10-Q

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 June 30, 2013

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  ¨    No  x

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been required to file by Section 13 or 15(d) of the Securities Exchange Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934.)

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 August 12, 2013, there were 1,361,300 Class A Units, 114,277,308.5 Class B Units, 12,031,250 Class C Units and 100,234,164 Class E Units issued and outstanding.

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2013

TABLE OF CONTENTS

		Page
Part I. Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012		1
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012		2
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012		3
	Notes to Consolidated Financial Statements		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		34
Item 4.	Controls and Procedures		37
Part II. Other Information
Item 1.	Legal Proceedings		38
Item 1A.	Risk Factors		40
Item 6.	Exhibits		41
Signatures			43
Exhibit Index			44

(i)

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	June 30,			December 31,
	2013			2012
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	12,821		$	1,383
Restricted cash		686			—
Accounts receivable, net of allowance for doubtful accounts of $509 at June 30, 2013 and December 31, 2012		56,222			46,553
Accounts receivable - insurance recovery		3,400			3,100
Due from affiliates		23			347
Prepaid expenses and other current assets		12,150			27,972
Current portion of escrow for abandonment costs		16,807			—
Derivative assets		—			2,408
TOTAL CURRENT ASSETS		102,109			81,763
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $255,998 and $191,326 at June 30, 2013 and December 31, 2012, respectively		224,104			260,012
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $4,294 and $1,717 at June 30, 2013 and December 31, 2012, respectively		5,819			1,968
OTHER ASSETS
Debt issue costs, net		2,261			3,230
Asset retirement obligation escrow receivable		20,348			20,348
Escrow for abandonment costs, net of current portion		215,545			215,263
Other assets		7,316			7,880
TOTAL OTHER ASSETS		245,470			246,721
TOTAL ASSETS	$	577,502		$	590,464
LIABILITIES AND MEMBERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	160,084		$	108,736
Derivative liabilities		1,672			—
Asset retirement obligations		33,621			41,572
Current portion of debt and notes payable		335			3,552
TOTAL CURRENT LIABILITIES		195,712			153,860
LONG-TERM LIABILITIES
Gas imbalance payable		2,527			2,521
Dividends payable		—			12,408
Derivative liabilities		1,858			5,091
Asset retirement obligations, net of current portion		288,843			303,933
Debt, net of current portion, net of unamortized discount of $754 and $882 at June 30, 2013 and December 31, 2012, respectively		174,306			201,118
TOTAL LONG-TERM LIABILITIES		467,534			525,071
TOTAL LIABILITIES		663,246			678,931
CLASS E AND CLASS D PREFERRED UNITS		100,234			30,000
COMMITMENTS AND CONTINGENCIES
MEMBERS’ DEFICIT		(185,978	)		(118,467	)
TOTAL LIABILITIES AND MEMBERS’ DEFICIT	$	577,502		$	590,464

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

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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
REVENUES:
Oil sales	$	40,035		$	54,202		$	85,936		$	114,720
Natural gas sales		14,109			9,149			27,446			23,465
Plant product sales and other revenue		7,034			6,577			13,674			13,181
Realized (loss) gain on derivative financial instruments		(187	)		6,436			152			7,905
Unrealized gain (loss) on derivative financial instruments		5,383			30,230			(846	)		23,504
TOTAL REVENUES		66,374			106,594			126,362			182,775
OPERATING EXPENSES:
Lease operating		46,971			43,973			90,173			87,215
Production taxes		189			209			316			552
Workover		4,224			3,521			6,284			6,090
Exploration		—			41			—			938
Depreciation, depletion and amortization		11,145			11,873			22,700			24,244
Impairment of oil and gas properties		22,414			3,311			55,377			3,311
General and administrative		9,388			5,933			18,629			12,367
Gain on involuntary conversion of asset		(8,250	)		—			(10,633	)		—
Accretion of asset retirement obligations		7,569			8,892			15,093			17,972
Loss (gain) on sale of assets		1,984			120			(35,791	)		120
Other operating expenses		1,423			—			2,413			—
TOTAL OPERATING EXPENSES		97,057			77,873			164,561			152,809
(LOSS) INCOME FROM OPERATIONS		(30,683	)		28,721			(38,199	)		29,966
OTHER INCOME (EXPENSE):
Interest income		29			13			51			294
Miscellaneous expense		(2,564	)		(844	)		(4,946	)		(1,489	)
Interest expense		(6,300	)		(6,373	)		(12,636	)		(12,908	)
TOTAL OTHER EXPENSE, NET		(8,835	)		(7,204	)		(17,531	)		(14,103	)
NET (LOSS) INCOME		(39,518	)		21,517			(55,730	)		15,863
LESS: PREFERRED UNIT DIVIDENDS		4,683			1,944			7,826			3,744
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	(44,201	)	$	19,573		$	(63,556	)	$	12,119

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

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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(55,730	)	$	15,863
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, and amortization		22,700			24,244
Impairment of oil and gas properties		55,377			3,311
Accretion of asset retirement obligations		15,093			17,972
Amortization of debt issue costs		2,818			2,194
Accretion of debt discount		128			111
Unrealized loss (gain) on derivative financial instruments		846			(23,504	)
(Gain) loss on sale of assets		(35,791	)		120
Gain on involuntary conversion of assets		(10,633	)		—
Changes in operating assets and liabilities:
Accounts receivable		(8,638	)		12,021
Due from affiliates, net		324			—
Prepaid expenses and other assets		15,870			(13,193	)
Other assets		254			—
Accounts payable and accrued liabilities		41,197			(7,043	)
Gas imbalance		316			744
Settlement of asset retirement obligations		(17,476	)		(6,570	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		26,655			26,270
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(78,414	)		(10,965	)
Acquisition of oil and gas properties		(3,250	)		(3,455	)
Sale of oil and gas properties		52,580			(119	)
Additions to property and equipment		(671	)		(131	)
Cash assumed in consolidation of Freedom Well Services, LLC		473			—
Proceeds received from insurance recovery		13,497			—
Deposits		25			(25	)
Restricted cash		(686	)		—
Escrow payments, net		(17,089	)		(30,716	)
NET CASH USED IN INVESTING ACTIVITIES		(33,535	)		(45,411	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on short term notes		—			17,645
Payments on short term notes		(3,380	)		(7,660	)
Borrowing on bank debt		9,000			121,000
Payments on bank debt		(36,000	)		(97,000	)
Debt issuance costs		(1,302	)		(2,038	)
Contributions from members		50,000			—
Distributions to members		—			(13,120	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		18,318			18,827
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		11,438			(314	)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD		1,383			17,260
CASH AND CASH EQUIVALENTS - END OF PERIOD	$	12,821		$	16,946
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	11,512		$	11,531
NONCASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations relieved due to sale of properties	$	(22,999	)	$	—
Increase in asset retirement due to revaluation	$	2,341		$	—
Paid-in-kind dividends on preferred equity and accrued distributions to members	$	7,826		$	3,744

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

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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(Unaudited)

NOTE 1—BASIS OF PRESENTATION

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 November 20, 2007 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, 2012 (the “2012 Form 10-K”).

Reclassifications: Certain reclassifications have been made to conform 2012 balances to our 2013 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. Effective January 1, 2013, in accordance with accounting guidelines for consolidation of variable interest entities, we consolidated Freedom Well Services, LLC (“FWS”), as we determined that we are the primary beneficiary of FWS and will have the power to direct the activities of FWS. 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.

Recent Accounting Pronouncements: 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. The adoption of this amendment did not have a material impact on our consolidated financial statements.

NOTE 2—LIQUIDITY RISKS AND UNCERTAINTIES

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $93.6 million at June 30, 2013. The combination of restricted credit availability, lower production since the fourth quarter of 2012 and our drilling program led to significant cash reductions in the fourth quarter of 2012 and the first and second quarters of 2013. To increase liquidity, we stretched accounts payable and aggressively pursued accounts receivable. We have worked closely with our vendors during this time and expect to normalize the age of accounts payables within 2013. We continue to optimize our production portfolio and recommenced our drilling program in the fourth quarter of 2012. Currently, we have two rigs under contract, and we expect to

4

drill or complete six operated wells and four non-operated wells in 2013. To fund our drilling programs and operations, we expect to continue to raise additional capital over the next several years. We are currently evaluating new sources of liquidity including, but not limited to, (i) entering into a new revolving credit facility with a traditional bank syndicate or Platinum, our majority owner, and (ii) accessing the debt capital markets. Additionally, we are evaluating potential asset sales of core and non-core assets to optimize our portfolio. On March 26, 2013, we sold four producing fields to Renaissance Offshore, LLC for approximately $52.5 million subject to normal purchase price adjustments. A portion of the proceeds from the sale were used to reduce the amount borrowed under the credit facility (the “Credit Facility”) by $36 million and the remainder has been and will be used for general corporate purposes. We expect that escrows of approximately $9.0 million related to the sold properties will be released and received in the third quarter of 2013. The remainder of the escrow funds released for the sold properties will be used to increase the collateral with the surety companies relating to bonds that had previously been issued that provide us with surety bonds to satisfy the bonding and security requirements of the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”). We also expect to obtain site clearance on certain properties after the plugging and abandonment (“P&A”) work has been performed and will meet obligations in the escrow agreements to release additional funds of $7.8 million. We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million subject to normal purchase price adjustments.

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. 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. Also, our letters of credit with Capital One are backed entirely by cash. We use letters of credit to back a portion of our surety bonds for P&A obligations.

We were not in compliance with our leverage ratio or our interest rate coverage ratio under our Credit Facility as of June 30, 2013. On July 31, 2013, we entered into the Tenth Amendment to (1) obtain waivers related to our financial covenants for the second quarter of 2013, (2) maintain the borrowing base at $25 million through August 30, 2013, and will reduce it to $0 on September 2, 2013 either through refinancing by another lender or a purchase agreement by Platinum, (3) release the liens on the second Renaissance sale that occurred on July 31, 2013 and (4) allow us to retain the proceeds from the second Renaissance sale and up to $5 million in aggregate of any escrow releases from both Renaissance sales or any other collateral sales. If Platinum purchases the debt, there will be an additional addendum extending the maturity date to July 1, 2014.

As of June 30, 2013, we were in compliance with all covenants under the Indenture. However, based on our financial results for 2013 to date, we anticipate that we are unlikely to be in compliance at December 31, 2013 with a covenant respecting maximum capital expenditures. We have the option under the indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes if we do not believe we will be in compliance with this covenant; however, there can be no assurance that we will have sufficient funds to do so. If the Notes remain outstanding at December 31, 2013 and a default under this covenant actually occurs, then we anticipate we would solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the indenture, the indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the indenture covenant could also result in a cross-default under our bank credit facility.

As discussed above, we are currently evaluating new sources of liquidity including, but not limited to, entering into a new revolving credit facility with a traditional bank syndicate or Platinum, our majority owner, accessing the debt capital markets and potential asset sales of non-core and core properties to optimize our portfolio. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amount and classifications of liabilities that might result from the uncertainty associated with our ability to meet our obligations as they come due. For additional information, please see “Risk Factors” under Item 1A of this Form 10-Q.

Our capital budget may be adjusted in the future as business conditions warrant and the ultimate amount of capital we expend may fluctuate materially based on market conditions and the success of our drilling program 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 budgeted 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. Our planned operations for the remainder of 2013 reflect our expectations for production based on actual production history and new production expected to be brought online, the continuation of commodity prices near current levels and the higher cost of servicing our additional financing and other obligations.

5

Our cash flow projections are highly dependent upon numerous assumptions including the timing and rates of production from our wells, the sales prices we realize for our oil and natural gas, the cost to develop and produce our reserves, our ability to monetize our properties and future production through asset sales and financial derivatives, and a number of other factors, some of which are beyond our control. Our inability to increase near-term production levels and generate sufficient liquidity through the actions noted above could result in our inability to meet our obligations as they come due which would have a material adverse effect on our financial position, results of operation and cash flows. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through other financing sources; however, there is no assurance that we will be able to do so in the future if required to meet any short-term liquidity needs.

Our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimation process requires significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, and may differ materially from our actual results. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves requires us to expect that capital will be available to fund their development. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and we intend to continue to develop these reserves, but there is no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet the requirements of our financing obligations.

Our current production is concentrated in the Gulf of Mexico, which is characterized by production declines more rapid than those of conventional onshore properties. As a result, we are particularly vulnerable to a near-term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and severe weather. Any unanticipated significant disruption to, or decline in, our current production levels or prolonged negative changes in commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet our commitments as they come due.

Oil and natural gas development and production in the Gulf of Mexico are regulated by the BOEM and BSEE of the Department of the Interior (“DOI”). We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Deepwater Horizon incident in 2010 have changed the way we conduct our business and increased our costs of developing and commissioning new assets. Should there be additional significant future regulations or additional statutory limitations, they could require further changes in the way we conduct our business, further increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico.

As an oil and gas company, our revenue, profitability, cash flows, proved reserves and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our debt and other obligations.

NOTE 3—OIL AND GAS PROPERTIES

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

	June 30,			December 31,
	2013			2012
	(Unaudited)
	(in thousands)
Proved properties	$	479,654		$	451,338
Unproved properties, not subject to depletion		448			—
Total capitalized costs		480,102			451,338
Accumulated depreciation, depletion, amortization and impairment		(255,988	)		(191,326	)
Oil and gas properties, net	$	224,104		$	260,012

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

	(in thousands)
Balance at December 31, 2012	$	345,505
Revaluation of liability		2,341
Liabilities relieved due to sale of properties		(22,999	)
Liabilities settled		(17,476	)
Accretion expense		15,093
Balance at June 30, 2013	$	322,464
Less: current portion		(33,621	)
Total Long-Term Asset Retirement Obligations	$	288,843

NOTE 4—ACQUISITIONS AND DIVESTITURES

On March 26, 2013, we completed the sale of four fields to Renaissance for approximately $52.5 million subject to normal purchase price adjustments. Funds were used to reduce the amount borrowed under the Credit Facility by $36 million and for general corporate purposes. We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million, subject to normal purchase price adjustments and will use the funds for general corporate purposes.

NOTE 5—DERIVATIVE INSTRUMENTS

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

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At June 30, 2013, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) (unaudited)):

	Crude Oil											Natural Gas										Total
Period	Volume (Bbls)			Contract Price ($/Bbl)		Asset (Liability)			Fair  Value Gain (Loss)			Volume (MMBtu)		Contract Price ($/MMBtu)		Asset (Liability)			Fair  Value Gain (Loss)			Asset (Liability)			Fair  Value Gain (Loss)
Swaps:						(in thousands)										(in thousands)						(in thousands)
7/13 - 8/13		27,750		$	96.90	$	29		$	29			104,000	$	4.60	$	198		$	198		$	227		$	227
9/13 - 10/13		27,750		$	96.90		89			89			104,000	$	4.60	$	207			207			296			296
11/13 -11/13		26,800			96.90		70			70			104,000		4.60		94			94			164			164
12/13 - 12/13		27,750			96.90		91			91			104,000		4.60		76			76			167			167
1/14 - 2/14		19,000			96.90		159			159			82,000		4.60		105			105			264			264
7/13 - 7/13		7,132			100.80		31			31			148,788		4.94		183			183			214			214
8/13 - 8/13		5,980			100.80		27			27			139,212		4.94		189			189			216			216
9/13 - 9/13		3,897			100.80		20			20			116,125		4.94		156			156			176			176
10/13 - 10/13		3,259			100.80		19			19			91,166		4.94		120			120			139			139
11/13 - 11/13		—			—		—			—			64,926		4.94		80			80			80			80
12/13 - 12/13		10,042			100.80		70			70			119,462		4.94		127			127			197			197
1/14 - 5/14		10,083			100.80		422			422			129,960		4.94		639			639			1,061			1,061
6/14 - 6/14		—			—		—			—			129,960		4.94		125			125			125			125
7/13 - 12/13		19,750			85.90		(1,063	)		(1,063	)		47,000		5.00		371			371			(692	)		(692	)
1/14 - 12/14		15,000			65.00		(3,937	)		(3,937	)		—		—		—			—			(3,937	)		(3,937	)
7/13 - 7/13		23,143			88.80		(179	)		(179	)		36,765		4.09		14			14			(165	)		(165	)
8/13 - 8/13		24,915			88.80		(183	)		(183	)		34,725		4.09		18			18			(165	)		(165	)
9/13 - 9/13		28,688			88.80		(190	)		(190	)		31,739		4.09		16			16			(174	)		(174	)
10/13 - 10/13		28,006			88.80		(164	)		(164	)		34,551		4.09		17			17			(147	)		(147	)
11/13 - 11/13		31,605			88.80		(161	)		(161	)		28,939		4.09		12			12			(149	)		(149	)
12/13 - 12/13		38,743			88.80		(168	)		(168	)		37,906		4.09		10			10			(158	)		(158	)
1/14 - 1/14		4,723			88.80		(17	)		(17	)		43,347		4.09		7			7			(10	)		(10	)
2/14 - 2/14		13,313			88.80		(40	)		(40	)		32,636		4.09		5			5			(35	)		(35	)
3/14 - 3/14		8,413			88.80		(21	)		(21	)		46,764		4.09		9			9			(12	)		(12	)
4/14 - 4/14		12,473			88.80		(25	)		(25	)		41,253		4.09		11			11			(14	)		(14	)
5/14 - 5/14		11,793			88.80		(19	)		(19	)		40,391		4.09		10			10			(9	)		(9	)
6/14 - 6/14		15,546			88.80		(18	)		(18	)		20,112		4.09		4			4			(14	)		(14	)
7/14 - 7/14		11,845			88.80		(9	)		(9	)		39,283		4.09		7			7			(2	)		(2	)
8/14 - 8/14		13,165			88.80		(4	)		(4	)		34,246		4.09		5			5			1			1
9/14 - 9/14		16,235			88.80		—			—			29,753		4.09		5			5			5			5
10/14 - 10/14		15,605			88.80		5			5			28,635		4.09		4			4			9			9
11/14 - 11/14		18,525			88.80		11			11			27,081		4.09		2			2			13			13
12/14 - 12/14		22,526			88.80		22			22			34,114		4.09		(2	)		(2	)		20			20
7/13 - 7/13		15,000			87.85		(130	)		(130	)		—		—		—			—			(130	)		(130	)
8/13 - 8/13		11,000			87.85		(91	)		(91	)		—		—		—			—			(91	)		(91	)
9/13 - 9/13		20,000			87.85		(151	)		(151	)		—		—		—			—			(151	)		(151	)
10/13 - 10/13		4,000			87.85		(27	)		(27	)		—		—		—			—			(27	)		(27	)
11/13 - 11/13		250			87.85		(2	)		(2	)		—		—		—			—			(2	)		(2	)
12/13 - 12/13		2,500			87.85		(13	)		(13	)		—		—		—			—			(13	)		(13	)
1/14 -1/14		46,000			87.85		(206	)		(206	)		—		—		—			—			(206	)		(206	)
2/14 - 2/14		25,000			87.85		(97	)		(97	)		—		—		—			—			(97	)		(97	)
3/14 - 3/14		56,000			87.85		(185	)		(185	)		—		—		—			—			(185	)		(185	)
4/14 - 4/14		45,000			87.85		(129	)		(129	)		—		—		—			—			(129	)		(129	)
5/14 - 5/14		46,000			87.85		(111	)		(111	)		—		—		—			—			(111	)		(111	)
6/14 - 6/14		48,000			87.85		(96	)		(96	)		40,391		4.19		12			12			(84	)		(84	)
7/14 - 7/14		36,000			87.85		(56	)		(56	)		20,112		4.19		5			5			(51	)		(51	)
8/14 - 8/14		34,000			87.85		(39	)		(39	)		39,283		4.19		10			10			(29	)		(29	)
9/14 - 9/14		26,000			87.85		(21	)		(21	)		34,246		4.19		8			8			(13	)		(13	)
10/14 - 10/14		27,000			87.85		(13	)		(13	)		29,753		4.19		7			7			(6	)		(6	)
11/14 - 11/14		20,000			87.85		(4	)		(4	)		28,635		4.19		4			4			—			—
12/14 - 12/14		31,000			87.85		6			6			27,081		4.19		—			—			6			6
9/13 - 9/13		(17,500	)		89.15		110			110			—		—		—			—			110			110
1/15 - 1/15		—			—		—			—			34,114		4.19		(2	)		(2	)		(2	)		(2	)
2/15 - 2/15		—			—		—			—			27,838		4.19		(1	)		(1	)		(1	)		(1	)
3/15 - 3/15		—			—		—			—			24,461		4.19		—			—			—			—
1/15 - 1/15		—			—		—			—			27,838		4.09		(4	)		(4	)		(4	)		(4	)
2/15 - 2/15		—			—		—			—			24,461		4.09		(3	)		(3	)		(3	)		(3	)
3/15 - 3/15		—			—		—			—			26,443		4.09		(2	)		(2	)		(2	)		(2	)
						$	(6,388	)	$	(6,388	)					$	2,858		$	2,858		$	(3,530	)	$	(3,530	)

8

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

	Asset Derivatives			Liability Derivatives				Asset (Liability) Derivatives Total
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at June 30, 2013		Balance Sheet Location	Fair Value at June 30, 2013			Balance Sheet Location	Fair Value at June 30, 2013
Commodity Contracts	Derivative financial instruments			Derivative financial instruments				Derivative financial instruments
	Current	$	3,953	Current	$	(5,625	)	Current	$	(1,672	)
	Non-current		100	Non-current		(1,958	)	Non-current		(1,858	)
Total derivative instruments		$	4,053		$	(7,583	)		$	(3,530	)
	Asset Derivatives			Liability Derivatives				Asset (Liability) Derivatives Total
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at December 31, 2012		Balance Sheet Location	Fair Value at December 31, 2012			Balance Sheet Location	Fair Value at December 31, 2012
Commodity Contracts	Derivative financial instruments			Derivative financial instruments				Derivative financial instruments
	Current	$	6,808	Current	$	(4,400	)	Current	$	2,408
	Non-current		1,235	Non-current		(6,326	)	Non-current		(5,091	)
Total derivative instruments		$	8,043		$	(10,726	)		$	(2,683	)

We have a netting agreement with our financial institution that permits net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and we routinely exercise our contractual right to offset realized gains against realized losses when settling with our derivative counterparty.

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

Derivatives Not Designated as Hedging		Three Months Ended June  30,					Six Months Ended June 30,
Instruments under Accounting Guidance	Statements of Operations Location	2013			2012		2013			2012
Commodity Contracts	Realized (loss) gain on derivative financial instruments	$	(187	)	$	6,436	$	152		$	7,905
Commodity Contracts	Unrealized gain (loss) on derivative financial instruments		5,383			30,230		(846	)		23,504
Total derivative instruments		$	5,196		$	36,666	$	(694	)	$	31,409

NOTE 6—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.

9

The following tables present information about our assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and December 31, 2012 and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands) (unaudited):

	Fair Value Measurements at June 30, 2013 Using Fair Value Hierarchy
	Fair Value as of June 30, 2013			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	4,053		$	—	$	4,053		$	—
	$	4,053		$	—	$	4,053		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(7,583	)	$	—	$	(7,583	)	$	—
	$	(7,583	)	$	—	$	(7,583	)	$	—
	Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	Fair Value as of December 31, 2012			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	8,043		$	—	$	8,043		$	—
	$	8,043		$	—	$	8,043		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(10,726	)	$	—	$	(10,726	)	$	—
	$	(10,726	)	$	—	$	(10,726	)	$	—

At June 30, 2013 and December 31, 2012, management estimates that the derivative contracts had a fair value of ($3.5) million and ($2.7) 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 June 30, 2013, 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 June 30, 2013 was $175.4 million.

Fair Value on a Non-Recurring Basis

As of June 30, 2013, oil and gas properties with a carrying value of $279.4 million were written down to their fair value of $224.1 million, resulting in an impairment charge of $22.4 million and $55.3 million for the three and six months ended June 30, 2013, respectively, which is recognized under “Impairments of oil and gas properties” in the consolidated statements of operations. As of June 30, 2012, oil and gas properties with a carrying value of $229.3 million were written down to their fair value of $226.0 million, resulting in an impairment charge of $3.3 million for each of the three and six months ended June 30, 2012. 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.

The revaluation to asset retirement obligations resulted from revised estimations. Fair values for the asset retirement obligations are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $2.3 million in additions to asset retirement obligations measured at fair value during the three months ended June 30, 2013.

10

NOTE 7—DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:

	June 30, 2013			December 31, 2012
	(in thousands)
	(unaudited)
Senior Secured Revolving Credit Facility	$	25,000		$	52,000
13.75% Senior Secured Notes, net of discount		149,246			149,118
AFCO Credit Corporation-insurance note payble		—			3,552
Other debt		395			—
Total debt		174,641			204,670
Less: current portion		(335	)		(3,552	)
Total long-term debt	$	174,306		$	201,118

Senior Secured Revolving Credit Facility

On December 24, 2010, we entered into an aggregate 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 facility 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.

We have entered into various amendments to the Credit Facility. These amendments have, among other things, (1) changed our amount available for borrowing under the Revolving Credit Facility from $35 million to $25 million, (2) increased the secured letter of credit from $75 million to $200 million, (3) increased the applicable margin with respect to each ABR loan or Eurodollar loan outstanding by 1% if the credit exposure is greater than $15 million, (4) amended certain provisions governing our swap agreements, (5) updated the fees on the letters of credit to 2% on a go-forward basis, (6) updated the “change in control” definition, (7) amended the definition of debt included in the calculation of the covenants, (8) changed the maturity date from December 24, 2013 to January 15, 2014 on the Revolving Credit Facility and to June 22, 2014 on the Letter of Credit Facility, (9) added affirmative covenants to be furnished on a weekly basis including updated cash flow projections, updated accounts payable and accounts receivable schedules, and daily production reports for the week, (10) added an affirmative covenant that we would receive certain specified capital contributions from Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”)or entities designated by PPBE during the first quarter of 2013, (11) revised the definition of “Event of Default” to include non-compliance with new affirmative covenants and (12) restricted returns of capital to our unit holders or distributions of our property to our equity interest holders.

