income		11			131			(120	)		-92	%		305			358			(53	)		-15	%
Miscellaneous expense		(919	)		(496	)		(423	)		85	%		(2,408	)		(6,086	)		3,678			-60	%
Interest expense		(6,514	)		(6,873	)		359			-5	%		(19,422	)		(19,275	)		(147	)		1	%
TOTAL OTHER EXPENSE		(7,422	)		(7,238	)		(184	)		3	%		(21,525	)		(25,003	)		3,478			-14	%
NET (LOSS) INCOME	$	(32,575	)	$	51,114		$	(83,689	)		-164	%	$	(16,712	)	$	55,041		$	(71,753	)		-130	%

Production

Oil and natural gas production.Total oil, natural gas and plant product production of 1,291 MBoe decreased 196 MBoe, or 13%, during the three months ended September 30, 2012 compared to the same period in 2011 as a result of uneconomic leases and several fields being shut-in. For the nine months ended September 30, 2012, total oil, natural gas and plant production of 4,119 MBoe increased 381 MBoe, or 10%, compared to the nine months ended 2011 due to the properties acquired in the Merit Acquisition in May 2011 (971 MBoe for the nine months ended September 30, 2012) which was partially offset by lower production in uneconomic leases and several fields being shut-in during the second and third quarters of 2012.

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Revenues

Total revenues.Total revenues for the three and nine months ended September 30, 2012 of $57.1 million and $239.9 million, respectively, decreased $84.2 million, or 60%, and $24.8 million, or 9%, respectively, over the comparable periods in 2011.

Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, decreased $14.4 million, or 17%, for the three months ended September 30, 2012 compared to the same period in 2011 as a result of lower oil and gas production due to uneconomic leases and several fields being shut-in and lower natural gas and plant product prices. For the nine months ended September 30, 2012, revenues, excluding the realized and unrealized revenues from commodity hedge contracts, increased $3.3 million, or 2%, compared to the same period in 2011 as a result of increased production due to properties acquired in the Merit Acquisition in May 2011 and higher oil prices partially offset by lower gas and plant product prices.

We entered into certain oil and natural gas commodity derivative contracts in 2012 and 2011. We realized gains on these derivative contracts in the amounts of $3.3 million and $11.2 million for the three and nine months ended September 30, 2012, respectively, and realized gains of $6.7 million and $3.7 million for the three and nine months ended September 30, 2011, respectively. We recognized unrealized gains (losses) of $(16.1) million and $7.4 million for the three and nine months ended September 30, 2012, respectively, and unrealized gains of $50.2 million and $43.0 million in the same periods of 2011.

Excluding hedges, we realized average oil prices of $102.92 per barrel and $107.93 per barrel and gas prices of $3.06 per Mcf and $2.63 per Mcf for the three and nine months ended September 30, 2012, respectively. For the same periods in 2011, excluding hedges, we realized average oil prices of $102.56 per barrel and $105.44 per barrel and $4.28 per Mcf and $4.43 per Mcf, respectively. Average prices realized from the sale of oil on a third quarter and year-to-date basis reflected the economic turnaround that began during 2011. Gas prices were lower on a quarter and year-to-date basis compared to 2011 but are higher than the second quarter of 2012.

Operating Expenses

Lease operating costs.Our lease operating costs for the three and nine months ended September 30, 2012 decreased to $43.8 million, or $33.95 per Boe, and increased to $131.1 million, or $31.82 per Boe, respectively. For the three and nine months ended September 30, 2011, our lease operating costs were $47.1 million, or $31.69 per Boe, and $100.0 million, or $26.75 per Boe, respectively. Lease operating expenses decreased for the three months ended September 30, 2012 compared to the same period in 2011 due to cost reduction initiatives and the unmanning of platforms as well as lower offshore insurance costs. The increase in lease operating costs for the nine months ended September 30, 2012 compared to the same period in 2011 was directly related to the additional properties acquired from the Maritech and the Merit Acquisitions. The increase in cost per Boe during 2012 was primarily attributable to a mix of increased properties and certain non-recurring safety and regulatory costs on the newly acquired properties and lower production due to pipeline repairs and leaks in 2012.