As of June 30, 2013, letters of credit in the aggregate amount of $105.7 million were outstanding under the Letter of Credit Facility. We had $25.0 million in borrowings under the Revolving Credit Facility. As of August 12, 2013, we had no amount available for additional borrowings under the Revolving Credit Facility.

A commitment fee of 0.5% per annum is computed based on the unused borrowing base and paid quarterly. For each of the three and six months ended June 30, 2013, we recognized $4,125 in commitment fees, which have been included in “Interest expense” on the consolidated statements of operations. A letter of credit fee is computed based on the same applicable margin used to determine the interest rate to Eurodollar loans times the stated face amount of each letter of credit.

The Credit Facility is secured by mortgages on at least 80% of the total value of 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 first borrowing base redetermination date for 2013 has been extended to August 30, 2013.

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 payables restriction covenant, which does not allow accounts payable greater than 90 days old to exceed $6.0 million in the aggregate, excluding certain vendors (in each case as defined in our revolving Credit Facility). 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 June 30, 2013, we were not in compliance with the total leverage ratio covenant and the interest coverage ratio covenant. Our total leverage ratio was calculated to be 5.2 to 1.0, which was higher than the required maximum of 2.5 to 1.0. Our interest coverage ratio covenant was calculated to be 1.3 to 1.0, which was lower than the minimum 3.0 to 1.0. We received a limited waiver relating to such covenants in the Tenth Amendment for only the fiscal quarter ended June 30, 2013. In addition to the waiver, the Tenth Amendment also (1) maintains the borrowing base at $25 million through August 30, 2013 and

11

will reduce to $0 on September 2, 2013 either through refinancing by another lender or a purchase agreement by Platinum, (2) releases the liens on the second Renaissance sale that occurred on July 31, 2013 and (3) allows us to retain the proceeds from the second Renaissance sale and up to $5 million in aggregate of any escrow releases from both Renaissance sales or any other collateral sales. See Note 2.

On July 31, 2013, we entered into a loan purchase agreement (the “Letter Loan Purchase Agreement”) with Capital One, N.A., as Administrative Agent, the Lenders and PPVA (Equity) pursuant to which PPVA (Equity) agreed to (i) purchase all of our loans and commitments under the Credit Agreement from the Lenders and (ii) assume the obligations of the Administrative Agent under the Credit Agreement and related loan documents if not refinanced by another lender.

In connection with the Letter Loan Purchase Agreement, on July 31, 2013, Platinum Partners Value Arbitrage Fund L.P. and the other guarantors party thereto (the “Guarantors”) entered into a guaranty (the “Guaranty”) in favor of Capital One, N.A, as Administrative Agent for the benefit of the Lenders under the Credit Agreement. Pursuant to the Guaranty, the Guarantors agreed to guarantee the full, complete and timely performance of obligations of PPVA (Equity) under the Letter Loan Purchase Agreement.

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 BOEMRE 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, at which time all principal then outstanding will be due. As of June 30, 2013, the recorded value of the Notes was $149.2 million, which includes the unamortized discount of $0.8 million. We incurred underwriting and debt issue costs of $7.2 million, which have been capitalized and are being amortized over the life of the Notes.

The Notes are secured by a security interest in our 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 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, impairment of oil and gas properties, and exploration expense for any year thereafter. As of June 30, 2013, we were in compliance with all covenants under the Indenture. However, based on our financial results for 2013 to date, we anticipate that we are unlikely to be in compliance at December 31, 2013 with a covenant respecting maximum capital expenditures. We have the option under the Indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes if we do not believe we will be in compliance with this covenant, however, there can be no assurance that we will have sufficient funds to do so. If the Notes remain outstanding at December 31, 2013 and a default under this covenant actually occurs, then we anticipate we would solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the Indenture, the Indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the Indenture covenant could also result in a cross-default under our bank credit facility.

12

The amounts of required principal payments based on our outstanding debt amounts as of June 30, 2013, were as follows:

Period Ending June 30,	(in thousands)
2014	$	335
2015		25,030
2016		150,030
2017		—
2018		—
		175,395
Unamortized discount on 13.75% Senior Secured Notes		(754	)
Total debt	$	174,641

NOTE 8-PREFERRED UNITS

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 $30 million 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, PPVA (Equity).

The Class D Units were non-voting units, had an aggregate liquidation preference of $30 million and accrued dividends payable in kind at a rate per annum of 24%, compounded annually to the extent they were not distributed. On January 25, 2013, we entered into a contribution agreement with PPVA (Equity), whereby PPVA (Equity) made a capital contribution of $10 million in exchange for 10 million of our Class E Preferred Units (the “Class E Units”) and 76 Class B Units (the “Class B Units”), having such rights, preferences and privileges as set forth in our Third Amendment to Second Amended and Restated Limited Liability Operating Agreement. In addition, we also agreed to issue an additional 43 million Class E Units in exchange for $30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class E Units will receive a preferred return of 20% per annum, which will increase from and after March 25, 2014 to 36% per annum (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement).

During 2013, we entered into contribution agreements with PPBE or the Platinum Group and issued 50.0 million of Class E Units and 3.8 million Class B Units. On March 31, 2013 and June 30, 2013, we issued an additional amount of Class E Units of 2,522,693 and 4,683,471, respectively, as paid-in-kind dividends to the holders of Class E Units on such date.

On February 12, 2013, we entered into an agreement with Platinum under which we agreed to issue Class B Units to Platinum in exchange for financial consulting services, including (1) analysis and assessment of our business and financial condition and compliance with financial covenants in our Credit Facility, (2) discussion with us and senior bank lenders regarding capital contributions and divestitures of non-core assets, and (3) coordination with our attorneys, accountants, and other professionals. On February 12, 2013, we issued 1,131,458.5 Class B Units to PPVA Black Elk (Equity) LLC, an affiliate of Platinum, pursuant to such agreement.

On February 12, 2013, we entered into the Fourth Amendment to the Second Amended and Restated Limited Liability Operating Agreement of the Company (the “Fourth Amendment”). The Fourth Amendment amended the Company’s operating agreement to effectuate a 10,000 to 1 unit split for each of the Class A Units, Class B Units and Class C Units.

NOTE 9—COMMITMENTS AND CONTINGENCIES

General

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.

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For each of the following proceedings, we are currently evaluating the plaintiff’s claims and determining appropriate courses of response with the aid of legal counsel. These proceedings are at a preliminary stage; accordingly, we currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings. Some or all of the costs of defense and liability (if any) may be covered under our General Liability insurance policy. We intend to vigorously defend ourselves in these proceedings. We are currently in the early stages of litigation for each proceeding and are therefore unable to determine whether these proceedings would have a material adverse effect on our financial position, results of operations or cash flows.

West Delta 32

On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform (the “West Delta 32 Incident”). The cause of the West Delta 32 Incident is being investigated by BSEE, in coordination with the U.S. Coast Guard. We are fully cooperating with all government agencies and have engaged ABS Consulting to assist with our investigation. At BSEE’s direction, we engaged an independent third-party auditor to audit our SEMS program. BSEE participated in the audit and after reviewing the results, it issued a letter to Black Elk stating that “Black Elk’s SEMS meets the intent of BSEE regulations and policies, provided that the Corrective Action Plan (“CAP”) is implemented in accordance with Black Elk’s SEMS Audit Report.” We are currently providing regular updates on our CAP progress.

As of August 8, 2013, several civil lawsuits have been filed as a result of the West Delta 32 Incident. On January 8, 2013, five investors in Black Elk Energy, LLC (“BEE”) filed a purported derivative action on behalf of BEE in the 164th Judicial District of Harris County, Texas against our President and CEO, John Hoffman; our majority unit holder, PPVA Black Elk (Equity) LLC; several entities affiliated with PPVA Black Elk (Equity) LLC; and Iron Island Technologies, Inc. The lawsuit originally alleged that the defendants improperly diluted BEE’s percentage ownership in our company and that the defendants’ alleged gross mismanagement harmed BEE by allegedly causing a credit rating downgrade and a prospective buyer to reduce an alleged offer price for our company. The plaintiffs seek an unspecified amount of damages on behalf of BEE in connection with these claims. On July 26, 2013, in response to a motion to dismiss by PPVA Black Elk (Equity) LLC and its affiliated entities, the court dismissed all claims against all defendants. The claims were dismissed with prejudice to re-filing in Texas.

On March 22, 2013, these same investor plaintiffs filed a purported derivative action on behalf of BEE in the Supreme Court of New York County in the State of New York. The suit is filed against our company; John Hoffman; our majority unit holder, PPVA Black Elk (Equity) LLC; several entities and individuals affiliated with PPVA Black Elk (Equity) LLC; and Iron Island Technologies, Inc. The plaintiffs allege that the defendants improperly diluted BEE’s percentage ownership in our company; it is unclear whether plaintiffs are also asserting claims with respect to the West Delta 32 Incident in connection with this separate lawsuit. The plaintiffs seek an unspecified amount of damages individually and on behalf of BEE in connection with these claims. Like the Harris County lawsuit, we believe this claim is without merit and is being defended vigorously.

On January 31, 2013, eight individual plaintiffs sued Black Elk Energy Offshore Operations, LLC (“BEEOO”), BEE, and three independent contractors (Wood Group USA, Inc., Compass Engineering and Consultants, LLC, and Enviro-Tech Specialties, Inc.) in the United States District Court for the Southern District of Texas. The plaintiffs seek to recover for injuries they allege to have suffered in connection with the West Delta 32 Incident. The plaintiffs allege that they were employed by Grand Isle Shipyard, Inc., and that they were working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. The plaintiffs seek $100 million in actual damages and $300 million in punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

On February 27, 2013, the family of decedent Avelino Tajonera sued BEEOO in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Tajonera’s wife individually and on behalf of his estate and Mr. Tajonera’s three children. The plaintiffs allege that Mr. Tajonera was employed by Grand Isle Shipyard, Inc. and was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Tajonera died several days after the West Delta 32 Incident from injuries he sustained therein. The plaintiffs are seeking an unspecified amount of actual and punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

On March 25, 2013, the family of decedent Ellroy Corporal sued our company in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Corporal’s wife individually and on behalf of his estate and Mr. Corporal’s two children. The plaintiffs allege that Mr. Corporal was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Corporal died from complications due to the West Delta 32 Incident. The plaintiffs are seeking an unspecified amount of actual and punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

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On April 29, 2013, Grand Isle Shipyards, Inc. (“GIS”) sued BEE, Enviro Tech Systems, LLC, Wood Group USA, Inc., and Compass Engineering & Consultants, LLC in the United States District Court for the Eastern District of Louisiana for damages it alleged incurred in connection with the West Delta 32 Incident. GIS specifically seeks damages for loss of property and equipment, expenses in the form of indemnity and medical benefits paid to or on behalf of its employees, and for unpaid invoices in connection with the work it performed at West Delta 32. Finally, GIS seeks a declaration that the Louisiana Oilfield Anti-Indemnity Act voids all contractual defense indemnity and additional insured provisions in the Master Service Agreement between GIS and BEE. Upon motion by BEE, however, the court dismissed GIS’ lawsuit and ordered GIS and BEE to first attempt to resolve their claims through mediation, and if that is unsuccessful, then through binding arbitration, pursuant to and in accordance with the MSA. BEE and GIS are in the process of scheduling the mediation of this matter in accordance with the court’s order.

Operating Leases

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 June 30, 2013 were as follows:

During 2012, we entered into two drilling unit contracts. One of the contracts was amended in November 2012 to a total term of 270 days and was extended an additional 180 days on June 3, 2013. The second contract was for the duration of one drill well and was extended to include one additional drill well. Additionally, we purchased leasehold in South Texas and plan to spud a drill well in the third quarter of 2013.

Period Ending June 30,	(in thousands)
2014	$	19,806
2015		2,263
2016		2,072
2017		1,808
2018		1,620
Thereafter		3,856
	$	31,425

Escrow Accounts

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 June 30, 2013, we have funded $15.4 million into the non-operating escrow account, leaving $15.8 million to be funded through May 1, 2017.

The obligations under the W&T Escrow Accounts are fully guaranteed by an affiliate of Platinum. W&T Offshore Inc. (“W&T”) has a first lien on the entirety of the W&T Escrow Accounts, and BP Corporation North America Inc. and Platinum are pari passu second lien holders. Once P&A obligations with respect to the interest in properties acquired from the W&T Acquisition have been fully satisfied, the lien on the W&T Escrow Accounts will be automatically extinguished. W&T also has a second priority lien with respect to the interest in properties acquired from the W&T Acquisition (with Platinum and BNP Paribas sharing a first priority lien), which lien will be released once the W&T Escrow Accounts have been fully funded. On December 19, 2012, we entered into a Third Amendment to Purchase and Sale Agreement (the “Third Amendment”) with W&T. Pursuant to the Third Amendment, we caused performance bonds (the “ARGO Bonds”) in an aggregate amount of $32.6 million to be issued by Argonaut Insurance

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Company to W&T to guaranty our performance of certain plugging and abandonment obligations. Upon receipt of the ARGO Bonds, W&T (i) released its rights to any money held in an escrow account established to secure our performance of certain plugging and abandonment obligations with respect to the Operated Properties Escrow Account, (ii) released the security interest and deposit account control agreement formerly securing its rights in the Operated Properties Escrow Account and (iii) authorized the escrow agent to release such funds from the Operated Properties Escrow Account to or at our direction. In addition, we and W&T agreed that until the funding of an escrow account established to our performance of certain plugging and abandonment obligations with respect to certain non-operated properties is complete, we may not obtain reductions of the ARGO Bonds under any circumstances without W&T’s consent.

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 June 30, 2013, we have funded $10.2 million, leaving $2.9 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 June 30, 2013, we have funded $50.0 million, leaving $10.0 million to be funded through November 2013.

NOTE 10—GAIN ON INVOLUNTARY CONVERSION

High Island 443 A-2

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, BSEE advised us to plug and abandon the well. We have well control insurance and pursued reimbursement for this incident. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drilling are also insurance recoverable.

The claim was approved. We recorded a receivable of $3.1 million for reimbursement, after a deductible of $0.5 million, under our insurance policy at December 31, 2012 and received the funds during the first quarter of 2013. As of June 30, 2013, we recorded a receivable of $3.4 million for additional reimbursement and received these funds in July 2013. We have received a total of approximately $16.8 million in cash for the claim as of August 9, 2013.

NOTE 11—RELATED PARTY TRANSACTIONS

We pay for certain operating and general and administration expenses on behalf of Black Elk Energy, LLC. At both June 30, 2013 and December 31, 2012, we had receivables from Black Elk Energy, LLC in the amount of $23,430.

During 2011, we entered into a contribution agreement with Platinum. We also entered into additional contributions with (PPVA (Equity)) and the Platinum Group in 2013. See Note 8.

On May 28, 2013, FWS entered into an equipment lease agreement with Pea and Eigh Company, LLC (“Pea and Eigh”), a related party of Platinum. The lease began on July 1, 2013 and is payable in monthly installments of approximately $35,000, maturing on December 31, 2013, with an option to purchase the equipment for $1.5 million. As of June 30, 2013, we have not purchased all of the equipment. We currently have restricted cash of $0.7 million for the additional equipment to be purchased as well as advances due to Pea and Eigh, which is included in “Accounts payable and accrued expenses”.

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. The loan was paid off in December 2012 in connection with the sale of Freedom. Before the sale, Freedom provided us with aircraft services, which were prepaid on a monthly basis. As of December 31, 2012, we had a receivable of $0.3 million from Freedom. The receivable was paid on February 26, 2013.

NOTE 12—SUBSEQUENT EVENTS

Sale of Properties. On July 31, 2013, we completed the sale of one field to Renaissance Offshore, LLC for approximately $10.5 million subject to normal purchase price adjustments. Funds were used for general corporate purposes.

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Credit Facility Amendment. On July 31, 2013, we entered into the Tenth Amendment to (1) obtain waivers related to our financial covenants for the second quarter of 2013, (2) maintain the borrowing base at $25 million through August 30, 2013, and will reduce it to $0 on September 2, 2013 either through refinancing by another lender or a purchase agreement by Platinum, (3) release the liens on the second Renaissance sale that occurred on July 31, 2013 and (4) allow us to retain the proceeds from the second Renaissance sale and up to $5 million in aggregate of any escrow releases from both Renaissance sales or any other collateral sales.

Letter Loan Purchase Agreement and Guaranty. On July 31, 2013, we entered into the Letter Loan Purchase Agreement with Capital One, N.A., as Administrative Agent, the Lenders and PPVA (Equity) pursuant to which PPVA (Equity) agreed to (i) purchase all of our loans and commitments under the Credit Agreement from the Lenders and (ii) assume the obligations of the Administrative Agent under the Credit Agreement and related loan documents.

In connection with the Letter Loan Purchase Agreement, on July 31, 2013, the Guarantors entered into the Guaranty in favor of Capital One, N.A, as Administrative Agent for the benefit of the Lenders under the Credit Agreement. Pursuant to the Guaranty, the Guarantors agreed to guarantee the full, complete and timely performance of obligations of PPVA (Equity) under the Letter Loan Purchase Agreement.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

• 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 2012 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;

• Ability to post additional collateral as required by surety companies;

• Cash flow and liquidity;

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

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

• Geological concentration of our reserves;

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

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

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• 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 current litigation matters as a result of the explosion and fire on the West Delta 32-E Platform and other 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;

• Possible referral to the Bureau of Ocean Energy Management to revoke our status as an operator on all of our existing facilities pursuant to a letter received from BSEE on November 21, 2012; 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 2012 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 June 30, 2013, we held an aggregate net interest in approximately 500,370 gross (242,240 net) acres under lease and had an interest in 1,094 gross wells, 258 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 Offshore Operations, LLC and Black Elk Energy Land Operations, LLC were formed on November 20, 2007 as operating subsidiaries of Black Elk Energy, 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 three wholly owned domestic subsidiaries: (i) Black Elk Energy Land Operations, LLC, which is a guarantor under our Indenture, (ii) Black Elk Energy Finance Corp., which is the co-issuer of the Notes and (iii) Freedom Well Services, LLC. Neither Black Elk Energy Land Operations, LLC nor Black Elk Energy Finance Corp has any material assets or operations. Black Elk Energy, LLC owns a minority interest in Black Elk Energy Offshore Operations, LLC.

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.

We have historically grown our business through third-party acquisitions, including the acquisition of our first field, South Timbalier 8, in 2008, which was followed by an additional field acquisition, West Cameron 66, the W&T Acquisition in 2009, the Chroma and Nippon Acquisitions in 2010 and the Maritech and Merit Acquisitions in 2011.

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.

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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 six months ended June 30, 2013 and 2012 are shown in the table below.

	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Oil:
Average price before effects of hedges ($/Bbl)(1)	$	103.98	$	106.03		$	107.00	$	110.30
Average price after effects of hedges ($/Bbl)		101.43		106.84			104.21		107.38
Average price differentials(2)		9.84		12.73			12.78		12.19
Gas:
Average price before effects of hedges ($/Mcf)(1)	$	4.22	$	2.26		$	3.89	$	2.43
Average price after effects of hedges ($/Mcf)		4.46		3.75			4.23		3.56
Average price differentials(2)		0.20		(0.02	)		0.13		0.07

(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.

Oil and natural gas prices remain unstable and we expect them to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

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

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 Events

Safety and Environmental Management Systems (“SEMS”) Audit

On January 17, 2013, we commenced a Bureau of Safety and Environmental Enforcement (“BSEE”) directed Independent Third Party SEMS Audit. The audit was conducted by M&H Energy Services (“M&H”) in three phases: documentation, implementation and offshore facilities. During the offshore phase, 19 platforms were audited for SEMS compliance. BSEE participated as observers in portions of each phase.

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Phase I started with a request from M&H to provide SEMS Program Manual and all documents incorporated by reference. These documents were reviewed for compliance with the requirements of 30 CFR Part 250 Subpart S and API RP 75 (incorporated by reference). Phase 2 kicked off on February 13, 2013 with a review of preliminary findings from Phase 1 and an analysis of SEMS records and documentation to determine how effectively the SEMS was implemented. The Phase 3 Offshore Audit started on March 4, 2013 and covered 19 platforms across our Gulf of Mexico asset areas (East, Central, and West). The final audit phase was completed on March 13, 2013. The Audit Closeout Meeting occurred on March 25, 2013 on schedule with the plan submitted to BSEE. We submitted the Final Audit Report to BSEE on April 10, 2013. The Corrective Action Plan (“CAP”) was submitted to BSEE on April 11, 2013. We received a letter from BSEE on April 24, 2013 stating that the review was complete and that our SEMS meets the intent of the regulations and policies provided that the CAP is implemented in accordance with the SEMS Audit Report. We are currently providing regular updates on our CAP progress.

Performance Improvement Plan (“PIP”)

On November 21, 2012, BSEE sent us a letter requiring us to take certain actions and to improve our performance. The letter made reference to, among other things, the explosion and fire that occurred on our West Delta 32-E platform on November 16, 2012, (the “November 16, 2012 Incident”). BSEE stated in the letter that if we did not improve our performance, we would be subject to additional enforcement action up to and including possible referral to the Bureau of Ocean Energy Management to revoke our status as an operator on all of our existing facilities. We have undertaken the actions BSEE required of us in the November 21 letter and have been regularly reporting our progress on those required improvements to BSEE. We have submitted a PIP to BSEE that identifies corrective action items to improve safety performance in offshore operations. The primary components of the PIP address:

• Independent Third-Party SEMS Audit

• Enhanced oversight of work on our operated platforms

• Hazard Recognition

• Compliance

• Reduction of Incidents of Non-Conformance (INCs)

• Stop Work Authority

• Incentive compensation for safety performance

Implementation of corrective actions is in progress. Many items have been completed, such as the establishment of several new positions within the Health, Safety, Environmental, and Compliance group to provide work oversight and improve regulatory compliance on offshore facilities. Essential documentation such as our Simultaneous Operations (“SIMOPS”) Plan, Project Execution Plans and Contractor Bridging Agreements have been improved to provide better guidelines and procedures for hazard assessment and work controls. Training in Hazard Recognition, Job Safety Analysis and Stop Work Authority is ongoing. Additionally, we have initiated a Production Operations Performance Incentive Program to reward field operations personnel for safe and compliant performance on our facilities.

Based on the receipt of requested work and operation permits along with our interactions with BSEE and our corrective actions discussed above, we believe we have improved our safety and compliance performance and are in good standing as an operator.

High Island 443 A-2

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 BSEE advised us to plug and abandon the well. We have well control insurance and pursued reimbursement for this incident and the claim was approved. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drill are also insurance recoverable. We recorded a receivable of $3.1 million for reimbursement, after a deductible of $0.5 million, under our insurance policy at December 31, 2012 and received the funds during the first quarter of 2013. As of June 30, 2013, we recorded a receivable of $3.4 million for reimbursement and received these funds in July 2013. We have received a total of approximately $16.8 million in cash for the claim as of August 9, 2013.

Capital Contributions

In the first quarter of 2013, we entered into contribution agreements with PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”) or entities designated by PPBE (together, the “Platinum Group”) pursuant to which we have issued 50 million additional Class E Units and 3.8 million additional Class B Units to the Platinum Group for an aggregate offering price of $50.0 million. In addition, we also agreed to issue an additional 43 million Class E Units in exchange for $30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class E Units will receive a preferred return of 20% per annum, which will increase from and after March 25, 2014 to 36% per annum (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement). On March 31, 2013 and June 30, 2013, we issued an additional amount of Class E Units of 2,522,693 and 4,683,471, respectively, as paid-in-kind dividends to the holders of Class E Units.

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Operating Agreement Amendment

On April 9, 2013, we entered into the Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC (the “Fifth Amendment”) to (1) revise and confirm the order and manner of distributions to our members and (2) permit the issuance of Class E Units in an aggregate amount not to exceed $95.0 million and the issuance of Class B Units in connection with such Class E Units in an aggregate amount not to exceed 3,800,000 units before giving effect to any capitalized Class E preferred return, for cash or property capital contributions.

On May 3, 2013, we entered into the Sixth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC (the “Sixth Amendment”) to (1) establish the payment of the Class E Preferred Return to be paid in kind at the end of each calendar quarter to holders of record on that date unless we, with the consent of the Platinum Manager, elect to pay the Class E Preferred Return in cash and (2) establish New Mountain Finance Holdings, LLC as a Class E Member and, in the event that we do not file required reports with the U.S. Securities and Exchange Commission, provide them with rights as an Observer to the Board (as such term is defined by the Sixth Amendment). Additionally, pursuant to the Sixth Amendment, for so long as any Class E Preferred Units are outstanding, we cannot, without the written consent of the Class E Members, issue any equity instruments, including any additional classes of preferred units, that have rights, privileges or priorities that are equal or superior to the rights, privileges, or priorities of the existing Class E Preferred Units.

Letter of Credit Facility Amendment and Credit Facility Amendments

In April 2013, we also entered into the Limited Waiver and Seventh Amendment to Letter of Credit Facility (the “Seventh Amendment”) and the Limited Waiver and Ninth Amendment to our Credit Facility (the “Ninth Amendment”) to obtain waivers related to (1) the leverage ratio for the quarter ended December 31, 2012, (2) the over hedged oil position for the calendar month of January 2013 at December 31, 2012, (3) the hedge requirement only to the extent that it relates to existing oil hedges but that such noncompliance was a result of the sale of the four fields to Renaissance Offshore, LLC, provided that we will be in compliance with the covenant when the borrowing base is re-determined in May 2013 and (4) the delay in the capital contributions, which were all received by April 9, 2013. The Seventh Amendment and the Ninth Amendment removed the current ratio covenant and replaced it with a payables restriction covenant, which does not allow accounts payable greater than 90 days old to exceed $6.0 million in the aggregate, excluding certain vendors. For the quarter ended June 30, 2013 only, the interest coverage ratio covenant was amended to be no less than 2.25 to 1.00 and the leverage ratio covenant was amended to not exceed 3.5 to 1.0. We paid $0.3 million to obtain the waiver.

On July 31, 2013, we entered into the Limited Waiver and Tenth Amendment to our Credit Facility to (1) obtain waivers related to our financial covenants for the second quarter of 2013, (2) maintain the borrowing base at $25 million through August 30, 2013 and will reduce it to $0 on September 2, 2013 either through refinancing by another lender or a purchase agreement by Platinum (3) release the liens on the second Renaissance sale that occurred on July 31, 2013 and (4) allow us to retain the proceeds from the second Renaissance sale and up to $5 million in aggregate of any escrow releases from both Renaissance sales or any other collateral sales.

Letter Loan Purchase Agreement and Guaranty

On July 31, 2013, we entered into the Letter Loan Purchase Agreement with Capital One, N.A., as Administrative Agent, the Lenders and PPVA (Equity) pursuant to which PPVA (Equity) agreed to (i) purchase all of our loans and commitments under the Credit Agreement from the Lenders and (ii) assume the obligations of the Administrative Agent under the Credit Agreement and related loan documents.

In connection with the Letter Loan Purchase Agreement, on July 31, 2013, the Guarantors entered into the Guaranty in favor of Capital One, N.A, as Administrative Agent for the benefit of the Lenders under the Credit Agreement. Pursuant to the Guaranty, the Guarantors agreed to guarantee the full, complete and timely performance of obligations of PPVA (Equity) under the Letter Loan Purchase Agreement.

Sale of Assets

On July 31, 2013, we completed the sale of one field to Renaissance Offshore, LLC for approximately $10.5 million subject to normal purchase price adjustments. Funds were used for general corporate purposes.

Drilling Update

Currently, we have two drilling rigs performing sidetrack operations on our operated properties and one currently drilling on a non-operated property. We successfully completed five wells during the first six months of 2013 all of which encountered pay equal to or above our expectations. Our rig activity during the remainder of 2013 will be dependent on oil and gas prices. Accordingly, our rig count may increase or decrease.

Liquidity Risks and Uncertainties

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As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $93.6 million at June 30, 2013. The combination of restricted credit availability, lower production since the fourth quarter of 2012 and our drilling program led to significant cash reductions in the fourth quarter of 2012 and the first and second quarters of 2013. To increase liquidity, we stretched accounts payable and aggressively pursued accounts receivable. We have worked closely with our vendors during this time and expect to normalize the age of accounts payables within 2013. We continue to optimize our production portfolio and recommenced our drilling program in the fourth quarter of 2012. Currently, we have two rigs under contract, and we expect to drill or complete six operated wells and four non-operated wells in 2013. To fund our drilling programs and operations, we expect to continue to raise additional capital over the next several years. We are currently evaluating new sources of liquidity including, but not limited to, (i) entering into a new revolving credit facility with a traditional bank syndicate or Platinum, our majority owner, and (ii) accessing the debt capital markets. Additionally, we are evaluating potential asset sales of core and non-core assets to optimize our portfolio. On March 26, 2013, we sold four producing fields to Renaissance Offshore, LLC for approximately $52.5 million subject to normal purchase price adjustments. A portion of the proceeds from the sale were used to reduce the amount borrowed under the credit facility (the “Credit Facility”) by $36 million and the remainder has been and will be used for general corporate purposes. We expect that escrows of approximately $9.0 million related to the sold properties will be released and received in the third quarter of 2013. The remainder of the escrow funds released for the sold properties will be used to increase the collateral with the surety companies relating to bonds that had previously been issued that provide us with surety bonds to satisfy the bonding and security requirements of the BOEMRE. We also expect to obtain site clearance on certain properties after the plugging and abandonment (“P&A”) work has been performed and will meet obligations in the escrow agreements to release additional funds of $7.8 million. We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million subject to normal purchase price adjustments.

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. 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. Also, our letters of credit with Capital One are backed entirely by cash. We use letters of credit to back a portion of our surety bonds for P&A obligations.

We were not in compliance with our leverage ratio or our interest rate coverage ratio under our Credit Facility as of June 30, 2013. On July 31, 2013, we entered into the Tenth Amendment to (1) obtain waivers related to our financial covenants for the second quarter of 2013, (2) maintain the borrowing base at $25 million through August 30, 2013, and will reduce it to $0 on September 2, 2013 either through refinancing by another lender or a purchase agreement by Platinum, (3) release the liens on the second Renaissance sale that occurred on July 31, 2013 and (4) allow us to retain the proceeds from the second Renaissance sale and up to $5 million in aggregate of any escrow releases from both Renaissance sales or any other collateral sales. If Platinum purchases the debt, there will be an additional addendum extending the maturity date to July 1, 2014.

As of June 30, 2013, we were in compliance with all covenants under the Indenture. However, based on our financial results for 2013 to date, we anticipate that we are unlikely to be in compliance at December 31, 2013 with a covenant respecting maximum capital expenditures. We have the option under the indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes if we do not believe we will be in compliance with this covenant; however, there can be no assurance that we will have sufficient funds to do so. If the Notes remain outstanding at December 31, 2013 and a default under this covenant actually occurs, then we anticipate we would solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the indenture, the indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the indenture covenant could also result in a cross-default under our bank credit facility.

As discussed above, we are currently evaluating new sources of liquidity including, but not limited to, entering into a new revolving credit facility with a traditional bank syndicate or Platinum, our majority owner, accessing the debt capital markets and potential asset sales of non-core and core properties to optimize our portfolio. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amount and classifications of liabilities that might result from the uncertainty associated with our ability to meet our obligations as they come due. For additional information, please see “Risk Factors” under Item 1A of this Form 10-Q.

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Our capital budget may be adjusted in the future as business conditions warrant and the ultimate amount of capital we expend may fluctuate materially based on market conditions and the success of our drilling program 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 budgeted 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. Our planned operations for the remainder of 2013 reflect our expectations for production based on actual production history and new production expected to be brought online, the continuation of commodity prices near current levels and the higher cost of servicing our additional financing and other obligations.

Our cash flow projections are highly dependent upon numerous assumptions including the timing and rates of production from our wells, the sales prices we realize for our oil and natural gas, the cost to develop and produce our reserves, our ability to monetize our properties and future production through asset sales and financial derivatives, and a number of other factors, some of which are beyond our control. Our inability to increase near-term production levels and generate sufficient liquidity through the actions noted above could result in our inability to meet our obligations as they come due which would have a material adverse effect on our financial position, results of operation and cash flows. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through other financing sources; however, there is no assurance that we will be able to do so in the future if required to meet any short-term liquidity needs.

Our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimation process requires significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, and may differ materially from our actual results. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves requires us to expect that capital will be available to fund their development. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and we intend to continue to develop these reserves, but there is no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet the requirements of our financing obligations.

Our current production is concentrated in the Gulf of Mexico, which is characterized by production declines more rapid than those of conventional onshore properties. As a result, we are particularly vulnerable to a near-term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and severe weather. Any unanticipated significant disruption to, or decline in, our current production levels or prolonged negative changes in commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet our commitments as they come due.

Oil and natural gas development and production in the Gulf of Mexico are regulated by the BOEM and BSEE of the DOI. We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Deepwater Horizon incident in 2010 have changed the way we conduct our business and increased our costs of developing and commissioning new assets. Should there be additional significant future regulations or additional statutory limitations, they could require further changes in the way we conduct our business, further increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico.

As an oil and gas company, our revenue, profitability, cash flows, proved reserves and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our debt and other obligations.

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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 six months ended June 30, 2013 and 2012:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013			2012		2013			2012
Average daily sales:
Oil (Bopd)		4,231			5,617		4,437			5,715
Natural gas (Mcfpd)		36,764			44,410		38,939			53,046
Plant products (Galpd)		24,741			43,055		28,419			41,273
Oil equivalents (Boepd)		10,947			14,044		11,604			15,538
Average realized prices(1):
Oil ($/Bbl)	$	101.43		$	106.84	$	104.21		$	107.38
Natural gas ($/Mcf)		4.46			3.75		4.23			3.56
Plant products ($/Gallon)		0.83			1.00		0.85			1.09
Oil equivalents ($/Boe)		56.03			57.67		56.14			54.56
Costs and Expenses:
Lease operating expense ($/Boe)		47.15			34.41		42.93			30.84
Production tax expense ($/Boe)		0.19			0.16		0.15			0.20
General and administrative expense ($/Boe)		9.42			4.64		8.87			4.37
Net (loss) income (in thousands)		(39,518	)		21,517		(55,730	)		15,863
Adjusted EBITDA(2) (in thousands)		(1,441	)		23,609		8,902			53,710

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

(2) Adjusted EBITDA is defined as net (loss) income before interest expense, net, surety and letter of credit fees, unrealized (gain) loss on derivative instruments, accretion of asset retirement obligations, depreciation, depletion, and amortization, impairment of oil and gas properties, gain on involuntary conversion of assets and loss (gain) on sale of assets. 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 (loss) 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 June  30,						Six Months Ended June  30,
	2013			2012			2013			2012
	(in thousands)
Net (loss) income	$	(39,518	)	$	21,517		$	(55,730	)	$	15,863
Adjusted EBITDA	$	(1,441	)	$	23,609		$	8,902		$	53,710
Reconciliation of Net (loss) income to Adjusted EBITDA
Net (loss) income	$	(39,518	)	$	21,517		$	(55,730	)	$	15,863
Interest expense, net		6,218			6,452			12,481			12,835
Surety and letter of credit fees		2,380			1,674			4,559			2,869
Unrealized (gain) loss on derivative instruments		(5,383	)		(30,230	)		846			(23,504	)
Accretion of asset retirement obligations		7,569			8,892			15,093			17,972
Depreciation, depletion and amortization		11,145			11,873			22,700			24,244
Impairment of oil and gas properties		22,414			3,311			55,377			3,311
Gain on involuntary conversion of assets		(8,250	)		—			(10,633	)		—
Loss (gain) on sale of assets		1,984			120			(35,791	)		120
Adjusted EBITDA	$	(1,441	)	$	23,609		$	8,902		$	53,710

The following table sets forth certain information with respect to oil and gas operations for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,												Six Months Ended June 30,
	2013			2012			Change			% Change			2013			2012			Change			% Change
PRODUCTION:
Oil (MBbl)		385			511			(126	)		-25	%		803			1,040			(237	)		-23	%
Natural gas (MMcf)		3,346			4,041			(695	)		-17	%		7,048			9,654			(2,606	)		-27	%
Plant products (MGal)		2,251			3,918			(1,667	)		-43	%		5,144			7,512			(2,368	)		-32	%
Total (MBoe)		996			1,278			(282	)		-22	%		2,100			2,828			(728	)		-26	%
REVENUES:
Oil sales	$	40,035		$	54,202		$	(14,167	)		-26	%	$	85,936		$	114,720		$	(28,784	)		-25	%
Natural gas sales		14,109			9,149			4,960			54	%		27,446			23,465			3,981			17	%
Plant product sales and other revenue		7,034			6,577			457			7	%		13,674			13,181			493			4	%
Realized (loss) gain on derivative financial instruments		(187	)		6,436			(6,623	)		-103	%		152			7,905			(7,753	)		-98	%
Unrealized gain (loss) on derivative financial instruments		5,383			30,230			(24,847	)		-82	%		(846	)		23,504			(24,350	)		-104	%
TOTAL REVENUES		66,374			106,594			(40,220	)		-38	%		126,362			182,775			(56,413	)		-31	%
OPERATING EXPENSES:
Lease operating		46,971			43,973			2,998			7	%		90,173			87,215			2,958			3	%
Production taxes		189			209			(20	)		-10	%		316			552			(236	)		-43	%
Workover		4,224			3,521			703			20	%		6,284			6,090			194			3	%
Exploration		—			41			(41	)		-100	%		—			938			(938	)		-100	%
Depreciation, depletion and amortization		11,145			11,873			(728	)		-6	%		22,700			24,244			(1,544	)		-6	%
Impairment of oil and gas properties		22,414			3,311			19,103			577	%		55,377			3,311			52,066			1573	%
General and administrative		9,388			5,933			3,455			58	%		18,629			12,367			6,262			51	%
Gain on involuntary conversion of asset		(8,250	)		—			(8,250	)		-100	%		(10,633	)		—			(10,633	)		-100	%
Accretion of asset retirement obligations		7,569			8,892			(1,323	)		-15	%		15,093			17,972			(2,879	)		-16	%
Loss (gain) on sale of assets		1,984			120			1,864			1553	%		(35,791	)		120			(35,911	)		-29926	%
Other operating expenses		1,423			—			1,423			100	%		2,413			—			2,413			100	%
TOTAL OPERATING EXPENSES		97,057			77,873			19,184			25	%		164,561			152,809			11,752			8	%
(LOSS) INCOME FROM OPERATIONS		(30,683	)		28,721			(59,404	)		-207	%		(38,199	)		29,966			(68,165	)		-227	%
OTHER INCOME (EXPENSE):
Interest income		29			13			16			123	%		51			294			(243	)		-83	%
Miscellaneous expense		(2,564	)		(844	)		(1,720	)		204	%		(4,946	)		(1,489	)		(3,457	)		232	%
Interest expense		(6,300	)		(6,373	)		73			-1	%		(12,636	)		(12,908	)		272			-2	%
TOTAL OTHER EXPENSE, NET		(8,835	)		(7,204	)		(1,631	)		23	%		(17,531	)		(14,103	)		(3,428	)		24	%
NET LOSS (INCOME)	$	(39,518	)	$	21,517		$	(61,035	)		-284	%	$	(55,730	)	$	15,863		$	(71,593	)		-451	%

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Production

Oil and natural gas production. Total oil, natural gas and plant product production of 996 MBoe and 2,100 MBoe decreased 282 MBoe, or 22%, and 728 MBoe, or 26%, respectively, during the three and six months ended June 30, 2013 compared to the same periods in 2012 as a result of downtime in the fields requiring hot work, which was delayed due to the BSEE requirements for approval after the West Delta 32 incident, pipeline repairs, and the sale of four fields to Renaissance on March 26, 2013. The year-to-date variance was also a result of winter weather. Production volumes were 44% oil and natural gas liquids (“NGLs”) and 56% natural gas in the three and six months ended June 30, 2013.

Revenues

Total revenues. Total revenues for the three and six months ended June 30, 2013 of $66.4 million and $126.4 million decreased $40.2 million, or 38%, and $56.4 million, or 31%, respectively, over the comparable periods in 2012.

Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, decreased $8.8 million, or 13%, and $24.3 million, or 16%, respectively, for the three and six months ended June 30, 2013 compared to the same periods in 2012 as a result of lower oil, gas and plant product production and lower oil and plant product prices partially offset by higher gas prices.

We entered into certain oil and natural gas commodity derivative contracts in 2013 and 2012. We realized (losses) gains on these derivative contracts in the amounts of ($0.2) million and $0.2 million for the three and six months ended June 30, 2013, respectively, and $6.4 million and $7.9 million for the three and six months ended June 30, 2012, respectively. We recognized unrealized gains (losses) of $5.4 million and ($0.8) million for the three and six months ended June 30, 2013, respectively, and $30.2 million and $23.5 million in the same periods of 2012.

Excluding hedges, we realized average oil prices of $103.98 per barrel and $107.00 per barrel and gas prices of $4.22 per Mcf and $3.89 per Mcf for the three and six months ended June 30, 2013, respectively. For the same periods in 2012, excluding hedges, we realized average oil prices of $106.03 per barrel and $110.30 per barrel and gas prices of $2.26 per Mcf and $2.43 per Mcf, respectively. Oil prices were lower on a quarter and year-to-date basis compared to 2012. We expect commodity prices to remain volatile in the future.

Operating Expenses

Lease operating costs. Our lease operating costs for the three and six months ended June 30, 2013 were $47.0 million, or $47.15 per Boe, and $90.2 million, or $42.93 per Boe. For the three and six months ended June 30, 2012, our lease operating costs were $44.0 million, or $34.41 per Boe, and $87.2 million, or $30.84 per Boe, respectively. Lease operating expenses increased by $3.0 million for the three and six months ended June 30, 2013, respectively, compared to the same periods in 2012, primarily as a result of the West Delta 32 Incident. The increase in cost per Boe during 2013 was primarily attributable to decreased production.

For the three and six months ended June 30, 2013, non-recurring expenses relating to the West Delta 32 Incident included repair and incident investigation costs of $4.3 million and $7.2 million, respectively. In 2013, we remediated Incidents of Noncompliance (“INCs”) and expect the amount of non-recurring expenses incurred in the future to be less.

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Workover costs. Our workover costs for the three and six months ended June 30, 2013 were $4.2 million and $6.3 million, an increase of $0.7 million compared to the second quarter of 2012 and an increase of $0.2 million compared to the first six months in 2012. For the six months ended June 30, 2013, Ship Shoal 176, South Timbalier 190 and Vermilion 120 were the primary workover expense projects.

Exploration. Our exploration expenses for the three and six months ended June 30, 2012 were $41,000 and $0.9 million, respectively. There were no exploration costs for the same period in 2013. Exploration costs for 2012 included expenses to drill a non-operated well, South Pelto 13, which was unsuccessful.

Depreciation, depletion, amortization and impairment. DD&A expense was $11.1 million, or $11.19 per Boe, and $22.7 million, or $10.81 per Boe, for the three and six months ended June 30, 2013, respectively. For the three and six months ended June 30, 2012, DD&A was $11.9 million, or $9.29 per Boe, and $24.2 million, or $8.57 per Boe. The decrease in DD&A for the three and six months ended June 30, 2013 was a result of lower production and reduced asset basis as a result of the impairments recorded in 2013 and 2012. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded a $22.4 million and $55.4 million impairment for the three and six months ended June 30, 2013 and a $3.3 million impairment for the same periods in 2012. The impairment recorded during the three months ended June 30, 2013 resulted primarily from the well drilled at High Island 443. A significant portion of the costs associated with the drilling of this well are recoverable under our insurance policies. As a result, the impairment recorded on this well will be partially offset by the “Gain on Involuntary Conversion of Assets” discussed below. In addition, we recorded an impairment at our South Padre 833 field as the operator will plug and abandon the field. In addition during the three months ended March 31, 2013, we recorded an impairment related to Garden Banks 602 as we elected to non-consent on the deep water well.

General and administrative expenses. G&A expense was $9.4 million, or $9.42 per Boe, and $18.6 million, or $8.87 per Boe, for the three and six months ended June 30, 2013 and $5.9 million, or $4.64 per Boe, and $12.4 million, or $4.37 per Boe, for the same periods in 2012. The increase in G&A expense for the three and six months ended June 30, 2013 was due to an increase in staff, primarily in our drilling and safety groups, and related administrative costs, in addition to higher legal fees relating to the West Delta 32 incident of $0.6 million and $1.1 million, respectively, severance costs, consultant expenses and expenses related to our consolidation of Freedom Well Services, LLC. The increases in G&A expense were partially offset by reclassifying the 2013 surety fees in the amounts of $1.4 million and $2.9 million to “Miscellaneous expense” for the three and six months ended June 30, 2013, respectively.

Gain on involuntary conversion of asset. 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 BSEE advised us to plug and abandon the well. We have well control insurance and pursued reimbursement for this incident and the claim was approved. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drill are also insurance recoverable. We recorded a gain of $8.3 million and $10.6 million as of the three and six months ended June 30, 2013, respectively, for additional proceeds that were received in July 2013.

Accretion expense. We recognized accretion expense of $7.6 million and $15.1 million for the three and six months ended June 30, 2013, respectively, compared to $8.9 million and $18.0 million for the three and six months ended June 30, 2012, respectively. The decrease in accretion expense in 2013 was primarily attributable to P&A activity that was performed in 2012 and the extended life of the remaining assets, partially offset by increased liability, in the first three months of 2013.

(Loss) gain on sale of assets. (Loss) gain on sale of assets of ($2.0) million and $35.8 million for the three and six months ended June 30, 2013, respectively, was primarily related to the sale of four fields to Renaissance Offshore, LLC for approximately $52.5 million subject to normal purchase price adjustments on March 26, 2013.

Other operating expenses. Other operating expenses of $1.4 million and $2.4 million for the three and six months ended June 30, 2013, respectively, were related to our consolidation of Freedom Well Services, LLC. There were no other operating expenses for the same periods in 2012.

Miscellaneous expense. Miscellaneous expense of $2.6 million and $4.9 million for the three and six months ended June 30, 2013, respectively, compared to $0.8 million and $1.5 million for the three and six months ended June 30, 2012, respectively, was primarily due to the surety fee reclassification of $1.4 million and $2.9 million for the three and six months ended June 30, 2013, respectively, as mentioned above under “General and administrative expenses”.

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, cash flows from operations and asset sales. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drill are also insurance recoverable. 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. As described below, we are currently evaluating new sources of liquidity including, but not limited to (i) entering into a new revolving credit facility with a traditional bank syndicate or Platinum, our majority owner, and (ii) accessing the debt capital markets. Additionally, we are evaluating potential asset sales of core and non-core assets to optimize our portfolio.

Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital. If we are unable to enter into a new revolving credit facility, obtain additional contributions or loans from Platinum, or otherwise access new sources of liquidity, our cash flows from operations and other sources of funds may not be sufficient to satisfy our working capital requirements, contractual obligations and expected capital expenditures.

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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 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. 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 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 maturity dates are September 2, 2013 on the Revolving Credit Facility and June 22, 2014 on the Letter of Credit Facility.

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 and the ratio of debt to consolidated EBITDA for the four immediately preceding consecutive fiscal quarters should not exceed 2.5 to 1.0. The most recent amendment removed the current ratio covenant and replaced it with a payables restriction covenant, which does not allow accounts payable greater than 90 days old to exceed $6.0 million in the aggregate, excluding certain vendors.

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.

We have entered into various amendments to the Credit Facility. These amendments have (1) changed our amount available for borrowing under the Revolving Credit Facility from $35 million to $25 million, (2) increased the secured letter of credit from $75 million to $200 million, (3) increased the applicable margin with respect to each ABR loan or Eurodollar loan outstanding by 1% if the credit exposure is greater than $15 million, (4) amended certain provisions governing our swap agreements, (5) updated the fees on the letters of credit to 2% on a go-forward basis, (6) updated the “change in control” definition, (7) amended the definition of debt included in the calculation of the covenants, (8) added affirmative covenants to be furnished on a weekly basis including updated cash flow projections, updated accounts payable and accounts receivable schedules, and daily production reports for the week, (9) added an affirmative covenant that we would receive certain specified capital contributions from Platinum Partners Black Elk Opportunities Fund LLC or entities designated by PPBE (the “Platinum Group”) during the first quarter of 2013, (10) revised the definition of “Event of Default” to include non-compliance with new affirmative covenants and (11) restricted returns of capital to our unitholders or distributions of our property to our equity interest holders.

As of June 30, 2013, we were not in compliance with our interest coverage ratio and leverage ratio. Our total leverage ratio was calculated to be 5.2 to 1.0, which was higher than the required maximum of 2.5 to 1.0. Our interest coverage ratio covenant was calculated to be 1.3 to 1.0, which was lower than the minimum 3.0 to 1.0. We entered into the Tenth Amendment to (1) obtain waivers related to our financial covenants for the second quarter of 2013, (2) maintain the borrowing base at $25 million through August 30, 2013 and will reduce to $0 on September 2, 2013 either through refinancing by another lender or a purchase agreement by Platinum, (3) release the liens on the second Renaissance sale that occurred on July 31, 2013 and (4) allow us to retain the proceeds from the second Renaissance sale and up to $5 million in aggregate of any escrow releases from both Renaissance sales or any other collateral sales.

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In connection with the execution of the Tenth Amendment, we entered into the Letter Loan Purchase Agreement with Capital One, N.A., as Administrative Agent, the Lenders and PPVA (Equity) pursuant to which PPVA (Equity) agreed to (i) purchase all of our loans and commitments under the Credit Agreement from the Lenders and (ii) assume the obligations of the Administrative Agent under the Credit Agreement and related loan documents.

In connection with the Letter Loan Purchase Agreement, on July 31, 2013, the Guarantors entered into the Guaranty in favor of Capital One, N.A, as Administrative Agent for the benefit of the Lenders under the Credit Agreement. Pursuant to the Guaranty, the Guarantors agreed to guarantee the full, complete and timely performance of obligations of PPVA (Equity) under the Letter Loan Purchase Agreement.

We are currently engaged in discussions with other lenders to enter into a new revolving credit facility, which would be used to fund the repayment of our existing Credit Facility and fund future capital expenditures. We can provide no assurances that we will be able to enter in to a new credit facility prior to August 30, 2013 or at all. If Platinum purchases our loan obligations under the Credit Facility, we will have no remaining borrowing capacity. While we may seek additional funds from Platinum, they are under no obligation to provide us with additional capital. In addition to a new revolving credit facility, we are currently evaluating other new sources of liquidity including, but not limited to, accessing the debt capital markets and potential asset sales of non-core and core properties to optimize our portfolio. For additional information, please see “Risk Factors” under Item 1A of this Form 10-Q.

As of June 30, 2013, letters of credit in the aggregate amount of $105.7 million were outstanding under the Letter of Credit Facility and we had $25.0 million in borrowings under the Revolving Credit Facility. As of August 12, 2013, we had no amount 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 7—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 June 30, 2013, we were in compliance with all covenants under the Indenture. However, based on our financial results for 2013 to date, we anticipate that we are unlikely to be in compliance at December 31, 2013 with a covenant respecting maximum capital expenditures. We have the option under the indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes if we do not believe we will be in compliance with this covenant, however, there can be no assurance that we will have sufficient funds to do so. If the Notes remain outstanding at December 31, 2013 and a default under this covenant actually occurs, then we anticipate we would solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the indenture, the indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the indenture covenant could also result in a cross-default under our bank credit facility.

Member Contributions

On May 31, 2011, Platinum entered into a contribution agreement with us, whereby Platinum made a capital contribution of $30 million 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.

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On January 25, 2013, we entered into a contribution agreement with PPVA (Equity), whereby PPVA (Equity) made a capital contribution of $10 million in exchange for 10 million Class E Units and 76 Class B Units, having such rights, preferences and privileges as set forth in our Third Amendment to Second Amended and Restated Limited Liability Operating Agreement. In addition, we also agreed to issue an additional 43 million Class E Units in exchange for $30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class E Units will receive a preferred return of 20% per annum, which will increase from and after March 25, 2014 to 36% per annum (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement).

During 2013, we entered into contribution agreements with PPBE or the Platinum Group pursuant to which we have issued 50.0 million of Class E Units and 3.8 million Class B Units. On March 31, 2013 and June 30, 2013, we issued an additional amount of Class E Units of 2,522,693 and 4,683,471, respectively, as paid-in-kind dividends to the holders of Class E Units on such dates.