Workover costs.Our workover costs for the three and nine months ended September 30, 2012 were $4.4 million and $10.5 million, respectively, a decrease of $1.7 million compared to the third quarter of 2011 and a decrease of $1.1 million compared to the first nine months in 2011. For the nine months ended September 30, 2012, Eugene Island 240, West Cameron 20/45, Eugene Island 156/South Marsh 22, West Delta 31/32, and Eugene Island 331 were the primary workover expense projects.

Exploration. Our exploration expenses for the three and nine months ended September 30, 2012 were $0.3 million and $1.2 million, respectively. There were no exploration costs for the same periods in 2011. Exploration costs for 2012 include expenses to drill a non-operated well, South Pelto 13, which was unsuccessful.

Depreciation, depletion, amortization and impairment.DD&A expense was $12.3 million, or $9.53 per Boe, and $36.5 million, or $8.87 per Boe, for the three and nine months ended September 30, 2012, respectively, and $14.4 million, or $9.69 per Boe, and $32.0 million, or $8.57 per Boe, for the three and nine months ended 2011, respectively. The decrease in DD&A for the three months ended September 30, 2012 was a result of lower production due to uneconomic leases and several fields being shut-in. DD&A increased for the nine months ended September 30, 2012 due to production associated with the properties acquired in 2011, partially offset by lower production due to uneconomic leases and several fields being shut-in. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded a $3.6 million and $7.0 million impairment for the three and nine months ended September 30, 2012, respectively, and a $1.1 million and $5.4 million impairment for the same periods in 2011, respectively.

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General and administrative expenses.G&A expense was $8.3 million, or $6.43 per Boe, and $20.7 million, or $5.02 per Boe, for the three and nine months ended September 30, 2012, respectively, and $5.0 million, or $3.36 per Boe, and $16.9 million, or $4.51 per Boe, for the same periods in 2011, respectively. The increase in G&A expense for the three and nine months ended September 30, 2012 was due to an increase in staff and related administrative costs attributable to our growth, in addition to higher legal fees and insurance costs.

Accretion expense.We recognized accretion expense of $9.3 million and $27.2 million for the three and nine months ended September 30, 2012, respectively, compared to $9.1 and $18.5 million for the three and nine months ended September 30, 2011, respectively. The increase in accretion expense in 2012 was attributable to assumed asset retirement obligations related to our acquisitions in 2011.

Miscellaneous expense. Miscellaneous expense of $0.9 million and $2.4 million increased $0.4 million and decreased $3.7 million for the three and nine months ended September 30, 2012, respectively, compared to the same periods in 2011. The higher year-to-date expense in 2011 was a result of the consent solicitation fee paid under the First Supplemental Indenture.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from our members, proceeds from the offering of our senior notes, which closed in November 2010, borrowings under our lines of credit and cash flows from operations. We believe that our working capital requirements, contractual obligations and expected capital expenditures discussed below, as well as our other liquidity needs for the next twelve months, can be met from cash flows provided by operations, amounts available under our Revolving Credit Facility and capital contributions. 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 are currently exploring potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. As we plug and abandon certain fields and meet the various criteria related to the corresponding escrow accounts, we expect to release funds from the escrow accounts. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Senior Secured Revolving Credit Facility