On February 12, 2013, we entered into an agreement with Platinum under which we agreed to issue Class B Units to Platinum in exchange for financial consulting services, including (1) analysis and assessment of our business and financial condition and compliance with financial covenants in our credit facility, (2) discussion with us and senior bank lenders regarding capital contributions and divestitures of non-core assets, and (3) coordination with our attorneys, accountants, and other professionals. On February 12, 2013, we issued 1,131,458.5 Class B Units to PPVA Black Elk (Equity) LLC, an affiliate of Platinum, pursuant to such agreement.

Capital Expenditures

We expect total capital expenditures to be approximately $107.6 million for 2013 (excluding expenditures directly related to any acquisitions or costs to be reimbursed by insurance). Approximately $82.3 million was expended in the first six months of 2013 for various projects including recompletions and drilling, and the remaining $25.3 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.

To date, our 2013 capital budget has been funded from cash flow from operations, capital contributions, sale of four fields to Renaissance in March 2013 for $52.5 million and insurance reimbursements for P&A costs on the High Island 443 A-2 well (before a deductible of $0.5 million).

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 six months ended June 30, 2013 and 2012:

	Six Months Ended
	June 30,
	2013			2012
Net cash provided by operating activities	$	26,655		$	26,270
Net cash used in investing activities		(33,535	)		(45,411	)
Net cash provided by financing activities		18,318			18,827
Net increase (decrease) in cash and equivalents	$	11,438		$	(314	)

Cash flows provided by operating activities. Cash provided by operating activities totaled $26.7 million during the six months ended June 30, 2013 compared to $26.3 million during the six months ended June 30, 2012. Significant components of net cash provided by operating activities during the six months ended June 30, 2013 included $31.8 million of changes in operating assets and liabilities and $50.5 million of non-cash items, primarily DD&A expense, impairment and accretion of asset retirement obligations partially offset by the net loss, gain on sale of assets and gain on involuntary conversion of assets.

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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 $33.5 million in the six months ended June 30, 2013 was primarily attributable to $78.4 million in oil and gas property additions associated with the capital drilling program during the period and the $17.1 million funding of the future P&A obligations through escrow partially offset by the sale proceeds of $52.6 million related to the divestiture of four fields to Renaissance Offshore, LLC and $13.5 million in proceeds received from insurance recovery for HI443. Cash used in investing activities in the comparable period of 2012 totaling $45.4 million was attributable to $11.0 million in oil and gas property additions and the $30.7 million funding of the future P&A obligations through escrow.

Cash flows provided by (used in) financing activities. Cash flows provided by financing activities of $18.3 million in the six months ended June 30, 2013 were attributable to $50.0 million in contributions from the Platinum Group and PPVA Equity and $9.0 million of borrowings under the Credit Facility partially offset by $36.0 million of payments on the Credit Facility and $3.4 million in payments on short-term notes. Cash flows provided by financing activities of $18.8 million ended June 30, 2012 were attributable to $121.0 million of borrowings on the Credit Facility and $17.6 million borrowings on short term notes partially offset by $97.0 million of payments on the Credit Facility, $7.7 million in payments on short-term notes, $13.1 million of tax distributions to members and $2.0 million debt issue costs.

Asset Retirement Obligations

As many as four times per year, we review and, to the extent necessary, revise our asset retirement obligation estimates. As of June 30, 2013, we had a decrease in our asset retirement obligations primarily as a result of the sale of four fields to Renaissance Offshore, LLC and in P&A work performed in 2013 partially offset by a revaluation of the liability and accretion expense. For the three and six months ended June 30, 2013, we recognized $7.6 million and $15.1 million in accretion expense, respectively.

At June 30, 2013 and December 31, 2012, we recorded total asset retirement obligations of $322.5 million and $345.5 million, respectively, and have funded approximately $232.4 million and $215.3 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds. As of June 30, 2013 and December 31, 2012, 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 June 30, 2013:

	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	$	175,395	$	335	$	175,060	$	—	$	—
Interest on debt and notes payable		51,475		22,190		29,285		—		—
Operating leases (1)		31,425		19,806		4,335		3,428		3,856
Total contractual obligations		258,295		42,331		208,680		3,428		3,856
Other Obligations
Asset retirement obligations (2)		322,464		33,621		141,319		40,094		107,430
Total obligations (3)	$	580,759	$	75,952	$	349,999	$	43,522	$	111,286

(1) Consists of rig commitments and office space leases for our Texas and Louisiana offices and services provided in the office.

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

(3) Does not include Class D and Class E Cumulative Convertible Participating Preferred Units as they are contingently redeemable at the holders’ option.

Off-Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements.

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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 June 30 2013, commodity derivative instruments were in place covering approximately 56% of our projected oil sales volumes and 31% of our projected natural gas volumes through 2013.

Please see “Notes to Consolidated Financial Statements—Note 5—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 3—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 2012 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 six months ended June 30, 2013, we received an average of $103.98 and $107.00 per barrel of oil and $4.22 and $3.89 per Mcf of natural gas, respectively, before consideration of commodity derivative contracts, compared to $106.03 and $110.30 per barrel of oil and $2.26 and $2.43 per Mcf of natural gas, respectively, in the three and six months ended June 30, 2012. 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 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.

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 six months ended June 30, 2013, our annual revenue would increase or decrease by approximately $16.1 million for each $10.00 per barrel change in oil prices

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and $14.1 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, 2012, our revenues would have increased or decreased by approximately $19.8 million for each $10.00 per barrel change in oil prices and $17.9 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 June 30, 2013, the fair value of our commodity derivatives were included in our consolidated balance sheets for approximately $1.7 million as current liabilities and $1.8 million as long-term liabilities. At December 31, 2012, the fair value of our commodity derivatives was approximately $2.4 million and $5.1 million, which were recorded as current assets and long-term liabilities, respectively. For the three and six months ended June 30, 2013, we realized a net increase (decrease) in oil and natural gas revenues related to hedging transactions of approximately ($0.2) million and $0.2 million, respectively, and increases for the same periods in 2012 of $6.4 million and $7.9 million, respectively.

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As of June 30, 2013, we maintained the following commodity derivative contracts:

Remaining Contract Term: Oil	Contract Type	Notational Volume in Bbls/Month			NYMEX Strike Price
December 2013 - December 2013	Swap		27,750		$	96.90
July 2013 - October 2013	Swap		27,750		$	96.90
November 2013 - November 2013	Swap		26,800		$	96.90
July 2013 - December 2013	Swap		19,750		$	85.90
January 2014 - February 2014	Swap		19,000		$	96.90
January 2014 - December 2014	Swap		15,000		$	65.00
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
July 2013 - July 2013	Swap		23,143		$	88.80
August 2013 - August 2013	Swap		24,915		$	88.80
September 2013 - September 2013	Swap		28,688		$	88.80
October 2013 - October 2013	Swap		28,006		$	88.80
November 2013 - November 2013	Swap		31,605		$	88.80
December 2013 - December 2013	Swap		38,743		$	88.80
January 2014 - January 2014	Swap		4,723		$	88.80
February 2014 - February 2014	Swap		13,313		$	88.80
March 2014 - March 2014	Swap		8,413		$	88.80
April 2014 - April 2014	Swap		12,473		$	88.80
May 2014 - May 2014	Swap		11,793		$	88.80
June 2014 - June 2014	Swap		15,546		$	88.80
July 2014 - July 2014	Swap		11,845		$	88.80
August 2014 - August 2014	Swap		13,165		$	88.80
September 2014 - September 2014	Swap		16,235		$	88.80
October 2014 - October 2014	Swap		15,605		$	88.80
November 2014 - November 2014	Swap		18,525		$	88.80
December 2014 - December 2014	Swap		22,526		$	88.80
July 2013 - July 2013	Swap		15,000		$	87.85
August 2013 - August 2013	Swap		11,000		$	87.85
September 2013 - September 2013	Swap		20,000		$	87.85
October 2013 - October 2013	Swap		4,000		$	87.85
November 2013 - November 2013	Swap		250		$	87.85
December 2013 - December 2013	Swap		2,500		$	87.85
January 2014 - January 2014	Swap		46,000		$	87.85
February 2014 - February 2014	Swap		25,000		$	87.85
March 2014 - March 2014	Swap		56,000		$	87.85
April 2014 - April 2014	Swap		45,000		$	87.85
May 2014 - May 2014	Swap		46,000		$	87.85
June 2014 - June 2014	Swap		48,000		$	87.85
July 2014 - July 2014	Swap		36,000		$	87.85
August 2014 - August 2014	Swap		34,000		$	87.85
September 2014 - September 2014	Swap		26,000		$	87.85
October 2014 - October 2014	Swap		27,000		$	87.85
November 2014 - November 2014	Swap		20,000		$	87.85
December 2014 - December 2014	Swap		31,000		$	87.85
September 2013 - September 2013	Swap		(17,500	)	$	89.15
Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month			NYMEX Strike Price
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
July 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
July 2013 - December 2013	Swap		47,000		$	5.00
July 2013 - July 2013	Swap		36,765		$	4.09
August 2013 - August 2013	Swap		34,275		$	4.09
September 2013 - September 2013	Swap		31,739		$	4.09
October 2013 - October 2013	Swap		34,551		$	4.09
November 2013 - November 2013	Swap		28,939		$	4.09
December 2013 - December 2013	Swap		37,906		$	4.09
January 2014 - January 2014	Swap		43,347		$	4.09
February 2014 - February 2014	Swap		32,636		$	4.09
March 2014 - March 2014	Swap		46,764		$	4.09
April 2014 - April 2014	Swap		41,253		$	4.09
May 2014 - May 2014	Swap		40,391		$	4.09
June 2014 - June 2014	Swap		20,112		$	4.09
July 2014 - July 2014	Swap		39,283		$	4.09
August 2014 - August 2014	Swap		34,246		$	4.09
September 2014 - September 2014	Swap		29,753		$	4.09
October 2014 - October 2014	Swap		28,635		$	4.09
November 2014 - November 2014	Swap		27,081		$	4.09
December 2014 - December 2014	Swap		34,114		$	4.09
January 2015 - January 2015	Swap		27,838		$	4.09
February 2015 - February 2015	Swap		24,461		$	4.09
March 2015 - March 2015	Swap		26,443		$	4.09
June 2014 - June 2014	Swap		40,391		$	4.19
July 2014 - July 2014	Swap		20,112		$	4.19
August 2014 - August 2014	Swap		39,283		$	4.19
September 2014 - September 2014	Swap		34,246		$	4.19
October 2014 - October 2014	Swap		29,753		$	4.19
November 2014 - November 2014	Swap		28,635		$	4.19
December 2014 - December 2014	Swap		27,081		$	4.19
January 2015 - January 2015	Swap		34,114		$	4.19
February 2015 - February 2015	Swap		27,838		$	4.19
March 2015 - March 2015	Swap		24,461		$	4.19

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For a further discussion of our hedging activities, please see “Notes to Consolidated Financial Statements—Note 5—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 $21.2 million at June 30, 2013 and $17.8 million at December 31, 2012. 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 totaled $33.2 million at June 30, 2013 and $27.2 million at December 31, 2012. We also have credit risk associated with our financially settled crude oil and natural gas swaps. As of June 30, 2013, all of our swaps were with BP Energy Company as the counterparty.

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 $25.0 million outstanding under the Revolving Credit Facility as of June 30, 2013, an increase of 100 basis points in the underlying interest rate would have had a $0.3 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.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we have performed an evaluation of the design, operation and effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act) at June 30, 2013. Based on that evaluation, our principal executive officer and principal financial officer concluded that such disclosure controls and procedures were not effective. See “Material Weakness” below.

Material Weakness. In connection with the preparation of our consolidated financial statements for the year ended December 31, 2012, we identified control deficiencies that constituted a material weakness in the design and operation of our internal control over financial reporting. The following material weakness was present at December 31, 2012 and June 30, 2013:

• Financial Close Process: Controls over our financial accounting and reporting processes were deficient in accounting for non-routine and non-systematic transactions. These deficiencies resulted from the difficulty in the following:

• The updated asset portion of the revised estimate of our asset retirement obligations were not included in the impairment computation of Net Book Value.

Remediation. To remediate this material weakness, during 2013, management has and will continue executing the remediation program that began during early 2013, which includes assessing the adequacy of processes and procedures underlying the specific areas discussed above, expanding and strengthening our controls surrounding the multi-client process and strengthening our policies, procedures and controls surrounding accrued expenses ensuring cooperation and coordination with departments outside of the accounting department.

Changes in Internal Control Over Financial Reporting. Other than the measures described above under “Remediation” and the appointment of our Chief Financial Officer, Bruce Koch, on April 16, 2013, there has not been any 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 June 30, 2013 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

West Delta 32 Block Platform Incident. On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform, located in the Gulf of Mexico approximately 17 miles southeast of Grand Isle, Louisiana (“West Delta 32 Incident”). At the time of the explosion, production on the platform had been shut in while crews of independent contractors performed maintenance and construction on the platform.

Three workers died as a result of the explosion and subsequent fire, and others sustained varying degrees of personal injuries. In response to the West Delta 32 Incident, we dispatched two oil spill recovery vessels to the scene to evaluate any potential environmental impact and conduct spill recovery efforts. Based on preliminary estimates of the contents of the three oil tanks involved in the incident, we reported to the required regulatory agencies a loss amount of approximately 480 barrels of oil. There was no loss of containment from any well connected to the platform and no on-going spill following the initial incident. ABS Consulting, a third-party experienced in incident investigation and cause and origin determination, was engaged to assist with our investigation. ABS Consulting provided a report to us and to BSEE on August 13, 2013 that identifies four causal factors that contributed to the incident. Each causal factor applies to a contractor company working on WD-32 at the time of the incident. None of the causal factors apply to Black Elk. Additionally, the ABS Consulting report identified three suggested areas of improvement that were not causes of the incident. The report also includes recommendations for us as well as the contractors involved in the incident. We are currently evaluating the report and its implication on our business. We engaged ES&H Training and Consulting Group to clean the platform to prevent residual oil from being washed or blown into the Gulf of Mexico. This work was completed on November 30, 2012. We have insurance for some potential losses and are pursuing reimbursement for this incident.

Regulatory Investigation and Audit. The cause of the West Delta 32 Incident is being investigated by BSEE, in coordination with the U.S. Coast Guard. This investigation is still ongoing. The United States Chemical Safety and Hazard investigation board has also made inquiry of us regarding the incident but indicated that they will not open an investigation. We are fully cooperating with all government agencies.

On November 21, 2012, BSEE sent us a letter requiring us to take certain actions and to improve our performance. The letter made reference to, among other things, the November 16, 2012 Incident. BSEE stated in the letter that if we did not improve our performance, we would be subject to additional enforcement action up to and including possible referral to the Bureau of Ocean Energy Management to revoke our status as an operator on all of our existing facilities. We have undertaken the actions BSEE required of us in the November 21 letter and have been regularly reporting our progress on those required improvements to BSEE. One of those actions was to engage a third-party company to perform an audit of our entire SEMS program. BSEE participated in the third-party audit and after reviewing the results, it issued a letter to Black Elk on April 24, 2013 stating that “Black Elk’s SEMS meets the intent of BSEE regulations and policies, provided that the Corrective Action Plan is implemented in accordance with Black Elk’s SEMS Audit Report.”

We currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the investigations and the audit. As a result of the investigation, it is possible that BSEE could issue Incidents of Non-Compliance and associated penalties. We intend to vigorously defend the Company against preferential enforcement actions. BSEE has released WD-32 to the control of Black Elk. We have completed repairs and expect to reinitiate production shortly.

For the proceedings listed below, we are currently evaluating the plaintiff’s claims and determining appropriate courses of response with the aid of legal counsel. These proceedings are at a preliminary stage; accordingly, we currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings. Some or all of the costs of defense and liability (if any) may be covered under our General Liability insurance policy. We intend to vigorously defend the Company in these proceedings. We are currently in the early stages of litigation for each proceeding and are therefore unable to determine whether these proceedings would have a material adverse effect on our financial position, results of operations or cash flows.

Civil Litigation. As of August 8, 2013, several civil lawsuits have been filed as a result of the West Delta 32 Incident. On January 8, 2013, five investors in Black Elk Energy, LLC (“BEE”) filed a purported derivative action on behalf of BEE in the 164th Judicial District of Harris County, Texas against our President and CEO, John Hoffman; our majority unit holder, PPVA Black Elk (Equity) LLC; several entities affiliated with PPVA Black Elk (Equity) LLC; and Iron Island Technologies, Inc. The lawsuit originally alleged that the defendants improperly diluted BEE’s percentage ownership in our company and that the defendants’ alleged gross mismanagement harmed BEE by allegedly causing a credit rating downgrade and a prospective buyer to reduce an alleged offer price for our company. The plaintiffs seek an unspecified amount of damages on behalf of BEE in connection with these claims.

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On July 26, 2013, in response to a motion to dismiss by PPVA Black Elk (Equity) LLC and its affiliated entities, the court dismissed all claims against all defendants. The claims were dismissed with prejudice to re-filing in Texas.

On March 22, 2013, these same investor plaintiffs filed a purported derivative action on behalf of BEE in the Supreme Court of New York County in the State of New York. The suit is filed against our company; John Hoffman; our majority unit holder, PPVA Black Elk (Equity) LLC; several entities and individuals affiliated with PPVA Black Elk (Equity) LLC; and Iron Island Technologies, Inc. The plaintiffs allege that the defendants improperly diluted BEE’s percentage ownership in our company; it is unclear whether plaintiffs are also asserting claims with respect to the West Delta 32 Incident in connection with this separate lawsuit. The plaintiffs seek an unspecified amount of damages individually and on behalf of BEE in connection with these claims. Like the Harris County lawsuit, we believe this claim is without merit and is being defended vigorously.

On January 31, 2013, eight individual plaintiffs sued Black Elk Energy Offshore Operations, LLC (“BEEOO”), BEE, and three independent contractors (Wood Group USA, Inc., Compass Engineering and Consultants, LLC, and Enviro-Tech Specialties, Inc.) in the United States District Court for the Southern District of Texas. The plaintiffs seek to recover for injuries they allege to have suffered in connection with the West Delta 32 Incident. The plaintiffs allege that they were employed by Grand Isle Shipyard, Inc., and that they were working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. The plaintiffs seek $100 million in actual damages and $300 million in punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

On February 27, 2013, the family of decedent Avelino Tajonera sued BEEOO in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Tajonera’s wife individually and on behalf of his estate and Mr. Tajonera’s three children. The plaintiffs allege that Mr. Tajonera was employed by Grand Isle Shipyard, Inc. and was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Tajonera died several days after the West Delta 32 Incident from injuries he sustained therein. The plaintiffs are seeking an unspecified amount of actual and punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

On March 25, 2013, the family of decedent Ellroy Corporal sued our company in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Corporal’s wife individually and on behalf of his estate and Mr. Corporal’s two children. The plaintiffs allege that Mr. Corporal was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Corporal died from complications due to the West Delta 32 Incident. The plaintiffs are seeking an unspecified amount of actual and punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

On April 29, 2013, Grand Isle Shipyards, Inc. (“GIS”) sued BEE, Enviro Tech Systems, LLC, Wood Group USA, Inc., and Compass Engineering & Consultants, LLC in the United States District Court for the Eastern District of Louisiana for damages it alleged incurred in connection with the West Delta 32 Incident. GIS specifically seeks damages for loss of property and equipment, expenses in the form of indemnity and medical benefits paid to or on behalf of its employees, and for unpaid invoices in connection with the work it performed at West Delta 32. Finally, GIS seeks a declaration that the Louisiana Oilfield Anti-Indemnity Act voids all contractual defense indemnity and additional insured provisions in the Master Service Agreement between GIS and BEE. Upon motion by BEE, however, the court dismissed GIS’ lawsuit and ordered GIS and BEE to first attempt to resolve their claims through mediation, and if that is unsuccessful, then through binding arbitration, pursuant to and in accordance with the MSA. BEE and GIS are in the process of scheduling the mediation of this matter in accordance with the court’s order.

39

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

Item 1A. Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Risk Factors” in our 2012 Form 10-K. The risks described in the 2012 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 2012 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.

We may be required to post additional collateral in order to satisfy the collateral requirements related to the surety bonds that that secure our P&A obligations.

We are currently subject to the bonding or security requirements of BOEMRE for various obligations, including P&A obligations, for certain federal leases in the Gulf of Mexico. Failure to post the requisite bonds or otherwise satisfy BOEMRE’s security requirements could have a severe adverse effect on our ability to operate in the Gulf of Mexico. Because we are not exempt from the BOEMRE’s bonding requirements, we engage a number of surety companies to post the requisite bonds. Pursuant to the terms of our agreements with these surety companies, we are required to post collateral or post collateral on demand, the amount of which can be increased at the surety companies’ discretion with 30 days’ notice. If these surety companies increase the amount of required collateral, our available liquidity could be adversely affected, which could cause us to modify our 2013 capital expenditure budget. We cannot assure you that we will be able to satisfy any additional collateral requirements. If we fail to do so, we may be in default under our agreements with the surety companies, which in turn could cause a cross-default under our Credit Facility and Indenture. Additionally, should we default under any of our agreements with the surety companies, and should any surety company begin exercising its remedies under these agreements, our operations in the Gulf of Mexico could be severely adversely affected.

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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
**2.1	Purchase and Sale Agreement by and between Black Elk Energy Offshore Operations, LLC as Seller and Renaissance Offshore, LLC as Purchaser, dated as of March 1, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
**2.2	First Amendment to Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and Renaissance Offshore, LLC, effective as of March 22, 2013 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
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).
3.6	Third Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of January 25, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on January 31, 2013).
3.7	Fourth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of February 12, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on February 19, 2013).
3.8	Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of April 9, 2013 (incorporated by reference to Exhibit 3.10 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
3.9	Sixth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 3, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on May 9, 2013).
4.1	Limited Waiver and Ninth Amendment to Credit Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporated by reference to Exhibit 4.39 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
4.2	Limited Waiver and Tenth Amendment to Credit Agreement, effective as of July 31, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on August 5, 2013).

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Exhibit Number	Description
4.3	Limited Waiver and Seventh Amendment to Letter of Credit Facility Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders, and the Lenders signatory thereto (incorporated by reference to Exhibit 4.40 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
†10.1	Employment Agreement, dated as of April 16, 2013, between Bruce Koch 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 April 23, 2013).
†10.2	Offer and Separation Agreement and General Release Offer, dated as of April 1, 2013, by and between Black Elk Energy Offshore Operations, LLC and Douglas W. Fehr (incorporated by reference to Exhibit 10.26 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
10.3	Purchase and Sale Agreement by and between Black Elk Energy Offshore Operations, LLC as Seller and Renaissance Offshore, LLC as Purchaser, dated as of July 31, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on August 5, 2013).
10.4	Letter Loan Purchase Agreement, dated as of July 31, 2013, by and among the Company, PPVA Black Elk Equity LLC, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on August 5, 2013).
10.5	Guaranty, dated as of July 31, 2013, by Platinum Partners Value Arbitrage Fund L.P., Platinum Montaur Life Sciences, LLC, Meserole Group LLC, PPVA Black Elk Investors LLC and DMRJ Group LLC in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders to that certain Credit Agreement dated December 24, 2010, as amended (incorporated by reference to Exhibit 10.4 to the Form 8-K filed with the Securities and Exchange Commission on August 5, 2013).
*31.1	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
101.INS§	XBRL Instance Document
101.SCH§	XBRL Taxonomy Extension Schema Document
101.CAL§	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE§	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF§	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith.

** Pursuant to Item 601(b)(2) of Regulation S-K, the schedules and similar attachments to the Renaissance PSA and First Amendment have not been filed herewith. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.

† Management contract or compensatory plan or arrangement.

§ 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.

42

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)
Date: August 14, 2013	By:	/s/ Bruce Koch
		Bruce Koch
		Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

43

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
**2.1	Purchase and Sale Agreement by and between Black Elk Energy Offshore Operations, LLC as Seller and Renaissance Offshore, LLC as Purchaser, dated as of March 1, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
**2.2	First Amendment to Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and Renaissance Offshore, LLC, effective as of March 22, 2013 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
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).
3.6	Third Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of January 25, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on January 31, 2013).
3.7	Fourth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of February 12, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on February 19, 2013).
3.8	Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of April 9, 2013 (incorporated by reference to Exhibit 3.10 to the Form 8-K filed with the Securities and Exchange Commission on April 15, 2013).
3.9	Sixth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 3, 2013 (incorporated by reference to Exhibit 3.1 to the Form 10-K filed with the Securities and Exchange Commission on May 9, 2013).
4.1	Limited Waiver and Ninth Amendment to Credit Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporated by reference to Exhibit 4.39 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
4.2	Limited Waiver and Tenth Amendment to Credit Agreement, effective as of July 31, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on August 5, 2013).

44

4.3	Limited Waiver and Seventh Amendment to Letter of Credit Facility Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders, and the Lenders signatory thereto (incorporated by reference to Exhibit 4.40 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
†10.1	Employment Agreement, dated as of April 16, 2013, between Bruce Koch 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 April 23, 2013).
†10.2	Offer and Separation Agreement and General Release Offer, dated as of April 1, 2013, by and between Black Elk Energy Offshore Operations, LLC and Douglas W. Fehr (incorporated by reference to Exhibit 10.26 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
10.3	Purchase and Sale Agreement by and between Black Elk Energy Offshore Operations, LLC as Seller and Renaissance Offshore, LLC as Purchaser, dated as of July 31, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on August 5, 2013).
10.4	Letter Loan Purchase Agreement, dated as of July 31, 2013, by and among the Company, PPVA Black Elk Equity LLC, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on August 5, 2013).
10.5	Guaranty, dated as of July 31, 2013, by Platinum Partners Value Arbitrage Fund L.P., Platinum Montaur Life Sciences, LLC, Meserole Group LLC, PPVA Black Elk Investors LLC and DMRJ Group LLC in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders to that certain Credit Agreement dated December 24, 2010, as amended (incorporated by reference to Exhibit 10.4 to the Form 8-K filed with the Securities and Exchange Commission on August 5, 2013).
*31.1	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
101.INS§	XBRL Instance Document
101.SCH§	XBRL Taxonomy Extension Schema Document
101.CAL§	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE§	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF§	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith.

** Pursuant to Item 601(b)(2) of Regulation S-K, the schedules and similar attachments to the Renaissance PSA and First Amendment have not been filed herewith. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.

† Management contract or compensatory plan or arrangement.

§ 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.

45

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, John Hoffman, certify that:

1. I have reviewed this Form 10-Q of Black Elk Energy Offshore Operations, LLC (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 14, 2013	By:	/s/ John Hoffman
	Name:	John Hoffman
	Title:	President and Chief Executive Officer (Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Bruce Koch, certify that:

1. I have reviewed this Form 10-Q of Black Elk Energy Offshore Operations, LLC (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for r establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 14, 2013	By:	/s/ Bruce Koch
	Name:	Bruce Koch
	Title:	Vice President and Chief Financial Officer (Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION

In connection with the Form 10-Q of Black Elk Energy Offshore Operations, LLC (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), John Hoffman, Chief Executive Officer of the Company, and Bruce Koch, Chief Financial Officer of the Company, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his or her knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 14, 2013	By:	/s/ John Hoffman
	Name:	John Hoffman
	Title:	President and Chief Executive Officer (Principal Executive Officer)

Date: August 14, 2013	By:	/s/ Bruce Koch
	Name:	Bruce Koch
	Title:	Vice President and Chief Financial Officer (Principal Financial Officer)

XML

SUBSEQUENT EVENTS

6 Months Ended

Jun. 30, 2013

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

NOTE 12—SUBSEQUENT EVENTS

Sale of Properties. On July 31, 2013, we completed the sale of one field to Renaissance Offshore, LLC for approximately $10.5 million subject to normal purchase price adjustments. Funds were used for general corporate purposes.

Credit Facility Amendment. On July 31, 2013, we entered into the Tenth Amendment to (1) obtain waivers related to our financial covenants for the second quarter of 2013, (2) maintain the borrowing base at $25 million through August 30, 2013, and will reduce it to $0 on September 2, 2013 either through refinancing by another lender or a purchase agreement by Platinum, (3) release the liens on the second Renaissance sale that occurred on July 31, 2013 and (4) allow us to retain the proceeds from the second Renaissance sale and up to $5 million in aggregate of any escrow releases from both Renaissance sales or any other collateral sales.

Letter Loan Purchase Agreement and Guaranty. On July 31, 2013, we entered into the Letter Loan Purchase Agreement with Capital One, N.A., as Administrative Agent, the Lenders and PPVA (Equity) pursuant to which PPVA (Equity) agreed to (i) purchase all of our loans and commitments under the Credit Agreement from the Lenders and (ii) assume the obligations of the Administrative Agent under the Credit Agreement and related loan documents.

In connection with the Letter Loan Purchase Agreement, on July 31, 2013, the Guarantors entered into the Guaranty in favor of Capital One, N.A, as Administrative Agent for the benefit of the Lenders under the Credit Agreement. Pursuant to the Guaranty, the Guarantors agreed to guarantee the full, complete and timely performance of obligations of PPVA (Equity) under the Letter Loan Purchase Agreement.

XML

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
REVENUES:
Oil sales	$ 40,035	$ 54,202	$ 85,936	$ 114,720
Natural gas sales	14,109	9,149	27,446	23,465
Plant product sales and other revenue	7,034	6,577	13,674	13,181
Realized (loss) gain on derivative financial instruments	(187)	6,436	152	7,905
Unrealized gain (loss) on derivative financial instruments	5,383	30,230	(846)	23,504
TOTAL REVENUES	66,374	106,594	126,362	182,775
OPERATING EXPENSES:
Lease operating	46,971	43,973	90,173	87,215
Production taxes	189	209	316	552
Workover	4,224	3,521	6,284	6,090
Exploration		41		938
Depreciation, depletion and amortization	11,145	11,873	22,700	24,244
Impairment of oil and gas properties	22,414	3,311	55,377	3,311
General and administrative	9,388	5,933	18,629	12,367
Gain on involuntary conversion of asset	(8,250)		(10,633)
Accretion of asset retirement obligations	7,569	8,892	15,093	17,972
Loss (gain) on sale of assets	1,984	120	(35,791)	120
Other operating expenses	1,423		2,413
TOTAL OPERATING EXPENSES	97,057	77,873	164,561	152,809
(LOSS) INCOME FROM OPERATIONS	(30,683)	28,721	(38,199)	29,966
OTHER INCOME (EXPENSE):
Interest income	29	13	51	294
Miscellaneous expense	(2,564)	(844)	(4,946)	(1,489)
Interest expense	(6,300)	(6,373)	(12,636)	(12,908)
TOTAL OTHER EXPENSE, NET	(8,835)	(7,204)	(17,531)	(14,103)
NET (LOSS) INCOME	(39,518)	21,517	(55,730)	15,863
LESS: PREFERRED UNIT DIVIDENDS	4,683	1,944	7,826	3,744
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS	$ (44,201)	$ 19,573	$ (63,556)	$ 12,119

XML

DERIVATIVE INSTRUMENTS

6 Months Ended

Jun. 30, 2013

Derivative Instruments And Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

NOTE 5—DERIVATIVE INSTRUMENTS

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

At June 30, 2013, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) (unaudited)):

	Crude Oil											Natural Gas										Total
Period	Volume (Bbls)			Contract Price ($/Bbl)		Asset (Liability)			Fair  Value Gain (Loss)			Volume (MMBtu)		Contract Price ($/MMBtu)		Asset (Liability)			Fair  Value Gain (Loss)			Asset (Liability)			Fair  Value Gain (Loss)
Swaps:						(in thousands)										(in thousands)						(in thousands)
7/13 - 8/13		27,750		$	96.90	$	29		$	29			104,000	$	4.60	$	198		$	198		$	227		$	227
9/13 - 10/13		27,750		$	96.90		89			89			104,000	$	4.60	$	207			207			296			296
11/13 -11/13		26,800			96.90		70			70			104,000		4.60		94			94			164			164
12/13 - 12/13		27,750			96.90		91			91			104,000		4.60		76			76			167			167
1/14 - 2/14		19,000			96.90		159			159			82,000		4.60		105			105			264			264
7/13 - 7/13		7,132			100.80		31			31			148,788		4.94		183			183			214			214
8/13 - 8/13		5,980			100.80		27			27			139,212		4.94		189			189			216			216
9/13 - 9/13		3,897			100.80		20			20			116,125		4.94		156			156			176			176
10/13 - 10/13		3,259			100.80		19			19			91,166		4.94		120			120			139			139
11/13 - 11/13		—			—		—			—			64,926		4.94		80			80			80			80
12/13 - 12/13		10,042			100.80		70			70			119,462		4.94		127			127			197			197
1/14 - 5/14		10,083			100.80		422			422			129,960		4.94		639			639			1,061			1,061
6/14 - 6/14		—			—		—			—			129,960		4.94		125			125			125			125
7/13 - 12/13		19,750			85.90		(1,063	)		(1,063	)		47,000		5.00		371			371			(692	)		(692	)
1/14 - 12/14		15,000			65.00		(3,937	)		(3,937	)		—		—		—			—			(3,937	)		(3,937	)
7/13 - 7/13		23,143			88.80		(179	)		(179	)		36,765		4.09		14			14			(165	)		(165	)
8/13 - 8/13		24,915			88.80		(183	)		(183	)		34,725		4.09		18			18			(165	)		(165	)
9/13 - 9/13		28,688			88.80		(190	)		(190	)		31,739		4.09		16			16			(174	)		(174	)
10/13 - 10/13		28,006			88.80		(164	)		(164	)		34,551		4.09		17			17			(147	)		(147	)
11/13 - 11/13		31,605			88.80		(161	)		(161	)		28,939		4.09		12			12			(149	)		(149	)
12/13 - 12/13		38,743			88.80		(168	)		(168	)		37,906		4.09		10			10			(158	)		(158	)
1/14 - 1/14		4,723			88.80		(17	)		(17	)		43,347		4.09		7			7			(10	)		(10	)
2/14 - 2/14		13,313			88.80		(40	)		(40	)		32,636		4.09		5			5			(35	)		(35	)
3/14 - 3/14		8,413			88.80		(21	)		(21	)		46,764		4.09		9			9			(12	)		(12	)
4/14 - 4/14		12,473			88.80		(25	)		(25	)		41,253		4.09		11			11			(14	)		(14	)
5/14 - 5/14		11,793			88.80		(19	)		(19	)		40,391		4.09		10			10			(9	)		(9	)
6/14 - 6/14		15,546			88.80		(18	)		(18	)		20,112		4.09		4			4			(14	)		(14	)
7/14 - 7/14		11,845			88.80		(9	)		(9	)		39,283		4.09		7			7			(2	)		(2	)
8/14 - 8/14		13,165			88.80		(4	)		(4	)		34,246		4.09		5			5			1			1
9/14 - 9/14		16,235			88.80		—			—			29,753		4.09		5			5			5			5
10/14 - 10/14		15,605			88.80		5			5			28,635		4.09		4			4			9			9
11/14 - 11/14		18,525			88.80		11			11			27,081		4.09		2			2			13			13
12/14 - 12/14		22,526			88.80		22			22			34,114		4.09		(2	)		(2	)		20			20
7/13 - 7/13		15,000			87.85		(130	)		(130	)		—		—		—			—			(130	)		(130	)
8/13 - 8/13		11,000			87.85		(91	)		(91	)		—		—		—			—			(91	)		(91	)
9/13 - 9/13		20,000			87.85		(151	)		(151	)		—		—		—			—			(151	)		(151	)
10/13 - 10/13		4,000			87.85		(27	)		(27	)		—		—		—			—			(27	)		(27	)
11/13 - 11/13		250			87.85		(2	)		(2	)		—		—		—			—			(2	)		(2	)
12/13 - 12/13		2,500			87.85		(13	)		(13	)		—		—		—			—			(13	)		(13	)
1/14 -1/14		46,000			87.85		(206	)		(206	)		—		—		—			—			(206	)		(206	)
2/14 - 2/14		25,000			87.85		(97	)		(97	)		—		—		—			—			(97	)		(97	)
3/14 - 3/14		56,000			87.85		(185	)		(185	)		—		—		—			—			(185	)		(185	)
4/14 - 4/14		45,000			87.85		(129	)		(129	)		—		—		—			—			(129	)		(129	)
5/14 - 5/14		46,000			87.85		(111	)		(111	)		—		—		—			—			(111	)		(111	)
6/14 - 6/14		48,000			87.85		(96	)		(96	)		40,391		4.19		12			12			(84	)		(84	)
7/14 - 7/14		36,000			87.85		(56	)		(56	)		20,112		4.19		5			5			(51	)		(51	)
8/14 - 8/14		34,000			87.85		(39	)		(39	)		39,283		4.19		10			10			(29	)		(29	)
9/14 - 9/14		26,000			87.85		(21	)		(21	)		34,246		4.19		8			8			(13	)		(13	)
10/14 - 10/14		27,000			87.85		(13	)		(13	)		29,753		4.19		7			7			(6	)		(6	)
11/14 - 11/14		20,000			87.85		(4	)		(4	)		28,635		4.19		4			4			—			—
12/14 - 12/14		31,000			87.85		6			6			27,081		4.19		—			—			6			6
9/13 - 9/13		(17,500	)		89.15		110			110			—		—		—			—			110			110
1/15 - 1/15		—			—		—			—			34,114		4.19		(2	)		(2	)		(2	)		(2	)
2/15 - 2/15		—			—		—			—			27,838		4.19		(1	)		(1	)		(1	)		(1	)
3/15 - 3/15		—			—		—			—			24,461		4.19		—			—			—			—
1/15 - 1/15		—			—		—			—			27,838		4.09		(4	)		(4	)		(4	)		(4	)
2/15 - 2/15		—			—		—			—			24,461		4.09		(3	)		(3	)		(3	)		(3	)
3/15 - 3/15		—			—		—			—			26,443		4.09		(2	)		(2	)		(2	)		(2	)
						$	(6,388	)	$	(6,388	)					$	2,858		$	2,858		$	(3,530	)	$	(3,530	)

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

	Asset Derivatives			Liability Derivatives				Asset (Liability) Derivatives Total
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at June 30, 2013		Balance Sheet Location	Fair Value at June 30, 2013			Balance Sheet Location	Fair Value at June 30, 2013
Commodity Contracts	Derivative financial instruments			Derivative financial instruments				Derivative financial instruments
	Current	$	3,953	Current	$	(5,625	)	Current	$	(1,672	)
	Non-current		100	Non-current		(1,958	)	Non-current		(1,858	)
Total derivative instruments		$	4,053		$	(7,583	)		$	(3,530	)
	Asset Derivatives			Liability Derivatives				Asset (Liability) Derivatives Total
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at December 31, 2012		Balance Sheet Location	Fair Value at December 31, 2012			Balance Sheet Location	Fair Value at December 31, 2012
Commodity Contracts	Derivative financial instruments			Derivative financial instruments				Derivative financial instruments
	Current	$	6,808	Current	$	(4,400	)	Current	$	2,408
	Non-current		1,235	Non-current		(6,326	)	Non-current		(5,091	)
Total derivative instruments		$	8,043		$	(10,726	)		$	(2,683	)

We have a netting agreement with our financial institution that permits net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and we routinely exercise our contractual right to offset realized gains against realized losses when settling with our derivative counterparty.

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

Derivatives Not Designated as Hedging		Three Months Ended June  30,					Six Months Ended June 30,
Instruments under Accounting Guidance	Statements of Operations Location	2013			2012		2013			2012
Commodity Contracts	Realized (loss) gain on derivative financial instruments	$	(187	)	$	6,436	$	152		$	7,905
Commodity Contracts	Unrealized gain (loss) on derivative financial instruments		5,383			30,230		(846	)		23,504
Total derivative instruments		$	5,196		$	36,666	$	(694	)	$	31,409

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Liquidity Risks and Uncertainties - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended	1 Months Ended	6 Months Ended		1 Months Ended
	Jun. 30, 2013 Well Fields Rigs	Jul. 31, 2013 Subsequent Event [Member]	Jun. 30, 2013 13.75% Senior Secured Notes, net of discount [Member]	Jun. 30, 2013 13.75% Senior Secured Notes, net of discount [Member] Minimum [Member]	Jul. 31, 2013 Letter of Credit Facility Amendment and Credit Facility Amendment [Member] Subsequent Event [Member]	Jun. 30, 2013 Credit facility [Member]
Concentration Risk [Line Items]
Net working capital	$ 93.6
Number of rigs	2
Number of operated wells expected to be drilled in 2013	6
Number of non-operated wells to be drilled in 2013	4
Number of divested producing fields	4
Purchase price received from sale of four fields	52.5
Purchase price received from sale of additional interest in one field		10.5
Partial sale proceeds from disposition used to reduce the credit facility						36
Escrows related to sold properties	9
Additional funds used to meet obligations in escrow agreements	7.8				5.0
Outstanding balance					$ 25.0
Extended maturity date for purchased debt	Dec. 24, 2013		Dec. 01, 2015		Jul. 31, 2014
Optional redemption repurchase percentage for the 13.75% Senior Secured Notes from December 1, 2013 until December 1, 2014			106.875%
Grace period provided in the indenture			30 days
Aggregated principal amount percentage				25.00%

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BASIS OF PRESENTATION (Policies)

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Nature of Operations

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 November 20, 2007 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

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, 2012 (the “2012 Form 10-K”).

Reclassifications

Reclassifications: Certain reclassifications have been made to conform 2012 balances to our 2013 presentation. Such reclassifications had no effect on net income or cash flow.

Principles of Consolidation

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. Effective January 1, 2013, in accordance with accounting guidelines for consolidation of variable interest entities, we consolidated Freedom Well Services, LLC (“FWS”), as we determined that we are the primary beneficiary of FWS and will have the power to direct the activities of FWS. All material intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in Preparation of Financial Statements

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.

Recent Accounting Pronouncements

Recent Accounting Pronouncements: 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. The adoption of this amendment did not have a material impact on our consolidated financial statements.

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Commitments and Contingencies - Future Minimum Lease Payments Table (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013
Commitments And Contingencies Disclosure [Abstract]
2014	$ 19,806
2015	2,263
2016	2,072
2017	1,808
2018	1,620
Thereafter	3,856
Operating lease, total	$ 31,425

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Acquisitions and Divestitures - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended		1 Months Ended
	Jun. 30, 2013 Fields	Mar. 26, 2013	Jul. 31, 2013 Subsequent Event [Member]	Jun. 30, 2013 Credit facility [Member]
Acquisitions And Discontinued Operations [Line Items]
Number of fields sold to Renaissance	4
Sale price of business fields sold subject to purchases price adjustment		$ 52.5
Partial sale proceeds from disposition used to reduce the credit facility				36
Purchase price received from sale of additional interest in one field			$ 10.5

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Oil and Gas Properties - Schedules of Change to Our Asset Retirement Obligations (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Asset Retirement Obligation Roll Forward Analysis [Roll Forward]
Beginning balance			$ 345,505
Revaluation of liability			2,341
Liabilities relieved due to sale of properties			(22,999)
Liabilities settled			(17,476)
Accretion expense	7,569	8,892	15,093	17,972
Ending balance	322,464		322,464
Less: current portion	33,621		33,621		41,572
Total Long-Term Asset Retirement Obligations	$ 288,843		$ 288,843		$ 303,933

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Debt and Notes Payable - Additional Information (Detail) (USD $)	1 Months Ended	3 Months Ended	6 Months Ended		3 Months Ended	6 Months Ended			1 Months Ended	6 Months Ended		6 Months Ended		6 Months Ended		1 Months Ended	6 Months Ended	12 Months Ended			6 Months Ended
	Jan. 25, 2013	Jun. 30, 2013	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2013 Revolving Credit Facility [Member]	Jun. 30, 2013 Revolving Credit Facility [Member]	Dec. 24, 2010 Revolving Credit Facility [Member]	Aug. 12, 2013 Revolving Credit Facility [Member] Scenario, Forecast [Member]	Jul. 31, 2013 Subsequent Event [Member] Letter of Credit Facility Amendment and Credit Facility Amendment [Member]	Jun. 30, 2013 Minimum [Member] Revolving Credit Facility [Member]	Dec. 24, 2010 Minimum [Member] Revolving Credit Facility [Member]	Jun. 30, 2013 Maximum [Member] Revolving Credit Facility [Member]	Dec. 24, 2010 Maximum [Member] Revolving Credit Facility [Member]	Jun. 30, 2013 Letter of Credit Facility [Member]	Dec. 24, 2010 Letter of Credit Facility [Member]	May 31, 2011 13.75% Senior Secured Notes, net of discount [Member]	Jun. 30, 2013 13.75% Senior Secured Notes, net of discount [Member]	Dec. 31, 2011 13.75% Senior Secured Notes, net of discount [Member]	Dec. 31, 2012 13.75% Senior Secured Notes, net of discount [Member]	Nov. 23, 2010 13.75% Senior Secured Notes, net of discount [Member]	Jun. 30, 2013 13.75% Senior Secured Notes, net of discount [Member] Minimum [Member]	Jun. 30, 2013 13.75% Senior Secured Notes, net of discount [Member] Maximum [Member]
Line of Credit Facility [Line Items]
Aggregate maximum credit facility					$ 25,000,000	$ 25,000,000	$ 35,000,000							$ 200,000,000	$ 75,000,000
Credit facility interest rate description					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.
Margin Applicable in Interest in Credit Facility											2.75%		3.50%
Margin applicable on alternative base rate based on federal funds											1.25%		2.00%
Interest rate on notes/Fee percentage on letter of credit		2.00%	2.00%																	13.75%
Description of amendments to credit facility			Increased the applicable margin with respect to each ABR loan or Eurodollar loan outstanding by 1% if the credit exposure is greater than $15 million,
Line of credit facility, increase in applicable margin after specified credit exposure						1.00%
Minimum specified credit exposure for increase in margin					15,000,000	15,000,000
Credit facility date in original agreement			Dec. 24, 2013						Jul. 31, 2014								Dec. 01, 2015
Credit facility revise maturity date after amendment			Jan. 15, 2014											Jun. 22, 2014
Letter of Credit Outstanding		105,700,000	105,700,000
Outstanding balance					25,000,000	25,000,000			25,000,000
Amount available for additional borrowings under the Revolving Credit Facility								0
Commitment fee percentage per annum computed on unused borrowings base, paid quarterly						0.50%
Commitment fees recognized included in interest expense		4,125,000,000	4,125,000,000
Credit facility covenant requiring percentage of mortgages on total value of the proved oil and gas reserves						80.00%
Leverage ratio						5.2				1.0		2.5									1.0	1.4
Interest coverage ratio						1.3				1.0		3.0
Payables Restriction Covenant-Maximum amount of trade payables excluding certain vendors		6,000,000	6,000,000
Payable restriction covenant, Number of days			90 days
Borrowing base									25,000,000
Maximum Borrowing Capacity, Revolving Credit Facility									0
Escrows release related to the sold properties			7,800,000						5,000,000
Debt instrument face value																				150,000,000
Issue Price Of 13.75% Senior secured notes debt instruments as percentage of face amount																				99.109%
Total debt		174,641,000	174,641,000	204,670,000													149,246,000		149,118,000
Unamortized discount included in recorded notes value		754,000	754,000	882,000													800,000
Underwriting and debt issue costs capitalized																	7,200,000
Repurchase percentage for 13.75% Senior Secured Notes for a Change of Control																	101.00%
Percentage of the 13.75% Senior Secured Notes redeemable until December 1, 2013																	35.00%
Redeemable amount as a percentage of principal amount																	110.00%
Optional redemption repurchase percentage for the 13.75% Senior Secured Notes from December 1, 2013 until December 1, 2014																	106.875%
Consent solicitation fee																4,500,000
Contribution from our majority equity holder	$ 10,000,000															$ 30,000,000
Repurchase percentage for 13.75% Senior Secured Notes																		103.00%
Maximum percent limit on capital expenditure covenant																	30.00%
Grace period provided in the indenture																	30 days

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Related Party Transactions - Additional Information (Detail) (USD $)					6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Dec. 31, 2012 Freedom Logistics LLC [Member]	Oct. 08, 2010 Freedom Logistics LLC [Member] Helicopter	Jun. 30, 2013 Pea and Eigh Company, LLC [Member]
Related Party Transaction Due From To Related Party [Line Items]
Receivables from Black Elk Energy, LLC	$ 23,430	$ 23,430
Lease monthly installments					35,000
Option to purchase equipment					1,500,000
Restricted cash for additional equipment purchased					700,000
Lease maturing					Dec. 31, 2013
Number of helicopters as per purchase agreement				2
Guarantee of Freedom Logistics loan				3,200,000
Receivable from Freedom Logistics			$ 300,000

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Fair Value Measurements - Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets	$ 4,053	$ 8,043
Fair Value of Derivative Liability	(7,583)	(10,726)
Oil and Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets	4,053	8,043
Fair Value of Derivative Liability	(7,583)	(10,726)
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets
Fair Value of Derivative Liability
Level 1 [Member] | Oil and Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets
Fair Value of Derivative Liability
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets	4,053	8,043
Fair Value of Derivative Liability	(7,583)	(10,726)
Level 2 [Member] | Oil and Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets	4,053	8,043
Fair Value of Derivative Liability	(7,583)	(10,726)
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets
Fair Value of Derivative Liability
Level 3 [Member] | Oil and Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets
Fair Value of Derivative Liability

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Oil and Gas Properties - Capitalized Costs Related to Oil and Gas Properties (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Oil And Gas Property Successful Effort Method Net [Abstract]
Proved properties	$ 479,654	$ 451,338
Unproved properties, not subject to depletion	448
Total capitalized costs	480,102	451,338
Accumulated depreciation, depletion, amortization and impairment	(255,998)	(191,326)
Oil and gas properties, net	$ 224,104	$ 260,012

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BASIS OF PRESENTATION

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

BASIS OF PRESENTATION

NOTE 1—BASIS OF PRESENTATION

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 November 20, 2007 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, 2012 (the “2012 Form 10-K”).

Reclassifications: Certain reclassifications have been made to conform 2012 balances to our 2013 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. Effective January 1, 2013, in accordance with accounting guidelines for consolidation of variable interest entities, we consolidated Freedom Well Services, LLC (“FWS”), as we determined that we are the primary beneficiary of FWS and will have the power to direct the activities of FWS. 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.

Recent Accounting Pronouncements: 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. The adoption of this amendment did not have a material impact on our consolidated financial statements.

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OIL AND GAS PROPERTIES

6 Months Ended

Jun. 30, 2013

Property Plant And Equipment [Abstract]

OIL AND GAS PROPERTIES

NOTE 3—OIL AND GAS PROPERTIES

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

	June 30,			December 31,
	2013			2012
	(Unaudited)
	(in thousands)
Proved properties	$	479,654		$	451,338
Unproved properties, not subject to depletion		448			—
Total capitalized costs		480,102			451,338
Accumulated depreciation, depletion, amortization and impairment		(255,988	)		(191,326	)
Oil and gas properties, net	$	224,104		$	260,012

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

	(in thousands)
Balance at December 31, 2012	$	345,505
Revaluation of liability		2,341
Liabilities relieved due to sale of properties		(22,999	)
Liabilities settled		(17,476	)
Accretion expense		15,093
Balance at June 30, 2013	$	322,464
Less: current portion		(33,621	)
Total Long-Term Asset Retirement Obligations	$	288,843

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FAIR VALUE MEASUREMENTS

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

NOTE 6—FAIR VALUE MEASUREMENTS

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

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

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

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

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

The following tables present information about our assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and December 31, 2012 and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands) (unaudited):

	Fair Value Measurements at June 30, 2013 Using Fair Value Hierarchy
	Fair Value as of June 30, 2013			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	4,053		$	—	$	4,053		$	—
	$	4,053		$	—	$	4,053		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(7,583	)	$	—	$	(7,583	)	$	—
	$	(7,583	)	$	—	$	(7,583	)	$	—
	Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	Fair Value as of December 31, 2012			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	8,043		$	—	$	8,043		$	—
	$	8,043		$	—	$	8,043		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(10,726	)	$	—	$	(10,726	)	$	—
	$	(10,726	)	$	—	$	(10,726	)	$	—

At June 30, 2013 and December 31, 2012, management estimates that the derivative contracts had a fair value of ($3.5) million and ($2.7) 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 June 30, 2013, 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 June 30, 2013 was $175.4 million.