On December 24, 2010, we entered into an aggregate $110 million Credit Facility with Capital One, N.A., as administrative agent and a lender thereunder. The Credit Facility is comprised of (1) a senior secured reserve-based Revolving Credit Facility, under which our initial borrowing base was set at $35 million and (2) a $75 million secured Letter of Credit Facility, which is to be used exclusively for the issuance of letters of credit in support of our future P&A obligations relating to our oil and gas properties. The borrowing base under our Revolving Credit Facility is subject to redetermination on a semi-annual basis, effective April 1 and October 1, and up to one additional time during any six month period, as may be requested by either us or the administrative agent, acting at the direction of the majority of the lenders. The October 1, 2012 redetermination was completed in November 2012 with no changes to the Revolving Credit Facility and will remain in effect until January 31, 2013, at which time the borrowing base shall be re-determined. The borrowing base will be determined by the administrative agent in its sole discretion and consistent with its normal oil and gas lending criteria in existence at that particular time. Our obligations under the Credit Facility are guaranteed by our existing subsidiaries and are secured on a first-priority basis by all of our and our subsidiaries’ assets, in the case of the Revolving Credit Facility, and by cash collateral, in the case of the Letter of Credit Facility. The Credit Facility has a maturity date of December 24, 2013.

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

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

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

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

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On May 31, 2011, we entered into an amendment to the Credit Facility that (1) increased the amount available for borrowing under the Revolving Credit Facility from $35 million to $70 million and (2) increased the secured letter of credit from $75 million to $125 million. On June 30, 2011, we entered into a waiver and second amendment to the Revolving Credit Facility to amend certain provisions governing our swap agreements. On December 30, 2011, we entered into the second amendment to the Letter of Credit Facility to update the fees on the letters of credit to 2% on a go forward basis. On May 24, 2012, we entered into a third amendment to the Letter of Credit Facility to further increase the secured letter of credit from $125 million to $135 million. In November 2012, we entered into a third amendment to the Credit Facility to update the “change in control” definition, confirm the amount available of $70 million under the Revolving Credit Facility and amend the definition of debt included in the calculation of the covenants. In November 2012, we entered into the fourth amendment to the Letter of Credit Facility to increase the secured letter of credit from $135 million to $200 million, update the “change of control” definition, and amend the definition of debt included in the calculation of the covenants.

As of September 30, 2012, we were not in compliance with our total leverage and our interest coverage ratios. Our total leverage ratio was calculated to be 2.7 to 1.0 which was higher than the required 2.5 to 1.0. Our interest coverage ratio was 2.7 to 1.0 which was lower than the required 3.0 to 1.0. In November 2012, we received a waiver related to our total leverage and interest coverage ratios which allowed us to exclude preferred stock from the debt definition as long as no dividends were paid and the preferred stock is not redeemable within six months following the maturity date. Based on the revised debt definition, the total leverage ratio was recalculated to be 2.3 to 1.0 and the interest coverage ratio was recalculated to be 3.6 to 1.0 which were in compliance under our Credit Facility.

As of September 30, 2012, letters of credit in the aggregate amount of $126.8 million were outstanding under the Letter of Credit Facility and we had $56.5 million in borrowings under the Revolving Credit Facility. As of November 9, 2012, $7.0 million was available for additional borrowings under the Revolving Credit Facility.

For a further discussion of our Credit Facility, please see “Notes to Consolidated Financial Statements—Note 6—Debt and Notes Payable” in this Form 10-Q.

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. We also have an optional redemption in which we may redeem up to 35% of the aggregate principal amount of the Notes at a price equal to 110.0% of the principal amount, plus accrued and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings until December 1, 2013. From December 1, 2013 until December 1, 2014, we may redeem some or all of the Notes at an initial redemption price equal to par value plus one-half the coupon which equals 106.875% plus accrued and unpaid interest to the date of the redemption. On or after December 1, 2014, we may redeem some or all of the Notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption.

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

As of September 30, 2012, we were in compliance with our covenants under the Indenture.

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Member Contributions

On May 31, 2011, Platinum entered into a contribution agreement with us, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivable, in exchange for 30 million of our Class D Units. The Class D Units are non-voting units having an aggregate liquidation preference of $30 million and accruing dividends payable in kind at a rate per annum of 24%, compounded annually to the extent they are not distributed. The dividends are expected to be repaid after the Notes mature.

At September 30, 2012, Platinum had contributed a total of $15.1 million in cash and $14.9 million remained in financial instruments deemed by us to be a cash equivalent. In October 2012, we received $11.0 million in cash and expect to convert the remaining $3.9 million of cash equivalents into cash during the fourth quarter of 2012.