Fair Value on a Non-Recurring Basis

As of June 30, 2013, oil and gas properties with a carrying value of $279.4 million were written down to their fair value of $224.1 million, resulting in an impairment charge of $22.4 million and $55.3 million for the three and six months ended June 30, 2013, respectively, which is recognized under “Impairments of oil and gas properties” in the consolidated statements of operations. As of June 30, 2012, oil and gas properties with a carrying value of $229.3 million were written down to their fair value of $226.0 million, resulting in an impairment charge of $3.3 million for each of the three and six months ended June 30, 2012. 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.

The revaluation to asset retirement obligations resulted from revised estimations. Fair values for the asset retirement obligations are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $2.3 million in additions to asset retirement obligations measured at fair value during the three months ended June 30, 2013.

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ACQUISITIONS AND DIVESTITURES

6 Months Ended

Jun. 30, 2013

Business Combinations [Abstract]

ACQUISITIONS AND DIVESTITURES

NOTE 4—ACQUISITIONS AND DIVESTITURES

On March 26, 2013, we completed the sale of four fields to Renaissance for approximately $52.5 million subject to normal purchase price adjustments. Funds were used to reduce the amount borrowed under the Credit Facility by $36 million and for general corporate purposes. We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million, subject to normal purchase price adjustments and will use the funds for general corporate purposes.

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Subsequent Event - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended	1 Months Ended
	Jun. 30, 2013	Jul. 31, 2013 Subsequent Event [Member]	Jul. 31, 2013 Letter of Credit Facility Amendment and Credit Facility Amendment [Member] Subsequent Event [Member]
Subsequent Event [Line Items]
Sale of property		$ 10.5
Borrowing base			25
Escrow release related to properties sold	7.8		5.0
Projected borrowing base			$ 0

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Derivative Instruments - Commodity Derivative Instruments (Detail) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Derivative [Line Items]
Asset (Liability)	$ (3,530)
Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(3,530)
7/13 - 8/13 [Member]
Derivative [Line Items]
Asset (Liability)	227
7/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	227
9/13 - 10/13 [Member]
Derivative [Line Items]
Asset (Liability)	296
9/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	296
11/13 - 11/13 [Member]
Derivative [Line Items]
Asset (Liability)	164
11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	164
12/13 - 12/13 [Member]
Derivative [Line Items]
Asset (Liability)	167
12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	167
1/14 - 2/14 [Member]
Derivative [Line Items]
Asset (Liability)	264
1/14 - 2/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	264
7/13 - 7/13 [Member]
Derivative [Line Items]
Asset (Liability)	214
7/13 - 7/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	214
8/13 - 8/13 [Member]
Derivative [Line Items]
Asset (Liability)	216
8/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	216
9/13 - 9/13 [Member]
Derivative [Line Items]
Asset (Liability)	176
9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	176
10/13 - 10/13 [Member]
Derivative [Line Items]
Asset (Liability)	139
10/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	139
11/13 - 11/13 [Member]
Derivative [Line Items]
Asset (Liability)	80
11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	80
12/13 - 12/13 [Member]
Derivative [Line Items]
Asset (Liability)	197
12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	197
1/14 - 5/14 [Member]
Derivative [Line Items]
Asset (Liability)	1,061
1/14 - 5/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	1,061
6/14 - 6/14 [Member]
Derivative [Line Items]
Asset (Liability)	125
6/14 - 6/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	125
7/13 - 12/13 [Member]
Derivative [Line Items]
Asset (Liability)	(692)
7/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(692)
1/14 - 12/14 [Member]
Derivative [Line Items]
Asset (Liability)	(3,937)
1/14 - 12/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(3,937)
7/13 - 7/13 [Member]
Derivative [Line Items]
Asset (Liability)	(165)
7/13 - 7/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(165)
8/13 - 8/13 [Member]
Derivative [Line Items]
Asset (Liability)	(165)
8/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(165)
9/13 - 9/13 [Member]
Derivative [Line Items]
Asset (Liability)	(174)
9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(174)
10/13 - 10/13 [Member]
Derivative [Line Items]
Asset (Liability)	(147)
10/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(147)
11/13 - 11/13 [Member]
Derivative [Line Items]
Asset (Liability)	(149)
11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(149)
12/13 - 12/13 [Member]
Derivative [Line Items]
Asset (Liability)	(158)
12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(158)
1/14 - 1/14 [Member]
Derivative [Line Items]
Asset (Liability)	(10)
1/14 - 1/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(10)
2/14 - 2/14 [Member]
Derivative [Line Items]
Asset (Liability)	(35)
2/14 - 2/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(35)
3/14 - 3/14 [Member]
Derivative [Line Items]
Asset (Liability)	(12)
3/14 - 3/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(12)
4/14 - 4/14 [Member]
Derivative [Line Items]
Asset (Liability)	(14)
4/14 - 4/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(14)
5/14- 5/14 [Member]
Derivative [Line Items]
Asset (Liability)	(9)
5/14- 5/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(9)
6/14 - 6/14 [Member]
Derivative [Line Items]
Asset (Liability)	(14)
6/14 - 6/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(14)
7/14 - 7/14 [Member]
Derivative [Line Items]
Asset (Liability)	(2)
7/14 - 7/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(2)
8/14 - 8/14 [Member]
Derivative [Line Items]
Asset (Liability)	1
8/14 - 8/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	1
9/14 - 9/14 [Member]
Derivative [Line Items]
Asset (Liability)	5
9/14 - 9/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	5
10/14 - 10/14 [Member]
Derivative [Line Items]
Asset (Liability)	9
10/14 - 10/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	9
11/14 - 11/14 [Member]
Derivative [Line Items]
Asset (Liability)	13
11/14 - 11/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	13
12/14 - 12/14 [Member]
Derivative [Line Items]
Asset (Liability)	20
12/14 - 12/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	20
7/13 - 7/13 [Member]
Derivative [Line Items]
Asset (Liability)	(130)
7/13 - 7/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(130)
8/13 - 8/13 [Member]
Derivative [Line Items]
Asset (Liability)	(91)
8/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(91)
9/13 - 9/13 [Member]
Derivative [Line Items]
Asset (Liability)	(151)
9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(151)
10/13 - 10/13 [Member]
Derivative [Line Items]
Asset (Liability)	(27)
10/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(27)
11/13 - 11/13 [Member]
Derivative [Line Items]
Asset (Liability)	(2)
11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(2)
12/13 - 12/13 [Member]
Derivative [Line Items]
Asset (Liability)	(13)
12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(13)
1/14 - 1/14 [Member]
Derivative [Line Items]
Asset (Liability)	(206)
1/14 - 1/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(206)
2/14 - 2/14 [Member]
Derivative [Line Items]
Asset (Liability)	(97)
2/14 - 2/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(97)
3/14 - 3/14 [Member]
Derivative [Line Items]
Asset (Liability)	(185)
3/14 - 3/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(185)
4/14 - 4/14 [Member]
Derivative [Line Items]
Asset (Liability)	(129)
4/14 - 4/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(129)
5/14 - 5/14 [Member]
Derivative [Line Items]
Asset (Liability)	(111)
5/14 - 5/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(111)
6/14 - 6/14 [Member]
Derivative [Line Items]
Asset (Liability)	(84)
6/14 - 6/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(84)
7/14 - 7/14 [Member]
Derivative [Line Items]
Asset (Liability)	(51)
7/14 - 7/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(51)
8/14 - 8/14 [Member]
Derivative [Line Items]
Asset (Liability)	(29)
8/14 - 8/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(29)
9/14 - 9/14 [Member]
Derivative [Line Items]
Asset (Liability)	(13)
9/14 - 9/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(13)
10/14 - 10/14 [Member]
Derivative [Line Items]
Asset (Liability)	(6)
10/14 - 10/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(6)
11/14 - 11/14 [Member]
Derivative [Line Items]
Asset (Liability)
11/14 - 11/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
12/14 - 12/14 [Member]
Derivative [Line Items]
Asset (Liability)	6
12/14 - 12/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	6
9/13 - 9/13 [Member]
Derivative [Line Items]
Asset (Liability)	110
9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	110
1/15 - 1/15 [Member]
Derivative [Line Items]
Asset (Liability)	(2)
1/15 - 1/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(2)
2/15 - 2/15 [Member]
Derivative [Line Items]
Asset (Liability)	(1)
2/15 - 2/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(1)
3/15 - 3/15 [Member]
Derivative [Line Items]
Asset (Liability)
3/15 - 3/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
1/15 - 1/15 [Member]
Derivative [Line Items]
Asset (Liability)	(4)
1/15 - 1/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(4)
2/15 - 2/15 [Member]
Derivative [Line Items]
Asset (Liability)	(3)
2/15 - 2/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(3)
3/15 - 3/15 [Member]
Derivative [Line Items]
Asset (Liability)	(2)
3/15 - 3/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(2)
Crude Oil [Member]
Derivative [Line Items]
Asset (Liability)	(6,388)
Crude Oil [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(6,388)
Crude Oil [Member] | 7/13 - 8/13 [Member]
Derivative [Line Items]
Volume	27,750
Contract Price ($/MMBtu)	96.90
Asset (Liability)	29
Crude Oil [Member] | 7/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	29
Crude Oil [Member] | 9/13 - 10/13 [Member]
Derivative [Line Items]
Volume	27,750
Contract Price ($/MMBtu)	96.90
Asset (Liability)	89
Crude Oil [Member] | 9/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	89
Crude Oil [Member] | 11/13 - 11/13 [Member]
Derivative [Line Items]
Volume	26,800
Contract Price ($/MMBtu)	96.90
Asset (Liability)	70
Crude Oil [Member] | 11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	70
Crude Oil [Member] | 12/13 - 12/13 [Member]
Derivative [Line Items]
Volume	27,750
Contract Price ($/MMBtu)	96.90
Asset (Liability)	91
Crude Oil [Member] | 12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	91
Crude Oil [Member] | 1/14 - 2/14 [Member]
Derivative [Line Items]
Volume	19,000
Contract Price ($/MMBtu)	96.90
Asset (Liability)	159
Crude Oil [Member] | 1/14 - 2/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	159
Crude Oil [Member] | 7/13 - 7/13 [Member]
Derivative [Line Items]
Volume	7,132
Contract Price ($/MMBtu)	101
Asset (Liability)	31
Crude Oil [Member] | 7/13 - 7/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	31
Crude Oil [Member] | 8/13 - 8/13 [Member]
Derivative [Line Items]
Volume	5,980
Contract Price ($/MMBtu)	101
Asset (Liability)	27
Crude Oil [Member] | 8/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	27
Crude Oil [Member] | 9/13 - 9/13 [Member]
Derivative [Line Items]
Volume	3,897
Contract Price ($/MMBtu)	101
Asset (Liability)	20
Crude Oil [Member] | 9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	20
Crude Oil [Member] | 10/13 - 10/13 [Member]
Derivative [Line Items]
Volume	3,259
Contract Price ($/MMBtu)	101
Asset (Liability)	19
Crude Oil [Member] | 10/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	19
Crude Oil [Member] | 11/13 - 11/13 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Crude Oil [Member] | 11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Crude Oil [Member] | 12/13 - 12/13 [Member]
Derivative [Line Items]
Volume	10,042
Contract Price ($/MMBtu)	101
Asset (Liability)	70
Crude Oil [Member] | 12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	70
Crude Oil [Member] | 1/14 - 5/14 [Member]
Derivative [Line Items]
Volume	10,083
Contract Price ($/MMBtu)	101
Asset (Liability)	422
Crude Oil [Member] | 1/14 - 5/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	422
Crude Oil [Member] | 6/14 - 6/14 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Crude Oil [Member] | 6/14 - 6/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Crude Oil [Member] | 7/13 - 12/13 [Member]
Derivative [Line Items]
Volume	19,750
Contract Price ($/MMBtu)	85.90
Asset (Liability)	(1,063)
Crude Oil [Member] | 7/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(1,063)
Crude Oil [Member] | 1/14 - 12/14 [Member]
Derivative [Line Items]
Volume	15,000
Contract Price ($/MMBtu)	65.00
Asset (Liability)	(3,937)
Crude Oil [Member] | 1/14 - 12/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(3,937)
Crude Oil [Member] | 7/13 - 7/13 [Member]
Derivative [Line Items]
Volume	23,143
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(179)
Crude Oil [Member] | 7/13 - 7/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(179)
Crude Oil [Member] | 8/13 - 8/13 [Member]
Derivative [Line Items]
Volume	24,915
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(183)
Crude Oil [Member] | 8/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(183)
Crude Oil [Member] | 9/13 - 9/13 [Member]
Derivative [Line Items]
Volume	28,688
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(190)
Crude Oil [Member] | 9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(190)
Crude Oil [Member] | 10/13 - 10/13 [Member]
Derivative [Line Items]
Volume	28,006
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(164)
Crude Oil [Member] | 10/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(164)
Crude Oil [Member] | 11/13 - 11/13 [Member]
Derivative [Line Items]
Volume	31,605
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(161)
Crude Oil [Member] | 11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(161)
Crude Oil [Member] | 12/13 - 12/13 [Member]
Derivative [Line Items]
Volume	38,743
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(168)
Crude Oil [Member] | 12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(168)
Crude Oil [Member] | 1/14 - 1/14 [Member]
Derivative [Line Items]
Volume	4,723
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(17)
Crude Oil [Member] | 1/14 - 1/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(17)
Crude Oil [Member] | 2/14 - 2/14 [Member]
Derivative [Line Items]
Volume	13,313
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(40)
Crude Oil [Member] | 2/14 - 2/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(40)
Crude Oil [Member] | 3/14 - 3/14 [Member]
Derivative [Line Items]
Volume	8,413
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(21)
Crude Oil [Member] | 3/14 - 3/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(21)
Crude Oil [Member] | 4/14 - 4/14 [Member]
Derivative [Line Items]
Volume	12,473
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(25)
Crude Oil [Member] | 4/14 - 4/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(25)
Crude Oil [Member] | 5/14- 5/14 [Member]
Derivative [Line Items]
Volume	11,793
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(19)
Crude Oil [Member] | 5/14- 5/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(19)
Crude Oil [Member] | 6/14 - 6/14 [Member]
Derivative [Line Items]
Volume	15,546
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(18)
Crude Oil [Member] | 6/14 - 6/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(18)
Crude Oil [Member] | 7/14 - 7/14 [Member]
Derivative [Line Items]
Volume	11,845
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(9)
Crude Oil [Member] | 7/14 - 7/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(9)
Crude Oil [Member] | 8/14 - 8/14 [Member]
Derivative [Line Items]
Volume	13,165
Contract Price ($/MMBtu)	88.80
Asset (Liability)	(4)
Crude Oil [Member] | 8/14 - 8/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(4)
Crude Oil [Member] | 9/14 - 9/14 [Member]
Derivative [Line Items]
Volume	16,235
Contract Price ($/MMBtu)	88.80
Asset (Liability)
Crude Oil [Member] | 9/14 - 9/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Crude Oil [Member] | 10/14 - 10/14 [Member]
Derivative [Line Items]
Volume	15,605
Contract Price ($/MMBtu)	88.80
Asset (Liability)	5
Crude Oil [Member] | 10/14 - 10/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	5
Crude Oil [Member] | 11/14 - 11/14 [Member]
Derivative [Line Items]
Volume	18,525
Contract Price ($/MMBtu)	88.80
Asset (Liability)	11
Crude Oil [Member] | 11/14 - 11/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	11
Crude Oil [Member] | 12/14 - 12/14 [Member]
Derivative [Line Items]
Volume	22,526
Contract Price ($/MMBtu)	88.80
Asset (Liability)	22
Crude Oil [Member] | 12/14 - 12/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	22
Crude Oil [Member] | 7/13 - 7/13 [Member]
Derivative [Line Items]
Volume	15,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(130)
Crude Oil [Member] | 7/13 - 7/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(130)
Crude Oil [Member] | 8/13 - 8/13 [Member]
Derivative [Line Items]
Volume	11,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(91)
Crude Oil [Member] | 8/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(91)
Crude Oil [Member] | 9/13 - 9/13 [Member]
Derivative [Line Items]
Volume	20,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(151)
Crude Oil [Member] | 9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(151)
Crude Oil [Member] | 10/13 - 10/13 [Member]
Derivative [Line Items]
Volume	4,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(27)
Crude Oil [Member] | 10/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(27)
Crude Oil [Member] | 11/13 - 11/13 [Member]
Derivative [Line Items]
Volume	250
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(2)
Crude Oil [Member] | 11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(2)
Crude Oil [Member] | 12/13 - 12/13 [Member]
Derivative [Line Items]
Volume	2,500
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(13)
Crude Oil [Member] | 12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(13)
Crude Oil [Member] | 1/14 - 1/14 [Member]
Derivative [Line Items]
Volume	46,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(206)
Crude Oil [Member] | 1/14 - 1/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(206)
Crude Oil [Member] | 2/14 - 2/14 [Member]
Derivative [Line Items]
Volume	25,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(97)
Crude Oil [Member] | 2/14 - 2/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(97)
Crude Oil [Member] | 3/14 - 3/14 [Member]
Derivative [Line Items]
Volume	56,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(185)
Crude Oil [Member] | 3/14 - 3/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(185)
Crude Oil [Member] | 4/14 - 4/14 [Member]
Derivative [Line Items]
Volume	45,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(129)
Crude Oil [Member] | 4/14 - 4/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(129)
Crude Oil [Member] | 5/14 - 5/14 [Member]
Derivative [Line Items]
Volume	46,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(111)
Crude Oil [Member] | 5/14 - 5/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(111)
Crude Oil [Member] | 6/14 - 6/14 [Member]
Derivative [Line Items]
Volume	48,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(96)
Crude Oil [Member] | 6/14 - 6/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(96)
Crude Oil [Member] | 7/14 - 7/14 [Member]
Derivative [Line Items]
Volume	36,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(56)
Crude Oil [Member] | 7/14 - 7/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(56)
Crude Oil [Member] | 8/14 - 8/14 [Member]
Derivative [Line Items]
Volume	34,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(39)
Crude Oil [Member] | 8/14 - 8/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(39)
Crude Oil [Member] | 9/14 - 9/14 [Member]
Derivative [Line Items]
Volume	26,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(21)
Crude Oil [Member] | 9/14 - 9/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(21)
Crude Oil [Member] | 10/14 - 10/14 [Member]
Derivative [Line Items]
Volume	27,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(13)
Crude Oil [Member] | 10/14 - 10/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(13)
Crude Oil [Member] | 11/14 - 11/14 [Member]
Derivative [Line Items]
Volume	20,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	(4)
Crude Oil [Member] | 11/14 - 11/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(4)
Crude Oil [Member] | 12/14 - 12/14 [Member]
Derivative [Line Items]
Volume	31,000
Contract Price ($/MMBtu)	87.85
Asset (Liability)	6
Crude Oil [Member] | 12/14 - 12/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	6
Crude Oil [Member] | 9/13 - 9/13 [Member]
Derivative [Line Items]
Volume	(17,500)
Contract Price ($/MMBtu)	89.15
Asset (Liability)	110
Crude Oil [Member] | 9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	110
Crude Oil [Member] | 1/15 - 1/15 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Crude Oil [Member] | 1/15 - 1/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Crude Oil [Member] | 2/15 - 2/15 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Crude Oil [Member] | 2/15 - 2/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Crude Oil [Member] | 3/15 - 3/15 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Crude Oil [Member] | 3/15 - 3/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Crude Oil [Member] | 1/15 - 1/15 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Crude Oil [Member] | 1/15 - 1/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Crude Oil [Member] | 2/15 - 2/15 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Crude Oil [Member] | 2/15 - 2/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Crude Oil [Member] | 3/15 - 3/15 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Crude Oil [Member] | 3/15 - 3/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member]
Derivative [Line Items]
Asset (Liability)	2,858
Natural Gas [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	2,858
Natural Gas [Member] | 7/13 - 8/13 [Member]
Derivative [Line Items]
Volume	104,000
Contract Price ($/MMBtu)	4.60
Asset (Liability)	198
Natural Gas [Member] | 7/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	198
Natural Gas [Member] | 9/13 - 10/13 [Member]
Derivative [Line Items]
Volume	104,000
Contract Price ($/MMBtu)	4.60
Asset (Liability)	207
Natural Gas [Member] | 9/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	207
Natural Gas [Member] | 11/13 - 11/13 [Member]
Derivative [Line Items]
Volume	104,000
Contract Price ($/MMBtu)	4.60
Asset (Liability)	94
Natural Gas [Member] | 11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	94
Natural Gas [Member] | 12/13 - 12/13 [Member]
Derivative [Line Items]
Volume	104,000
Contract Price ($/MMBtu)	4.60
Asset (Liability)	76
Natural Gas [Member] | 12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	76
Natural Gas [Member] | 1/14 - 2/14 [Member]
Derivative [Line Items]
Volume	82,000
Contract Price ($/MMBtu)	4.60
Asset (Liability)	105
Natural Gas [Member] | 1/14 - 2/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	105
Natural Gas [Member] | 7/13 - 7/13 [Member]
Derivative [Line Items]
Volume	148,788
Contract Price ($/MMBtu)	4.94
Asset (Liability)	183
Natural Gas [Member] | 7/13 - 7/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	183
Natural Gas [Member] | 8/13 - 8/13 [Member]
Derivative [Line Items]
Volume	139,212
Contract Price ($/MMBtu)	4.94
Asset (Liability)	189
Natural Gas [Member] | 8/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	189
Natural Gas [Member] | 9/13 - 9/13 [Member]
Derivative [Line Items]
Volume	116,125
Contract Price ($/MMBtu)	4.94
Asset (Liability)	156
Natural Gas [Member] | 9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	156
Natural Gas [Member] | 10/13 - 10/13 [Member]
Derivative [Line Items]
Volume	91,166
Contract Price ($/MMBtu)	4.94
Asset (Liability)	120
Natural Gas [Member] | 10/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	120
Natural Gas [Member] | 11/13 - 11/13 [Member]
Derivative [Line Items]
Volume	64,926
Contract Price ($/MMBtu)	4.94
Asset (Liability)	80
Natural Gas [Member] | 11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	80
Natural Gas [Member] | 12/13 - 12/13 [Member]
Derivative [Line Items]
Volume	119,462
Contract Price ($/MMBtu)	4.94
Asset (Liability)	127
Natural Gas [Member] | 12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	127
Natural Gas [Member] | 1/14 - 5/14 [Member]
Derivative [Line Items]
Volume	129,960
Contract Price ($/MMBtu)	4.94
Asset (Liability)	639
Natural Gas [Member] | 1/14 - 5/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	639
Natural Gas [Member] | 6/14 - 6/14 [Member]
Derivative [Line Items]
Volume	129,960
Contract Price ($/MMBtu)	4.94
Asset (Liability)	125
Natural Gas [Member] | 6/14 - 6/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	125
Natural Gas [Member] | 7/13 - 12/13 [Member]
Derivative [Line Items]
Volume	47,000
Contract Price ($/MMBtu)	5.00
Asset (Liability)	371
Natural Gas [Member] | 7/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	371
Natural Gas [Member] | 1/14 - 12/14 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 1/14 - 12/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 7/13 - 7/13 [Member]
Derivative [Line Items]
Volume	36,765
Contract Price ($/MMBtu)	4.09
Asset (Liability)	14
Natural Gas [Member] | 7/13 - 7/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	14
Natural Gas [Member] | 8/13 - 8/13 [Member]
Derivative [Line Items]
Volume	34,725
Contract Price ($/MMBtu)	4.09
Asset (Liability)	18
Natural Gas [Member] | 8/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	18
Natural Gas [Member] | 9/13 - 9/13 [Member]
Derivative [Line Items]
Volume	31,739
Contract Price ($/MMBtu)	4.09
Asset (Liability)	16
Natural Gas [Member] | 9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	16
Natural Gas [Member] | 10/13 - 10/13 [Member]
Derivative [Line Items]
Volume	34,551
Contract Price ($/MMBtu)	4.09
Asset (Liability)	17
Natural Gas [Member] | 10/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	17
Natural Gas [Member] | 11/13 - 11/13 [Member]
Derivative [Line Items]
Volume	28,939
Contract Price ($/MMBtu)	4.09
Asset (Liability)	12
Natural Gas [Member] | 11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	12
Natural Gas [Member] | 12/13 - 12/13 [Member]
Derivative [Line Items]
Volume	37,906
Contract Price ($/MMBtu)	4.09
Asset (Liability)	10
Natural Gas [Member] | 12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	10
Natural Gas [Member] | 1/14 - 1/14 [Member]
Derivative [Line Items]
Volume	43,347
Contract Price ($/MMBtu)	4.09
Asset (Liability)	7
Natural Gas [Member] | 1/14 - 1/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	7
Natural Gas [Member] | 2/14 - 2/14 [Member]
Derivative [Line Items]
Volume	32,636
Contract Price ($/MMBtu)	4.09
Asset (Liability)	5
Natural Gas [Member] | 2/14 - 2/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	5
Natural Gas [Member] | 3/14 - 3/14 [Member]
Derivative [Line Items]
Volume	46,764
Contract Price ($/MMBtu)	4.09
Asset (Liability)	9
Natural Gas [Member] | 3/14 - 3/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	9
Natural Gas [Member] | 4/14 - 4/14 [Member]
Derivative [Line Items]
Volume	41,253
Contract Price ($/MMBtu)	4.09
Asset (Liability)	11
Natural Gas [Member] | 4/14 - 4/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	11
Natural Gas [Member] | 5/14- 5/14 [Member]
Derivative [Line Items]
Volume	40,391
Contract Price ($/MMBtu)	4.09
Asset (Liability)	10
Natural Gas [Member] | 5/14- 5/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	10
Natural Gas [Member] | 6/14 - 6/14 [Member]
Derivative [Line Items]
Volume	20,112
Contract Price ($/MMBtu)	4.09
Asset (Liability)	4
Natural Gas [Member] | 6/14 - 6/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	4
Natural Gas [Member] | 7/14 - 7/14 [Member]
Derivative [Line Items]
Volume	39,283
Contract Price ($/MMBtu)	4.09
Asset (Liability)	7
Natural Gas [Member] | 7/14 - 7/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	7
Natural Gas [Member] | 8/14 - 8/14 [Member]
Derivative [Line Items]
Volume	34,246
Contract Price ($/MMBtu)	4.09
Asset (Liability)	5
Natural Gas [Member] | 8/14 - 8/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	5
Natural Gas [Member] | 9/14 - 9/14 [Member]
Derivative [Line Items]
Volume	29,753
Contract Price ($/MMBtu)	4.09
Asset (Liability)	5
Natural Gas [Member] | 9/14 - 9/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	5
Natural Gas [Member] | 10/14 - 10/14 [Member]
Derivative [Line Items]
Volume	28,635
Contract Price ($/MMBtu)	4.09
Asset (Liability)	4
Natural Gas [Member] | 10/14 - 10/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	4
Natural Gas [Member] | 11/14 - 11/14 [Member]
Derivative [Line Items]
Volume	27,081
Contract Price ($/MMBtu)	4.09
Asset (Liability)	2
Natural Gas [Member] | 11/14 - 11/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	2
Natural Gas [Member] | 12/14 - 12/14 [Member]
Derivative [Line Items]
Volume	34,114
Contract Price ($/MMBtu)	4.09
Asset (Liability)	(2)
Natural Gas [Member] | 12/14 - 12/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(2)
Natural Gas [Member] | 7/13 - 7/13 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 7/13 - 7/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 8/13 - 8/13 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 8/13 - 8/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 9/13 - 9/13 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 10/13 - 10/13 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 10/13 - 10/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 11/13 - 11/13 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 11/13 - 11/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 12/13 - 12/13 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 12/13 - 12/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 1/14 - 1/14 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 1/14 - 1/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 2/14 - 2/14 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 2/14 - 2/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 3/14 - 3/14 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 3/14 - 3/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 4/14 - 4/14 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 4/14 - 4/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 5/14 - 5/14 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 5/14 - 5/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 6/14 - 6/14 [Member]
Derivative [Line Items]
Volume	40,391
Contract Price ($/MMBtu)	4.19
Asset (Liability)	12
Natural Gas [Member] | 6/14 - 6/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	12
Natural Gas [Member] | 7/14 - 7/14 [Member]
Derivative [Line Items]
Volume	20,112
Contract Price ($/MMBtu)	4.19
Asset (Liability)	5
Natural Gas [Member] | 7/14 - 7/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	5
Natural Gas [Member] | 8/14 - 8/14 [Member]
Derivative [Line Items]
Volume	39,283
Contract Price ($/MMBtu)	4.19
Asset (Liability)	10
Natural Gas [Member] | 8/14 - 8/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	10
Natural Gas [Member] | 9/14 - 9/14 [Member]
Derivative [Line Items]
Volume	34,246
Contract Price ($/MMBtu)	4.19
Asset (Liability)	8
Natural Gas [Member] | 9/14 - 9/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	8
Natural Gas [Member] | 10/14 - 10/14 [Member]
Derivative [Line Items]
Volume	29,753
Contract Price ($/MMBtu)	4.19
Asset (Liability)	7
Natural Gas [Member] | 10/14 - 10/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	7
Natural Gas [Member] | 11/14 - 11/14 [Member]
Derivative [Line Items]
Volume	28,635
Contract Price ($/MMBtu)	4.19
Asset (Liability)	4
Natural Gas [Member] | 11/14 - 11/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	4
Natural Gas [Member] | 12/14 - 12/14 [Member]
Derivative [Line Items]
Volume	27,081
Contract Price ($/MMBtu)	4.19
Asset (Liability)
Natural Gas [Member] | 12/14 - 12/14 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 9/13 - 9/13 [Member]
Derivative [Line Items]
Volume
Contract Price ($/MMBtu)
Asset (Liability)
Natural Gas [Member] | 9/13 - 9/13 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 1/15 - 1/15 [Member]
Derivative [Line Items]
Volume	34,114
Contract Price ($/MMBtu)	4.19
Asset (Liability)	(2)
Natural Gas [Member] | 1/15 - 1/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(2)
Natural Gas [Member] | 2/15 - 2/15 [Member]
Derivative [Line Items]
Volume	27,838
Contract Price ($/MMBtu)	4.19
Asset (Liability)	(1)
Natural Gas [Member] | 2/15 - 2/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(1)
Natural Gas [Member] | 3/15 - 3/15 [Member]
Derivative [Line Items]
Volume	24,461
Contract Price ($/MMBtu)	4.19
Asset (Liability)
Natural Gas [Member] | 3/15 - 3/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)
Natural Gas [Member] | 1/15 - 1/15 [Member]
Derivative [Line Items]
Volume	27,838
Contract Price ($/MMBtu)	4.09
Asset (Liability)	(4)
Natural Gas [Member] | 1/15 - 1/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(4)
Natural Gas [Member] | 2/15 - 2/15 [Member]
Derivative [Line Items]
Volume	24,461
Contract Price ($/MMBtu)	4.09
Asset (Liability)	(3)
Natural Gas [Member] | 2/15 - 2/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	(3)
Natural Gas [Member] | 3/15 - 3/15 [Member]
Derivative [Line Items]
Volume	26,443
Contract Price ($/MMBtu)	4.09
Asset (Liability)	(2)
Natural Gas [Member] | 3/15 - 3/15 [Member] | Fair Value [Member]
Derivative [Line Items]
Fair Value Gain (Loss)	$ (2)

XML

Fair Value Measurements - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts, fair value	$ (3,500,000)		$ (3,500,000)		$ (2,700,000)
Debt, fair value	175,400,000		175,400,000
Oil and gas properties, fair value	224,104,000		224,104,000		260,012,000
Impairment	22,414,000	3,311,000	55,377,000	3,311,000
Additional asset retirement obligations	322,464,000		322,464,000		345,505,000
Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Oil and gas properties with a carrying value	279,400,000	229,300,000	279,400,000	229,300,000
Oil and gas properties, fair value	224,100,000	226,000,000	224,100,000	226,000,000
Impairment	22,400,000	3,300,000	55,300,000	3,300,000
Additional asset retirement obligations	$ 2,300,000		$ 2,300,000

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Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended			12 Months Ended			12 Months Ended	6 Months Ended		6 Months Ended		12 Months Ended		1 Months Ended
	Jun. 03, 2013	Jan. 31, 2013 Person Contractor	Nov. 30, 2012	Dec. 31, 2012 Contract	Jan. 08, 2013 Person	Jun. 30, 2013 ARGO [Member]	Dec. 31, 2012 W&T Total [Member]	Jun. 30, 2013 W&T Operating Properties [Member]	Nov. 30, 2010 W&T Operating Properties [Member]	Jun. 30, 2013 W&T Non-operating Properties [Member]	Jun. 30, 2013 Maritech [Member]	Dec. 31, 2012 Merit [Member] Installment	Jun. 30, 2013 Merit [Member]	Jan. 31, 2013 Punitive Damages [Member]	Jan. 31, 2013 Actual Damages [Member]	Aug. 08, 2013 Scenario, Forecast [Member] West Delta Thirty Two Block Platform [Member]
Long-term Purchase Commitment [Line Items]
Number of civil lawsuits filed																Several civil lawsuits have been filed
Number of investors in Black Elk Energy, LLC (BEE) filed a derivative action on behalf of BEE					5
Number of plaintiffs seeking recovery for injuries in connection with West Delta 32 incident		8
Number of independent contractors sued for recovery for injuries in connection with West Delta 32 incident		3
Loss Contingency, Damages Sought, Value														$ 300	$ 100
Number of drilling unit contract				2
Term of lease period for drilling contract			270 days
Additional lease period for drilling contract	180 days
Escrow to be funded							63.8	32.6		31.2	13.1	60.0
Escrow paid/funded									32.6	15.4	10.2		50.0
Remaining balance of escrow to be paid										15.8	2.9		10.0
Issuance of performance bonds						32.6
Payments for surety bonds												$ 33
Number of monthly installments to be deposited in escrow account												30

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Statement Of Financial Position [Abstract]
Allowance for doubtful accounts	$ 509	$ 509
Accumulated depreciation, depletion, amortization and impairment for oil and gas property	255,998	191,326
Accumulated depreciation for other property and equipment	4,294	1,717
Unamortized discount of debt	$ 754	$ 882

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2013

Commitments And Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 9—COMMITMENTS AND CONTINGENCIES

General

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.

For each of the following proceedings, we are currently evaluating the plaintiff’s claims and determining appropriate courses of response with the aid of legal counsel. These proceedings are at a preliminary stage; accordingly, we currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings. Some or all of the costs of defense and liability (if any) may be covered under our General Liability insurance policy. We intend to vigorously defend ourselves in these proceedings. We are currently in the early stages of litigation for each proceeding and are therefore unable to determine whether these proceedings would have a material adverse effect on our financial position, results of operations or cash flows.

West Delta 32

On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform (the “West Delta 32 Incident”). The cause of the West Delta 32 Incident is being investigated by BSEE, in coordination with the U.S. Coast Guard. We are fully cooperating with all government agencies and have engaged ABS Consulting to assist with our investigation. At BSEE’s direction, we engaged an independent third-party auditor to audit our SEMS program. BSEE participated in the audit and after reviewing the results, it issued a letter to Black Elk stating that “Black Elk’s SEMS meets the intent of BSEE regulations and policies, provided that the Corrective Action Plan (“CAP”) is implemented in accordance with Black Elk’s SEMS Audit Report.” We are currently providing regular updates on our CAP progress.

As of August 8, 2013, several civil lawsuits have been filed as a result of the West Delta 32 Incident. On January 8, 2013, five investors in Black Elk Energy, LLC (“BEE”) filed a purported derivative action on behalf of BEE in the 164th Judicial District of Harris County, Texas against our President and CEO, John Hoffman; our majority unit holder, PPVA Black Elk (Equity) LLC; several entities affiliated with PPVA Black Elk (Equity) LLC; and Iron Island Technologies, Inc. The lawsuit originally alleged that the defendants improperly diluted BEE’s percentage ownership in our company and that the defendants’ alleged gross mismanagement harmed BEE by allegedly causing a credit rating downgrade and a prospective buyer to reduce an alleged offer price for our company. The plaintiffs seek an unspecified amount of damages on behalf of BEE in connection with these claims. On July 26, 2013, in response to a motion to dismiss by PPVA Black Elk (Equity) LLC and its affiliated entities, the court dismissed all claims against all defendants. The claims were dismissed with prejudice to re-filing in Texas.

On March 22, 2013, these same investor plaintiffs filed a purported derivative action on behalf of BEE in the Supreme Court of New York County in the State of New York. The suit is filed against our company; John Hoffman; our majority unit holder, PPVA Black Elk (Equity) LLC; several entities and individuals affiliated with PPVA Black Elk (Equity) LLC; and Iron Island Technologies, Inc. The plaintiffs allege that the defendants improperly diluted BEE’s percentage ownership in our company; it is unclear whether plaintiffs are also asserting claims with respect to the West Delta 32 Incident in connection with this separate lawsuit. The plaintiffs seek an unspecified amount of damages individually and on behalf of BEE in connection with these claims. Like the Harris County lawsuit, we believe this claim is without merit and is being defended vigorously.

On January 31, 2013, eight individual plaintiffs sued Black Elk Energy Offshore Operations, LLC (“BEEOO”), BEE, and three independent contractors (Wood Group USA, Inc., Compass Engineering and Consultants, LLC, and Enviro-Tech Specialties, Inc.) in the United States District Court for the Southern District of Texas. The plaintiffs seek to recover for injuries they allege to have suffered in connection with the West Delta 32 Incident. The plaintiffs allege that they were employed by Grand Isle Shipyard, Inc., and that they were working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. The plaintiffs seek $100 million in actual damages and $300 million in punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

On February 27, 2013, the family of decedent Avelino Tajonera sued BEEOO in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Tajonera’s wife individually and on behalf of his estate and Mr. Tajonera’s three children. The plaintiffs allege that Mr. Tajonera was employed by Grand Isle Shipyard, Inc. and was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Tajonera died several days after the West Delta 32 Incident from injuries he sustained therein. The plaintiffs are seeking an unspecified amount of actual and punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

On March 25, 2013, the family of decedent Ellroy Corporal sued our company in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Corporal’s wife individually and on behalf of his estate and Mr. Corporal’s two children. The plaintiffs allege that Mr. Corporal was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Corporal died from complications due to the West Delta 32 Incident. The plaintiffs are seeking an unspecified amount of actual and punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

On April 29, 2013, Grand Isle Shipyards, Inc. (“GIS”) sued BEE, Enviro Tech Systems, LLC, Wood Group USA, Inc., and Compass Engineering & Consultants, LLC in the United States District Court for the Eastern District of Louisiana for damages it alleged incurred in connection with the West Delta 32 Incident. GIS specifically seeks damages for loss of property and equipment, expenses in the form of indemnity and medical benefits paid to or on behalf of its employees, and for unpaid invoices in connection with the work it performed at West Delta 32. Finally, GIS seeks a declaration that the Louisiana Oilfield Anti-Indemnity Act voids all contractual defense indemnity and additional insured provisions in the Master Service Agreement between GIS and BEE. Upon motion by BEE, however, the court dismissed GIS’ lawsuit and ordered GIS and BEE to first attempt to resolve their claims through mediation, and if that is unsuccessful, then through binding arbitration, pursuant to and in accordance with the MSA. BEE and GIS are in the process of scheduling the mediation of this matter in accordance with the court’s order.

Operating Leases

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 June 30, 2013 were as follows:

During 2012, we entered into two drilling unit contracts. One of the contracts was amended in November 2012 to a total term of 270 days and was extended an additional 180 days on June 3, 2013. The second contract was for the duration of one drill well and was extended to include one additional drill well. Additionally, we purchased leasehold in South Texas and plan to spud a drill well in the third quarter of 2013.

Period Ending June 30,	(in thousands)
2014	$	19,806
2015		2,263
2016		2,072
2017		1,808
2018		1,620
Thereafter		3,856
	$	31,425

Escrow Accounts

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 June 30, 2013, we have funded $15.4 million into the non-operating escrow account, leaving $15.8 million to be funded through May 1, 2017.

The obligations under the W&T Escrow Accounts are fully guaranteed by an affiliate of Platinum. W&T Offshore Inc. (“W&T”) has a first lien on the entirety of the W&T Escrow Accounts, and BP Corporation North America Inc. and Platinum are pari passu second lien holders. Once P&A obligations with respect to the interest in properties acquired from the W&T Acquisition have been fully satisfied, the lien on the W&T Escrow Accounts will be automatically extinguished. W&T also has a second priority lien with respect to the interest in properties acquired from the W&T Acquisition (with Platinum and BNP Paribas sharing a first priority lien), which lien will be released once the W&T Escrow Accounts have been fully funded. On December 19, 2012, we entered into a Third Amendment to Purchase and Sale Agreement (the “Third Amendment”) with W&T. Pursuant to the Third Amendment, we caused performance bonds (the “ARGO Bonds”) in an aggregate amount of $32.6 million to be issued by Argonaut Insurance Company to W&T to guaranty our performance of certain plugging and abandonment obligations. Upon receipt of the ARGO Bonds, W&T (i) released its rights to any money held in an escrow account established to secure our performance of certain plugging and abandonment obligations with respect to the Operated Properties Escrow Account, (ii) released the security interest and deposit account control agreement formerly securing its rights in the Operated Properties Escrow Account and (iii) authorized the escrow agent to release such funds from the Operated Properties Escrow Account to or at our direction. In addition, we and W&T agreed that until the funding of an escrow account established to our performance of certain plugging and abandonment obligations with respect to certain non-operated properties is complete, we may not obtain reductions of the ARGO Bonds under any circumstances without W&T’s consent.

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 June 30, 2013, we have funded $10.2 million, leaving $2.9 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 June 30, 2013, we have funded $50.0 million, leaving $10.0 million to be funded through November 2013.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$ (55,730)	$ 15,863
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, and amortization	22,700	24,244
Impairment of oil and gas properties	55,377	3,311
Accretion of asset retirement obligations	15,093	17,972
Amortization of debt issue costs	2,818	2,194
Accretion of debt discount	128	111
Unrealized loss (gain) on derivative financial instruments	846	(23,504)
(Gain) loss on sale of assets	(35,791)	120
Gain on involuntary conversion of asset	(10,633)
Changes in operating assets and liabilities:
Accounts receivable	(8,638)	12,021
Due from affiliates, net	324
Prepaid expenses and other assets	15,870	(13,193)
Other assets	254
Accounts payable and accrued liabilities	41,197	(7,043)
Gas imbalance	316	744
Settlement of asset retirement obligations	(17,476)	(6,570)
NET CASH PROVIDED BY OPERATING ACTIVITIES	26,655	26,270
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	(78,414)	(10,965)
Acquisition of oil and gas properties	(3,250)	(3,455)
Sale of oil and gas properties	52,580	(119)
Additions to property and equipment	(671)	(131)
Cash assumed in consolidation of Freedom Well Services, LLC	473
Proceeds received from insurance recovery	13,497
Deposits	25	(25)
Restricted cash	(686)
Escrow payments, net	(17,089)	(30,716)
NET CASH USED IN INVESTING ACTIVITIES	(33,535)	(45,411)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on short term notes		17,645
Payments on short term notes	(3,380)	(7,660)
Borrowing on bank debt	9,000	121,000
Payments on bank debt	(36,000)	(97,000)
Debt issuance costs	(1,302)	(2,038)
Contributions from members	50,000
Distributions to members		(13,120)
NET CASH PROVIDED BY FINANCING ACTIVITIES	18,318	18,827
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	11,438	(314)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD	1,383	17,260
CASH AND CASH EQUIVALENTS - END OF PERIOD	12,821	16,946
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	11,512	11,531
NONCASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations relieved due to sale of properties	(22,999)
Increase in asset retirement due to revaluation	2,341
Paid-in-kind dividends on preferred equity and accrued distributions to members	$ 7,826	$ 3,744

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 12,821	$ 1,383
Restricted cash	686
Accounts receivable, net of allowance for doubtful accounts of $509 at June 30, 2013 and December 31, 2012	56,222	46,553
Accounts receivable - insurance recovery	3,400	3,100
Due from affiliates	23	347
Prepaid expenses and other current assets	12,150	27,972
Current portion of escrow for abandonment costs	16,807
Derivative assets		2,408
TOTAL CURRENT ASSETS	102,109	81,763
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $255,998 and $191,326 at June 30, 2013 and December 31, 2012, respectively	224,104	260,012
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $4,294 and $1,717 at June 30, 2013 and December 31, 2012, respectively	5,819	1,968
OTHER ASSETS
Debt issue costs, net	2,261	3,230
Asset retirement obligation escrow receivable	20,348	20,348
Escrow for abandonment costs, net of current portion	215,545	215,263
Other assets	7,316	7,880
TOTAL OTHER ASSETS	245,470	246,721
TOTAL ASSETS	577,502	590,464
CURRENT LIABILITIES:
Accounts payable and accrued expenses	160,084	108,736
Derivative liabilities	1,672
Asset retirement obligations	33,621	41,572
Current portion of debt and notes payable	335	3,552
TOTAL CURRENT LIABILITIES	195,712	153,860
LONG-TERM LIABILITIES
Gas imbalance payable	2,527	2,521
Dividends payable		12,408
Derivative liabilities	1,858	5,091
Asset retirement obligations, net of current portion	288,843	303,933
Debt, net of current portion, net of unamortized discount of $754 and $882 at June 30, 2013 and December 31, 2012, respectively	174,306	201,118
TOTAL LONG-TERM LIABILITIES	467,534	525,071
TOTAL LIABILITIES	663,246	678,931
COMMITMENTS AND CONTINGENCIES
MEMBERS' DEFICIT	(185,978)	(118,467)
TOTAL LIABILITIES AND MEMBERS' DEFICIT	577,502	590,464
Class E And Class D Cumulative Convertible Participating Preferred Units [Member]
LONG-TERM LIABILITIES
CLASS E AND CLASS D PREFERRED UNITS	$ 100,234	$ 30,000

XML

Derivative Instruments - Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 4,053	$ 8,043
Liability Derivatives	(7,583)	(10,726)
Asset (Liability) Derivatives Total	(3,500)	(2,700)
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member]
Derivatives, Fair Value [Line Items]
Asset (Liability) Derivatives Total	(3,530)	(2,683)
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Current Liability Derivatives [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	(5,625)	(4,400)
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Non-current Liability Derivatives [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	(1,958)	(6,326)
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Liability Derivatives [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	(7,583)	(10,726)
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Current Assets Derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	3,953	6,808
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Non-current Assets Derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	100	1,235
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Assets Derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	4,053	8,043
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Asset (Liability) Derivatives, Current [Member]
Derivatives, Fair Value [Line Items]
Asset (Liability) Derivatives Total	(1,672)	2,408
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Asset (Liability) Derivatives, Non-current [Member]
Derivatives, Fair Value [Line Items]
Asset (Liability) Derivatives Total	$ (1,858)	$ (5,091)

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COMMITMENTS AND CONTINGENCIES (Tables)

6 Months Ended

Jun. 30, 2013

Commitments And Contingencies Disclosure [Abstract]

Future Minimum Lease Payments Table

Approximate future minimum lease payments for operating leases at June 30, 2013 were as follows:

Period Ending June 30,	(in thousands)
2014	$	19,806
2015		2,263
2016		2,072
2017		1,808
2018		1,620
Thereafter		3,856
	$	31,425

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Gain on Involuntary Conversion - Additional Information (Detail) (USD $)	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2013 High Island Four Hundred Forty Three [Member]	Dec. 31, 2012 High Island Four Hundred Forty Three [Member]	Aug. 09, 2013 High Island Four Hundred Forty Three [Member] Subsequent Event [Member]
Site Contingency [Line Items]
Receivable under our insurance policy	$ 3,400,000	$ 3,100,000	$ 3,400,000	$ 3,100,000	$ 16,800,000
Insurance claim, deductible amount				$ 500,000

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Debt and Notes Payable - Scheduled Maturities of Principal Amounts of Debt Obligations (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Long Term Debt By Maturity [Abstract]
2014	$ 335
2015	25,030
2016	150,030
2017
2018
Notes and loans payable	175,395
Unamortized discount on 13.75% Senior Secured Notes	(754)	(882)
Total debt	$ 174,641	$ 204,670

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Preferred Units - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended		6 Months Ended			1 Months Ended			6 Months Ended	1 Months Ended	3 Months Ended	6 Months Ended
	Jan. 25, 2013	May 31, 2011	Jun. 30, 2013	Feb. 12, 2013 PPVA (Equity) [Member] Capital Unit Class B [Member]	Jan. 25, 2013 PPVA (Equity) [Member] Capital Unit Class B [Member]	Jan. 31, 2013 Class D Preferred Units [Member]	May 31, 2011 Class D Preferred Units [Member]	Jan. 25, 2013 Class E units [Member]	Jun. 30, 2013 Class E units [Member] Maximum [Member]	Jan. 31, 2013 Class E units [Member] Minimum [Member]	Mar. 31, 2013 Class E units [Member] PPBE [Member]	Jun. 30, 2013 Class E units [Member] PPBE [Member]	Jun. 30, 2013 Class B units [Member] PPBE [Member] Capital Unit Class B [Member]
Class of Stock [Line Items]
Temporary Units Issued							30,000,000	10,000,000
Capital contribution	$ 10.0						$ 30.0					$ 50.0
Rate of accruing dividends payable in kind		24.00%							36.00%	20.00%
Additional units issued				1,131,458	76								3,800,000
Aggregate liquidation preference on Class D units							30
Class D Units Exchanged for Class E Units								43,000,000
Paid-in-kind dividends converted to Class E stock						$ 13.0
Paid-in-kind dividends issued as Class E Stock											2,522,693	4,683,471
Stock Split ratio			10,000

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PREFERRED UNITS

6 Months Ended

Jun. 30, 2013

Equity [Abstract]

PREFERRED UNITS

NOTE 8-PREFERRED UNITS

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 $30 million 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, PPVA (Equity).

The Class D Units were non-voting units, had an aggregate liquidation preference of $30 million and accrued dividends payable in kind at a rate per annum of 24%, compounded annually to the extent they were not distributed. On January 25, 2013, we entered into a contribution agreement with PPVA (Equity), whereby PPVA (Equity) made a capital contribution of $10 million in exchange for 10 million of our Class E Preferred Units (the “Class E Units”) and 76 Class B Units (the “Class B Units”), having such rights, preferences and privileges as set forth in our Third Amendment to Second Amended and Restated Limited Liability Operating Agreement. In addition, we also agreed to issue an additional 43 million Class E Units in exchange for $30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class E Units will receive a preferred return of 20% per annum, which will increase from and after March 25, 2014 to 36% per annum (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement).

During 2013, we entered into contribution agreements with PPBE or the Platinum Group and issued 50.0 million of Class E Units and 3.8 million Class B Units. On March 31, 2013 and June 30, 2013, we issued an additional amount of Class E Units of 2,522,693 and 4,683,471, respectively, as paid-in-kind dividends to the holders of Class E Units on such date.

On February 12, 2013, we entered into an agreement with Platinum under which we agreed to issue Class B Units to Platinum in exchange for financial consulting services, including (1) analysis and assessment of our business and financial condition and compliance with financial covenants in our Credit Facility, (2) discussion with us and senior bank lenders regarding capital contributions and divestitures of non-core assets, and (3) coordination with our attorneys, accountants, and other professionals. On February 12, 2013, we issued 1,131,458.5 Class B Units to PPVA Black Elk (Equity) LLC, an affiliate of Platinum, pursuant to such agreement.

On February 12, 2013, we entered into the Fourth Amendment to the Second Amended and Restated Limited Liability Operating Agreement of the Company (the “Fourth Amendment”). The Fourth Amendment amended the Company’s operating agreement to effectuate a 10,000 to 1 unit split for each of the Class A Units, Class B Units and Class C Units.