Capital Expenditures

We expect total capital expenditures to be $42.0 million for 2012 (excluding expenditures directly related to any acquisitions). Approximately $21.9 million was expended in the first nine months of 2012 for various projects including recompletions and drilling, and the remaining $20.1 million will be used for drilling and development during the remainder of the year. The capital expenditure limitation set forth in the Indenture was amended in conjunction with the Consent Solicitation on May 31, 2011 to a maximum limit of 30% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expense for any year after December 31, 2011.

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

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

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

Cash Flows

The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the nine months ended September 30, 2012 and 2011:

	Nine Months Ended September 30,
	2012			2011
	(in thousands)
Net cash provided by operating activities	$	44,028		$	53,535
Net cash used in investing activities		(61,129	)		(92,291	)
Net cash provided by financing activities		17,488			36,006
Net increase (decrease) in cash and equivalents	$	387		$	(2,750	)

Cash flows provided by operating activities.Cash provided by operating activities totaling $44.0 million during the nine months ended September 30, 2012 compared to $53.5 million during the nine months ended September 30, 2011. Significant components of net cash provided by operating activities during the nine months ended September 30, 2012 included $67.1 million of non-cash items, primarily DD&A expense and accretion of asset retirement obligations, partially offset by a net loss of $16.7 million and $6.4 million of changes in operating assets and liabilities.

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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 $61.1 million in the nine months ended September 30, 2012 was primarily attributable to additions to the oil and gas properties during the period and the funding of the future P&A obligations through escrow. Cash used in investing activities in the comparable period of 2011 totaling $92.3 million was attributable to the assets purchased in the Maritech Acquisition and Merit Acquisition and the funding of the future P&A obligations through escrow.

Cash flows provided by financing activities.Cash flows provided by financing activities of $17.5 million in the nine months ended September 30, 2012 were attributable to borrowings under the Credit Facility and short-term notes partially offset by payments on the Credit Facility and short-term notes, tax distributions to members, and debt issue costs. Cash provided by financing activities of $36.0 million during the nine months ended September 30, 2011 was attributable to borrowings under the Credit Facility and short-term notes as well as a $30 million contribution from Platinum, partially offset by payments on the Credit Facility, debt issuance costs of the Notes, and tax 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 2011, we increased our asset retirement obligations by $166.4 million, primarily as a result of the Maritech Acquisition and the Merit Acquisition, and recognized $27.4 million in accretion expense. As of September 30, 2012, we increased our asset retirement obligations by $13.6 million and for the three and nine months ended September 30, 2012, we recognized $9.3 million and $27.2 million in accretion expense, respectively.

At September 30, 2012 and December 31, 2011, we recorded total asset retirement obligations of $302.3 million and $288.7 million, respectively, and have funded approximately $211.0 million and $172.2 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds. As of September 30, 2012 and December 31, 2011, we also have a guaranteed escrow amount of $20.3 million for certain fields which will be refunded to us once we have completed our P&A obligations on the entire field. The escrow is guaranteed by TETRA Technologies, Inc.

Contractual Obligations

We have various contractual obligations in the normal course of our operations and financing activities. The following schedule summarizes our contractual obligations and other contractual commitments at September 30, 2012:

	Payments Due by Period
	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		After 5 Years
	(in thousands)
Contractual Obligations
Total debt and notes payable	$	215,358	$	8,858	$	56,500	$	150,000	$	—
Interest on debt and notes payable		68,821		23,476		41,908		3,437		—
Operating leases (1)		15,702		2,920		4,392		3,399		4,991
Total contractual obligations		299,881		35,254		102,800		156,836		4,991
Other Obligations
Asset retirement obligations (2)		302,291		19,609		208,382		42,234		32,066
Total obligations	$	602,172	$	54,863	$	311,182	$	199,070	$	37,057

(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 that a related party used to purchase two helicopters in the aggregate principal amount of $3.2 million. The related party is not consolidated in our financials as the entity is not material to us. On August 1, 2012, a purchase agreement was signed to sell certain aircraft equipment from the related party. The proceeds of the sale will be applied to the balance of the guaranteed loan once the sale has been finalized, which is expected to occur in December 2012. At September 30, 2012, the balance of the loan was $2.8 million and the maturity date is October 8, 2013. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

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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.