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Derivative Instruments - Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Statement of Operations (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Realized (loss) gain on derivative financial instruments	$ (187)	$ 6,436	$ 152	$ 7,905
Unrealized gain (loss) on derivative financial instruments	5,383	30,230	(846)	23,504
Total gain (loss) on derivative financial instruments	5,196	36,666	(694)	31,409
Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized (loss) gain on derivative financial instruments	(187)	6,436	152	7,905
Unrealized gain (loss) on derivative financial instruments	$ 5,383	$ 30,230	$ (846)	$ 23,504

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RELATED PARTY TRANSACTIONS

6 Months Ended

Jun. 30, 2013

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

NOTE 11—RELATED PARTY TRANSACTIONS

We pay for certain operating and general and administration expenses on behalf of Black Elk Energy, LLC. At both June 30, 2013 and December 31, 2012, we had receivables from Black Elk Energy, LLC in the amount of $23,430.

During 2011, we entered into a contribution agreement with Platinum. We also entered into additional contributions with (PPVA (Equity)) and the Platinum Group in 2013. See Note 8.

On May 28, 2013, FWS entered into an equipment lease agreement with Pea and Eigh Company, LLC (“Pea and Eigh”), a related party of Platinum. The lease began on July 1, 2013 and is payable in monthly installments of approximately $35,000, maturing on December 31, 2013, with an option to purchase the equipment for $1.5 million. As of June 30, 2013, we have not purchased all of the equipment. We currently have restricted cash of $0.7 million for the additional equipment to be purchased as well as advances due to Pea and Eigh, which is included in “Accounts payable and accrued expenses”.

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. The loan was paid off in December 2012 in connection with the sale of Freedom. Before the sale, Freedom provided us with aircraft services, which were prepaid on a monthly basis. As of December 31, 2012, we had a receivable of $0.3 million from Freedom. The receivable was paid on February 26, 2013.

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DEBT AND NOTES PAYABLE

6 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

DEBT AND NOTES PAYABLE

NOTE 7—DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:

	June 30, 2013			December 31, 2012
	(in thousands)
	(unaudited)
Senior Secured Revolving Credit Facility	$	25,000		$	52,000
13.75% Senior Secured Notes, net of discount		149,246			149,118
AFCO Credit Corporation-insurance note payble		—			3,552
Other debt		395			—
Total debt		174,641			204,670
Less: current portion		(335	)		(3,552	)
Total long-term debt	$	174,306		$	201,118

Senior Secured Revolving Credit Facility

On December 24, 2010, we entered into an aggregate 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 facility 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.

We have entered into various amendments to the Credit Facility. These amendments have, among other things, (1) changed our amount available for borrowing under the Revolving Credit Facility from $35 million to $25 million, (2) increased the secured letter of credit from $75 million to $200 million, (3) increased the applicable margin with respect to each ABR loan or Eurodollar loan outstanding by 1% if the credit exposure is greater than $15 million, (4) amended certain provisions governing our swap agreements, (5) updated the fees on the letters of credit to 2% on a go-forward basis, (6) updated the “change in control” definition, (7) amended the definition of debt included in the calculation of the covenants, (8) changed the maturity date from December 24, 2013 to January 15, 2014 on the Revolving Credit Facility and to June 22, 2014 on the Letter of Credit Facility, (9) added affirmative covenants to be furnished on a weekly basis including updated cash flow projections, updated accounts payable and accounts receivable schedules, and daily production reports for the week, (10) added an affirmative covenant that we would receive certain specified capital contributions from Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”)or entities designated by PPBE during the first quarter of 2013, (11) revised the definition of “Event of Default” to include non-compliance with new affirmative covenants and (12) restricted returns of capital to our unit holders or distributions of our property to our equity interest holders.

As of June 30, 2013, letters of credit in the aggregate amount of $105.7 million were outstanding under the Letter of Credit Facility. We had $25.0 million in borrowings under the Revolving Credit Facility. As of August 12, 2013, we had no amount available for additional borrowings under the Revolving Credit Facility.

A commitment fee of 0.5% per annum is computed based on the unused borrowing base and paid quarterly. For each of the three and six months ended June 30, 2013, we recognized $4,125 in commitment fees, which have been included in “Interest expense” on the consolidated statements of operations. A letter of credit fee is computed based on the same applicable margin used to determine the interest rate to Eurodollar loans times the stated face amount of each letter of credit.

The Credit Facility is secured by mortgages on at least 80% of the total value of 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 first borrowing base redetermination date for 2013 has been extended to August 30, 2013.

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 payables restriction covenant, which does not allow accounts payable greater than 90 days old to exceed $6.0 million in the aggregate, excluding certain vendors (in each case as defined in our revolving Credit Facility). 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 June 30, 2013, we were not in compliance with the total leverage ratio covenant and the interest coverage ratio covenant. Our total leverage ratio was calculated to be 5.2 to 1.0, which was higher than the required maximum of 2.5 to 1.0. Our interest coverage ratio covenant was calculated to be 1.3 to 1.0, which was lower than the minimum 3.0 to 1.0. We received a limited waiver relating to such covenants in the Tenth Amendment for only the fiscal quarter ended June 30, 2013. In addition to the waiver, the Tenth Amendment also (1) maintains the borrowing base at $25 million through August 30, 2013 and will reduce to $0 on September 2, 2013 either through refinancing by another lender or a purchase agreement by Platinum, (2) releases the liens on the second Renaissance sale that occurred on July 31, 2013 and (3) allows us to retain the proceeds from the second Renaissance sale and up to $5 million in aggregate of any escrow releases from both Renaissance sales or any other collateral sales. See Note 2.

On July 31, 2013, we entered into a loan purchase agreement (the “Letter Loan Purchase Agreement”) with Capital One, N.A., as Administrative Agent, the Lenders and PPVA (Equity) pursuant to which PPVA (Equity) agreed to (i) purchase all of our loans and commitments under the Credit Agreement from the Lenders and (ii) assume the obligations of the Administrative Agent under the Credit Agreement and related loan documents if not refinanced by another lender.

In connection with the Letter Loan Purchase Agreement, on July 31, 2013, Platinum Partners Value Arbitrage Fund L.P. and the other guarantors party thereto (the “Guarantors”) entered into a guaranty (the “Guaranty”) in favor of Capital One, N.A, as Administrative Agent for the benefit of the Lenders under the Credit Agreement. Pursuant to the Guaranty, the Guarantors agreed to guarantee the full, complete and timely performance of obligations of PPVA (Equity) under the Letter Loan Purchase Agreement.

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 BOEMRE 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, at which time all principal then outstanding will be due. As of June 30, 2013, the recorded value of the Notes was $149.2 million, which includes the unamortized discount of $0.8 million. We incurred underwriting and debt issue costs of $7.2 million, which have been capitalized and are being amortized over the life of the Notes.

The Notes are secured by a security interest in our 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 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, impairment of oil and gas properties, and exploration expense for any year thereafter. As of June 30, 2013, we were in compliance with all covenants under the Indenture. However, based on our financial results for 2013 to date, we anticipate that we are unlikely to be in compliance at December 31, 2013 with a covenant respecting maximum capital expenditures. We have the option under the Indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes if we do not believe we will be in compliance with this covenant, however, there can be no assurance that we will have sufficient funds to do so. If the Notes remain outstanding at December 31, 2013 and a default under this covenant actually occurs, then we anticipate we would solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the Indenture, the Indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the Indenture covenant could also result in a cross-default under our bank credit facility.

The amounts of required principal payments based on our outstanding debt amounts as of June 30, 2013, were as follows:

Period Ending June 30,	(in thousands)
2014	$	335
2015		25,030
2016		150,030
2017		—
2018		—
		175,395
Unamortized discount on 13.75% Senior Secured Notes		(754	)
Total debt	$	174,641

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LIQUIDITY RISKS AND UNCERTAINTIES

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

LIQUIDITY RISKS AND UNCERTAINTIES

NOTE 2—LIQUIDITY RISKS AND UNCERTAINTIES

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $93.6 million at June 30, 2013. The combination of restricted credit availability, lower production since the fourth quarter of 2012 and our drilling program led to significant cash reductions in the fourth quarter of 2012 and the first and second quarters of 2013. To increase liquidity, we stretched accounts payable and aggressively pursued accounts receivable. We have worked closely with our vendors during this time and expect to normalize the age of accounts payables within 2013. We continue to optimize our production portfolio and recommenced our drilling program in the fourth quarter of 2012. Currently, we have two rigs under contract, and we expect to drill or complete six operated wells and four non-operated wells in 2013. To fund our drilling programs and operations, we expect to continue to raise additional capital over the next several years. We are currently evaluating new sources of liquidity including, but not limited to, (i) entering into a new revolving credit facility with a traditional bank syndicate or Platinum, our majority owner, and (ii) accessing the debt capital markets. Additionally, we are evaluating potential asset sales of core and non-core assets to optimize our portfolio. On March 26, 2013, we sold four producing fields to Renaissance Offshore, LLC for approximately $52.5 million subject to normal purchase price adjustments. A portion of the proceeds from the sale were used to reduce the amount borrowed under the credit facility (the “Credit Facility”) by $36 million and the remainder has been and will be used for general corporate purposes. We expect that escrows of approximately $9.0 million related to the sold properties will be released and received in the third quarter of 2013. The remainder of the escrow funds released for the sold properties will be used to increase the collateral with the surety companies relating to bonds that had previously been issued that provide us with surety bonds to satisfy the bonding and security requirements of the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”). We also expect to obtain site clearance on certain properties after the plugging and abandonment (“P&A”) work has been performed and will meet obligations in the escrow agreements to release additional funds of $7.8 million. We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million subject to normal purchase price adjustments.

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. 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. Also, our letters of credit with Capital One are backed entirely by cash. We use letters of credit to back a portion of our surety bonds for P&A obligations.

We were not in compliance with our leverage ratio or our interest rate coverage ratio under our Credit Facility as of June 30, 2013. On July 31, 2013, we entered into the Tenth Amendment to (1) obtain waivers related to our financial covenants for the second quarter of 2013, (2) maintain the borrowing base at $25 million through August 30, 2013, and will reduce it to $0 on September 2, 2013 either through refinancing by another lender or a purchase agreement by Platinum, (3) release the liens on the second Renaissance sale that occurred on July 31, 2013 and (4) allow us to retain the proceeds from the second Renaissance sale and up to $5 million in aggregate of any escrow releases from both Renaissance sales or any other collateral sales. If Platinum purchases the debt, there will be an additional addendum extending the maturity date to July 1, 2014.

As of June 30, 2013, we were in compliance with all covenants under the Indenture. However, based on our financial results for 2013 to date, we anticipate that we are unlikely to be in compliance at December 31, 2013 with a covenant respecting maximum capital expenditures. We have the option under the indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes if we do not believe we will be in compliance with this covenant; however, there can be no assurance that we will have sufficient funds to do so. If the Notes remain outstanding at December 31, 2013 and a default under this covenant actually occurs, then we anticipate we would solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the indenture, the indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the indenture covenant could also result in a cross-default under our bank credit facility.

As discussed above, we are currently evaluating new sources of liquidity including, but not limited to, entering into a new revolving credit facility with a traditional bank syndicate or Platinum, our majority owner, accessing the debt capital markets and potential asset sales of non-core and core properties to optimize our portfolio. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amount and classifications of liabilities that might result from the uncertainty associated with our ability to meet our obligations as they come due. For additional information, please see “Risk Factors” under Item 1A of this Form 10-Q.

Our capital budget may be adjusted in the future as business conditions warrant and the ultimate amount of capital we expend may fluctuate materially based on market conditions and the success of our drilling program 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 budgeted 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. Our planned operations for the remainder of 2013 reflect our expectations for production based on actual production history and new production expected to be brought online, the continuation of commodity prices near current levels and the higher cost of servicing our additional financing and other obligations.

Our cash flow projections are highly dependent upon numerous assumptions including the timing and rates of production from our wells, the sales prices we realize for our oil and natural gas, the cost to develop and produce our reserves, our ability to monetize our properties and future production through asset sales and financial derivatives, and a number of other factors, some of which are beyond our control. Our inability to increase near-term production levels and generate sufficient liquidity through the actions noted above could result in our inability to meet our obligations as they come due which would have a material adverse effect on our financial position, results of operation and cash flows. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through other financing sources; however, there is no assurance that we will be able to do so in the future if required to meet any short-term liquidity needs.

Our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimation process requires significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, and may differ materially from our actual results. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves requires us to expect that capital will be available to fund their development. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and we intend to continue to develop these reserves, but there is no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet the requirements of our financing obligations.

Our current production is concentrated in the Gulf of Mexico, which is characterized by production declines more rapid than those of conventional onshore properties. As a result, we are particularly vulnerable to a near-term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and severe weather. Any unanticipated significant disruption to, or decline in, our current production levels or prolonged negative changes in commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet our commitments as they come due.

Oil and natural gas development and production in the Gulf of Mexico are regulated by the BOEM and BSEE of the Department of the Interior (“DOI”). We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Deepwater Horizon incident in 2010 have changed the way we conduct our business and increased our costs of developing and commissioning new assets. Should there be additional significant future regulations or additional statutory limitations, they could require further changes in the way we conduct our business, further increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico.

As an oil and gas company, our revenue, profitability, cash flows, proved reserves and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our debt and other obligations.

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Debt and Notes Payable - Debt and Notes Payable (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Total debt	$ 174,641	$ 204,670
Less: current portion	(335)	(3,552)
Total long-term debt	174,306	201,118
AFCO Credit Corporation-insurance note payable [Member]
Debt Instrument [Line Items]
Total debt		3,552
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Total debt	25,000	52,000
13.75% Senior Secured Notes, net of discount [Member]
Debt Instrument [Line Items]
Total debt	149,246	149,118
Other debt [Member]
Debt Instrument [Line Items]
Total debt	$ 395

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OIL AND GAS PROPERTIES (Tables)

6 Months Ended

Jun. 30, 2013

Property Plant And Equipment [Abstract]

Capitalized Costs Related to Oil and Gas Properties

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

	June 30,			December 31,
	2013			2012
	(Unaudited)
	(in thousands)
Proved properties	$	479,654		$	451,338
Unproved properties, not subject to depletion		448			—
Total capitalized costs		480,102			451,338
Accumulated depreciation, depletion, amortization and impairment		(255,988	)		(191,326	)
Oil and gas properties, net	$	224,104		$	260,012

Schedules of Change to Our Asset Retirement Obligations

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

	(in thousands)
Balance at December 31, 2012	$	345,505
Revaluation of liability		2,341
Liabilities relieved due to sale of properties		(22,999	)
Liabilities settled		(17,476	)
Accretion expense		15,093
Balance at June 30, 2013	$	322,464
Less: current portion		(33,621	)
Total Long-Term Asset Retirement Obligations	$	288,843

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GAIN ON INVOLUNTARY CONVERSION

6 Months Ended

Jun. 30, 2013

Text Block [Abstract]

GAIN ON INVOLUNTARY CONVERSION

NOTE 10—GAIN ON INVOLUNTARY CONVERSION

High Island 443 A-2

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, BSEE advised us to plug and abandon the well. We have well control insurance and pursued reimbursement for this incident. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drilling are also insurance recoverable.

The claim was approved. We recorded a receivable of $3.1 million for reimbursement, after a deductible of $0.5 million, under our insurance policy at December 31, 2012 and received the funds during the first quarter of 2013. As of June 30, 2013, we recorded a receivable of $3.4 million for additional reimbursement and received these funds in July 2013. We have received a total of approximately $16.8 million in cash for the claim as of August 9, 2013.

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DEBT AND NOTES PAYABLE (Tables)

6 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

Debt and Notes Payable

Our debt and notes payable are summarized as follows:

	June 30, 2013			December 31, 2012
	(in thousands)
	(unaudited)
Senior Secured Revolving Credit Facility	$	25,000		$	52,000
13.75% Senior Secured Notes, net of discount		149,246			149,118
AFCO Credit Corporation-insurance note payble		—			3,552
Other debt		395			—
Total debt		174,641			204,670
Less: current portion		(335	)		(3,552	)
Total long-term debt	$	174,306		$	201,118

Scheduled Maturities of Principal Amounts of Debt Obligations

The amounts of required principal payments based on our outstanding debt amounts as of June 30, 2013, were as follows:

Period Ending June 30,	(in thousands)
2014	$	335
2015		25,030
2016		150,030
2017		—
2018		—
		175,395
Unamortized discount on 13.75% Senior Secured Notes		(754	)
Total debt	$	174,641

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DERIVATIVE INSTRUMENTS (Tables)

6 Months Ended

Jun. 30, 2013

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Commodity Derivative Instruments

At June 30, 2013, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) (unaudited)):

	Crude Oil											Natural Gas										Total
Period	Volume (Bbls)			Contract Price ($/Bbl)		Asset (Liability)			Fair  Value Gain (Loss)			Volume (MMBtu)		Contract Price ($/MMBtu)		Asset (Liability)			Fair  Value Gain (Loss)			Asset (Liability)			Fair  Value Gain (Loss)
Swaps:						(in thousands)										(in thousands)						(in thousands)
7/13 - 8/13		27,750		$	96.90	$	29		$	29			104,000	$	4.60	$	198		$	198		$	227		$	227
9/13 - 10/13		27,750		$	96.90		89			89			104,000	$	4.60	$	207			207			296			296
11/13 -11/13		26,800			96.90		70			70			104,000		4.60		94			94			164			164
12/13 - 12/13		27,750			96.90		91			91			104,000		4.60		76			76			167			167
1/14 - 2/14		19,000			96.90		159			159			82,000		4.60		105			105			264			264
7/13 - 7/13		7,132			100.80		31			31			148,788		4.94		183			183			214			214
8/13 - 8/13		5,980			100.80		27			27			139,212		4.94		189			189			216			216
9/13 - 9/13		3,897			100.80		20			20			116,125		4.94		156			156			176			176
10/13 - 10/13		3,259			100.80		19			19			91,166		4.94		120			120			139			139
11/13 - 11/13		—			—		—			—			64,926		4.94		80			80			80			80
12/13 - 12/13		10,042			100.80		70			70			119,462		4.94		127			127			197			197
1/14 - 5/14		10,083			100.80		422			422			129,960		4.94		639			639			1,061			1,061
6/14 - 6/14		—			—		—			—			129,960		4.94		125			125			125			125
7/13 - 12/13		19,750			85.90		(1,063	)		(1,063	)		47,000		5.00		371			371			(692	)		(692	)
1/14 - 12/14		15,000			65.00		(3,937	)		(3,937	)		—		—		—			—			(3,937	)		(3,937	)
7/13 - 7/13		23,143			88.80		(179	)		(179	)		36,765		4.09		14			14			(165	)		(165	)
8/13 - 8/13		24,915			88.80		(183	)		(183	)		34,725		4.09		18			18			(165	)		(165	)
9/13 - 9/13		28,688			88.80		(190	)		(190	)		31,739		4.09		16			16			(174	)		(174	)
10/13 - 10/13		28,006			88.80		(164	)		(164	)		34,551		4.09		17			17			(147	)		(147	)
11/13 - 11/13		31,605			88.80		(161	)		(161	)		28,939		4.09		12			12			(149	)		(149	)
12/13 - 12/13		38,743			88.80		(168	)		(168	)		37,906		4.09		10			10			(158	)		(158	)
1/14 - 1/14		4,723			88.80		(17	)		(17	)		43,347		4.09		7			7			(10	)		(10	)
2/14 - 2/14		13,313			88.80		(40	)		(40	)		32,636		4.09		5			5			(35	)		(35	)
3/14 - 3/14		8,413			88.80		(21	)		(21	)		46,764		4.09		9			9			(12	)		(12	)
4/14 - 4/14		12,473			88.80		(25	)		(25	)		41,253		4.09		11			11			(14	)		(14	)
5/14 - 5/14		11,793			88.80		(19	)		(19	)		40,391		4.09		10			10			(9	)		(9	)
6/14 - 6/14		15,546			88.80		(18	)		(18	)		20,112		4.09		4			4			(14	)		(14	)
7/14 - 7/14		11,845			88.80		(9	)		(9	)		39,283		4.09		7			7			(2	)		(2	)
8/14 - 8/14		13,165			88.80		(4	)		(4	)		34,246		4.09		5			5			1			1
9/14 - 9/14		16,235			88.80		—			—			29,753		4.09		5			5			5			5
10/14 - 10/14		15,605			88.80		5			5			28,635		4.09		4			4			9			9
11/14 - 11/14		18,525			88.80		11			11			27,081		4.09		2			2			13			13
12/14 - 12/14		22,526			88.80		22			22			34,114		4.09		(2	)		(2	)		20			20
7/13 - 7/13		15,000			87.85		(130	)		(130	)		—		—		—			—			(130	)		(130	)
8/13 - 8/13		11,000			87.85		(91	)		(91	)		—		—		—			—			(91	)		(91	)
9/13 - 9/13		20,000			87.85		(151	)		(151	)		—		—		—			—			(151	)		(151	)
10/13 - 10/13		4,000			87.85		(27	)		(27	)		—		—		—			—			(27	)		(27	)
11/13 - 11/13		250			87.85		(2	)		(2	)		—		—		—			—			(2	)		(2	)
12/13 - 12/13		2,500			87.85		(13	)		(13	)		—		—		—			—			(13	)		(13	)
1/14 -1/14		46,000			87.85		(206	)		(206	)		—		—		—			—			(206	)		(206	)
2/14 - 2/14		25,000			87.85		(97	)		(97	)		—		—		—			—			(97	)		(97	)
3/14 - 3/14		56,000			87.85		(185	)		(185	)		—		—		—			—			(185	)		(185	)
4/14 - 4/14		45,000			87.85		(129	)		(129	)		—		—		—			—			(129	)		(129	)
5/14 - 5/14		46,000			87.85		(111	)		(111	)		—		—		—			—			(111	)		(111	)
6/14 - 6/14		48,000			87.85		(96	)		(96	)		40,391		4.19		12			12			(84	)		(84	)
7/14 - 7/14		36,000			87.85		(56	)		(56	)		20,112		4.19		5			5			(51	)		(51	)
8/14 - 8/14		34,000			87.85		(39	)		(39	)		39,283		4.19		10			10			(29	)		(29	)
9/14 - 9/14		26,000			87.85		(21	)		(21	)		34,246		4.19		8			8			(13	)		(13	)
10/14 - 10/14		27,000			87.85		(13	)		(13	)		29,753		4.19		7			7			(6	)		(6	)
11/14 - 11/14		20,000			87.85		(4	)		(4	)		28,635		4.19		4			4			—			—
12/14 - 12/14		31,000			87.85		6			6			27,081		4.19		—			—			6			6
9/13 - 9/13		(17,500	)		89.15		110			110			—		—		—			—			110			110
1/15 - 1/15		—			—		—			—			34,114		4.19		(2	)		(2	)		(2	)		(2	)
2/15 - 2/15		—			—		—			—			27,838		4.19		(1	)		(1	)		(1	)		(1	)
3/15 - 3/15		—			—		—			—			24,461		4.19		—			—			—			—
1/15 - 1/15		—			—		—			—			27,838		4.09		(4	)		(4	)		(4	)		(4	)
2/15 - 2/15		—			—		—			—			24,461		4.09		(3	)		(3	)		(3	)		(3	)
3/15 - 3/15		—			—		—			—			26,443		4.09		(2	)		(2	)		(2	)		(2	)
						$	(6,388	)	$	(6,388	)					$	2,858		$	2,858		$	(3,530	)	$	(3,530	)

Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet

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

	Asset Derivatives			Liability Derivatives				Asset (Liability) Derivatives Total
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at June 30, 2013		Balance Sheet Location	Fair Value at June 30, 2013			Balance Sheet Location	Fair Value at June 30, 2013
Commodity Contracts	Derivative financial instruments			Derivative financial instruments				Derivative financial instruments
	Current	$	3,953	Current	$	(5,625	)	Current	$	(1,672	)
	Non-current		100	Non-current		(1,958	)	Non-current		(1,858	)
Total derivative instruments		$	4,053		$	(7,583	)		$	(3,530	)
	Asset Derivatives			Liability Derivatives				Asset (Liability) Derivatives Total
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at December 31, 2012		Balance Sheet Location	Fair Value at December 31, 2012			Balance Sheet Location	Fair Value at December 31, 2012
Commodity Contracts	Derivative financial instruments			Derivative financial instruments				Derivative financial instruments
	Current	$	6,808	Current	$	(4,400	)	Current	$	2,408
	Non-current		1,235	Non-current		(6,326	)	Non-current		(5,091	)
Total derivative instruments		$	8,043		$	(10,726	)		$	(2,683	)

Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Statement of Operations

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

Derivatives Not Designated as Hedging		Three Months Ended June  30,					Six Months Ended June 30,
Instruments under Accounting Guidance	Statements of Operations Location	2013			2012		2013			2012
Commodity Contracts	Realized (loss) gain on derivative financial instruments	$	(187	)	$	6,436	$	152		$	7,905
Commodity Contracts	Unrealized gain (loss) on derivative financial instruments		5,383			30,230		(846	)		23,504
Total derivative instruments		$	5,196		$	36,666	$	(694	)	$	31,409

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2013	Aug. 12, 2013 Common Class A	Aug. 12, 2013 Common Class B	Aug. 12, 2013 Common Class C	Aug. 12, 2013 Common Class E
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Trading Symbol	CK0001518909
Entity Registrant Name	Black Elk Energy Offshore Operations, LLC
Entity Central Index Key	0001518909
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,361,300.0	114,277,308.5	12,031,250.0	100,234,164.0

XML

FAIR VALUE MEASUREMENTS (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table

The following tables present information about our assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and December 31, 2012 and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands) (unaudited):

	Fair Value Measurements at June 30, 2013 Using Fair Value Hierarchy
	Fair Value as of June 30, 2013			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	4,053		$	—	$	4,053		$	—
	$	4,053		$	—	$	4,053		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(7,583	)	$	—	$	(7,583	)	$	—
	$	(7,583	)	$	—	$	(7,583	)	$	—
	Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	Fair Value as of December 31, 2012			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	8,043		$	—	$	8,043		$	—
	$	8,043		$	—	$	8,043		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(10,726	)	$	—	$	(10,726	)	$	—
	$	(10,726	)	$	—	$	(10,726	)	$	—