At September 30, 2012, commodity derivative instruments were in place covering approximately 65% of our projected oil sales volumes and 42% of our projected natural gas volumes through 2012.

Please see “Notes to Consolidated Financial Statements—Note 4—Derivative Instruments” in this Form 10-Q 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 “Notes to Consolidated Financial Statements—Note 2—Oil and Gas Properties” in this Form 10-Q as well as in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2011 Form 10-K.

Inflation and Changes in Prices

Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the three and nine months ended September 30, 2012, we received an average of $102.92 and $107.93 per barrel of oil and $3.06 and $2.63 per Mcf of natural gas, respectively, before consideration of commodity derivative contracts, compared to $102.56 and $105.44 per barrel of oil and $4.28 and $4.43 per Mcf of natural gas, respectively, in the three and nine months ended September 30, 2011. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through the first six months of 2008, commodity prices for oil and natural gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs but also on capital costs. During 2012, commodity prices have softened and services and costs have not decreased in proportion to the lower prices. Higher costs are partially fueled by unconventional plays onshore as well as resource shifts out of the Gulf of Mexico.

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.

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Commodity Price Risk

Our primary market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our annualized production for the nine months ended September 30, 2012, our annual revenue would increase or decrease by approximately $20.4 million for each $10.00 per barrel change in oil prices and $18.7 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging. Based on our total annual production for the year ended December 31, 2011, our revenues would have increased or decreased by approximately $19.9 million for each $10.00 per barrel change in oil prices and $18.2 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging.

To partially reduce price risk caused by these market fluctuations, we hedge a significant portion of our anticipated oil and natural gas production as part of our risk management program. Reducing our exposure to price volatility helps ensure that we have 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, 2012, the fair value of our commodity derivatives were included in our consolidated balance sheets for approximately $7.3 million as current assets and $2.2 million as long-term assets. At December 31, 2011, the fair value of our commodity derivatives were approximately $4.2 million as current assets and $2.1 million as long-term liabilities. For the three and nine months ended September 30, 2012, we realized a net increase in oil and natural gas revenues related to hedging transactions of approximately $3.3 million and $11.2 million, respectively, and an increase for the same periods in 2011 of $6.7 million and $3.7 million, respectively.

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As of September 30, 2012, we maintained the following commodity derivative contracts:

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

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

For a further discussion of our hedging activities, please see “Notes to Consolidated Financial Statements - Note 4 - Derivative Instruments” in this Form 10-Q.

Credit Risk

We monitor our risk of loss associated with non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through joint interest receivables, which totaled $8.8 million at September 30, 2012 and $10.5 million at December 31, 2011. Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have an interest. We also have exposure to credit risk from the sale of our oil and natural gas production that we market to energy marketing companies and refineries, the receivables which totaled $27.4 million at September 30, 2012 and $35.9 million at December 31, 2011.

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

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our Revolving 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 $56.5 million outstanding under the Revolving Credit Facility as of September 30, 2012, an increase of 100 basis points in the underlying interest rate would have had a $0.6 million impact on our annual interest expense. However, there is no guarantee that we will not borrow additional amounts under the Revolving 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 Revolving 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.

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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 Accounting 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 Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Accounting Officer concluded that our disclosure controls and procedures were effective as of September 30, 2012, at the reasonable assurance level.

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, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We received a Notice of Proposed Civil Penalty Assessment dated April 5, 2011 (“Notice”) from the BOEMRE for an Incident of Noncompliance (“INC”) arising from a particular well’s alleged exceedance of certain testing time limits and alleged need for certain corrective actions. The INC was issued by BOEMRE during its on-site inspection of Vermilion Area Block 124, Platform F on July 30, 2010. The Notice includes a proposed penalty of greater than $0.1 million. We requested and attended a mitigation hearing with BOEMRE on the matter as we believe that a significant threat to safety or the environment did not exist, and are seeking a reduced civil penalty based on the mitigating circumstances presented in the hearing. We have received a final decision from BOEMRE on the matter and have been assessed a penalty of approximately $0.3 million of which we appealed to the Interior Board of Land Appeals (“IBLA”). We received notice on December 19, 2011 that the civil penalty would remain as assessed by the Reviewing Officer’s final decision. We paid the penalty of $0.3 million on September 5, 2012.

On June 27, 2012, we received notice from BSEE that administrative civil penalty proceedings had been initiated for two INCs issued as a result of an incident that occurred on October 9, 2011 at one of our offshore platforms. Both INCs allege operations involving well flowback operations were not conducted in a safe and workmanlike manner. As part of the civil penalty, we requested an informal meeting to present factual information to the reviewing officer that should serve to mitigate the proposed civil penalty of $140,000. The meeting was held on September 19, 2012. We are waiting on a final decision from the hearing officer.

We are also subject to other environmental matters and regulation. For a discussion of these items, see “Item 1. Business—Environmental and Occupational Health and Safety Regulation” in our 2011 Form 10-K.

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

Item 1A. Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of known risks we are subject to, see “Item 1A. Risk Factors” in our 2011 Form 10-K. The risks described in the 2011 Form 10-K could materially and adversely affect our business, financial condition, cash flows, and results of operations. Except as set forth below, there have been no material changes to the risks described in the 2011 Form 10-K. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

Our success depends on dedicated and skillful management and staff, whose departure could disrupt our business operations.

Our success depends on our ability to retain and attract experienced engineers, geoscientists and other professional staff, including John Hoffman, our President and Chief Executive Officer. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. If a significant number of key personnel and members of our management team resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

Item 5. Other Information

As of September 30, 2012, we were not in compliance with the financial covenants set forth in Section 9.01(b) and (c) of the Credit Agreement dated December 24, 2010 (as amended by that First Amendment dated May 31, 2011 and that Waiver and Second Amendment dated June 30, 2011, and as further amended, restated, supplemented or modified from time to time, the “Credit Agreement”) as our total leverage ratio was calculated to be 2.7 to 1.0 which was higher than the required 2.5 to 1.0 and our interest coverage ratio was calculated to be 2.7 to 1.0 which was lower than the required 3.0 to 1.0. We received a waiver for the period beginning fiscal quarter ended September 30, 2012 and for future periods which allows us to exclude preferred stock from the debt definition as long as no dividends were paid and the preferred stock is not redeemable within six months following the maturity date. Based on the revised debt definition, the leverage ratio was recalculated to be 2.3 to 1.0 and the interest coverage ratio was recalculated to be 3.6 to 1.0 which were in compliance under our Credit Facility.

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In connection with the above, we entered into the Limited Waiver and Third Amendment to Credit Agreement, dated to be effective as of September 30, 2012, 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, Capital One, N.A., as Administrative Agent for the Lenders, and Iberia Bank and Cadence Bank, N.A. as the Lenders (the “Credit Agreement Amendment”). Pursuant to the Credit Agreement Amendment, the Administrative Agent and Lenders waived compliance with the financial covenants contained in Section 9.01(b) and (c) of the Credit Agreement and amended the definition of “Debt” for purposes of calculating the leverage ratio for the quarter ended September 30, 2012. The Credit Agreement Amendment also updated the “change in control” definition by deleting clause (f) in Section 1.02 and affirmed the borrowing base under the Revolving Credit Facility of $70 million until January 31, 2013, at which time the borrowing base shall be re-determined.

On November 8, 2012, we also entered into the Fourth Amendment to Letter of Credit Facility Agreement and Waiver (the “Letter of Credit Facility Amendment”) by and among Black Elk Energy Offshore Operations, LLC, as the Borrower, the Guarantors party thereto, the Lenders and Capital One, N.A., as Administrative Agent. The Letter of Credit Facility Amendment amended that certain Letter of Credit Facility Agreement dated as of December 24, 2010 as amended, by and among Black Elk Energy Offshore Operations, LLC, as the Borrower, the Guarantors party thereto, the Lenders and Capital One, N.A., as Administrative Agent to increase the borrowing base available thereunder from $135 million to $200 million, update the “change in control” definition by deleting clause (f) in Section 1.02 and amend the definition of debt included in the financial covenant calculations. The Letter of Credit Facility Amendment also waived compliance with the financial covenants set forth in Section 9.01 (b) and (c) of the Credit Agreement.

The foregoing description of the Credit Agreement Amendment and Letter of Credit Facility Amendment, are qualified in their entirety by the full text of such agreements which are filed as Exhibits 4.1 and 4.2, respectively, to this Quarterly Report on Form 10-Q and incorporated by reference herein.

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Item 6. Exhibits

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

Exhibit Number	Description
3.1	Certificate of Formation of Black Elk Energy Offshore Operations, LLC, dated as of November 20, 2007 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.2	Certificate of Amendment of Black Elk Energy Offshore Operations, LLC, dated as of January 29, 2008 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.3	Second Amended and Restated Limited Liability Company Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of July 13, 2009 (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.4	First Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated August 19, 2010 (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.5	Second Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 31, 2011 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011 (SEC File No. 333-174226)).
*4.1	Limited Waiver and Third Amendment to Credit Agreement, dated as of November 8, 2012, 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.
*4.2	Fourth Amendment to Letter of Credit Facility Agreement and Waiver, dated as of November 8, 2012, 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.
10.1	Employment Agreement, dated as of July 13, 2012, between James F. Hagemeier and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 3, 2012 (SEC File No. 333-174226)).
10.2	Employment Agreement, dated as of July 13, 2012, between John G. Hoffman and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2012 (SEC File No. 333-174226)).
10.3	Employment Agreement, dated as of July 13, 2012, between Arthur Garza III and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2012 (SEC File No. 333-174226)).
*31.1	Certification of Principal 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 Principal 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 Principal Executive Officer and Principal 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

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Exhibit Number	Description
101.CAL§	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE§	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF§	XBRL Taxonomy Extension Definition Linkbase Document

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

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SIGNATURES

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

	BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC (Registrant)
	By:	Black Elk Energy, LLC, its sole member
Date: November 13, 2012	By:	/s/ Michelle Simmons
		Michelle Simmons
		Chief Accounting Officer (Duly Authorized Officer and Principal Financial Officer)

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EXHIBIT INDEX

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

Exhibit Number	Description
3.1	Certificate of Formation of Black Elk Energy Offshore Operations, LLC, dated as of November 20, 2007 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.2	Certificate of Amendment of Black Elk Energy Offshore Operations, LLC, dated as of January 29, 2008 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.3	Second Amended and Restated Limited Liability Company Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of July 13, 2009 (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.4	First Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated August 19, 2010 (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.5	Second Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 31, 2011 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011 (SEC File No. 333-174226)).
*4.1	Limited Waiver and Third Amendment to Credit Agreement, dated as of November 8, 2012, 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.
*4.2	Fourth Amendment to Letter of Credit Facility Agreement, dated as of November 8, 2012, 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.
10.1	Employment Agreement, dated as of July 13, 2012, between James F. Hagemeier and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 3, 2012 (SEC File No. 333-174226)).
10.2	Employment Agreement, dated as of July 13, 2012, between John G. Hoffman and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2012 (SEC File No. 333-174226)).
10.3	Employment Agreement, dated as of July 13, 2012, between Arthur Garza III and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2012 (SEC File No. 333-174226)).
*31.1	Certification of Principal 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 Principal 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 Principal Executive Officer and Principal 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

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Exhibit Number	Description
101.LAB§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE§	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF§	XBRL Taxonomy Extension Definition Linkbase Document

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

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