UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2014

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  ý

(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  ý    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  ý

As of August 14, 2014, there were 1,361,300 Class A Units, 114,277,308.5 Class B Units, 12,031,250 Class C Units and 103,944,435 Class E Units issued and outstanding.

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED June 30, 2014

TABLE OF CONTENTS

		Page
Part I. Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheet (unaudited) as of June 30, 2014 and December 31, 2013	1
	Consolidated Statement of Operations (unaudited) for the Three and Six Months Ended June 30, 2014 and 2013	2
	Consolidated Statements of Cash Flows (unaudited) for the Six Months Ended June 30, 2014 and 2013	3
	Notes to Consolidated Financial Statements (unaudited)	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 4.	Controls and Procedures	33
Part II. Other Information
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	36
Item 6.	Exhibits	38
Signatures		40
Exhibit Index		41

(i)

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(unaudited)

(in thousands)

	June 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,362		$	6,227
Restricted cash	675			775
Accounts receivable, net of allowance for doubtful accounts of $826 and $811 at June 30, 2014 and December 31, 2013, respectively	48,352			61,747
Due from affiliates	273			273
Prepaid expenses and other current assets	8,027			7,109
Current portion of escrow for abandonment costs	—			21,976
Derivative assets	34			1,370
TOTAL CURRENT ASSETS	60,723			99,477
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $253,174 and $293,973 at June 30, 2014 and December 31, 2013, respectively	153,654			196,136
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $6,334 and $5,350 at June 30, 2014 and December 31, 2013, respectively	3,929			4,862
OTHER ASSETS
Debt issue costs, net	690			1,488
Asset retirement obligation escrow receivable	20,348			20,348
Escrow for abandonment costs, net of current portion	231,010			235,473
Other assets	7,796			7,830
TOTAL OTHER ASSETS	259,844			265,139
TOTAL ASSETS	$	478,150		$	565,614
LIABILITIES AND MEMBERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	135,097		$	155,880
Derivative liabilities	8,142			9,828
Asset retirement obligations	26,746			43,109
Current portion of debt and notes payable	759			257
TOTAL CURRENT LIABILITIES	170,744			209,074
LONG-TERM LIABILITIES
Gas imbalance payable	1,144			1,888
Derivative liabilities	—			31
Asset retirement obligations, net of current portion	224,092			233,623
Debt, net of current portion, net of unamortized discount of $471 and $617 at June 30, 2014 and December 31, 2013, respectively	149,560			183,929
TOTAL LONG-TERM LIABILITIES	374,796			419,471
TOTAL LIABILITIES	545,540			628,545
CLASS E PREFERRED UNITS	103,944			109,744
COMMITMENTS AND CONTINGENCIES
MEMBERS’ DEFICIT	(171,334		)	(172,675		)
TOTAL LIABILITIES AND MEMBERS’ DEFICIT	$	478,150		$	565,614

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

1

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands)

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2014			2013			2014			2013
REVENUES:
Oil sales	$	25,057		$	40,035		$	62,881		$	85,936
Natural gas sales	8,802			14,109			21,474			27,445
Plant product sales	1,380			1,858			3,133			4,375
Realized (loss) gain on derivative financial instruments	(4,366		)	(187		)	(8,858		)	152
Unrealized (loss) gain on derivative financial instruments	(3		)	5,383			381			(846		)
Other revenues	6,551			5,177			13,388			9,300
TOTAL REVENUES	37,421			66,375			92,399			126,362
OPERATING EXPENSES:
Lease operating	27,297			46,971			53,940			90,173
Production taxes	(28		)	189			69			316
Workover	283			4,224			618			6,284
Depreciation, depletion and amortization	8,174			11,145			21,938			22,700
Impairment of oil and gas properties	2,161			22,414			3,074			55,377
General and administrative	5,473			9,388			12,730			18,629
Gain on involuntary conversion of asset	—			(8,250		)	—			(10,633		)
Accretion of asset retirement obligations	1,909			7,569			2,986			15,093
Loss (gain) on sale of assets	4,069			1,984			(34,551		)	(35,791		)
Other operating expenses	2,776			1,423			5,350			2,413
TOTAL OPERATING EXPENSES	52,114			97,057			66,154			164,561
(LOSS) INCOME FROM OPERATIONS	(14,693		)	(30,682		)	26,245			(38,199		)
OTHER INCOME (EXPENSE):
Interest income	13			29			36			51
Miscellaneous expense	(2,035		)	(2,564		)	(4,466		)	(4,946		)
Interest expense	(6,010		)	(6,300		)	(12,274		)	(12,636		)
TOTAL OTHER EXPENSE, NET	(8,032		)	(8,835		)	(16,704		)	(17,531		)
NET (LOSS) INCOME	(22,725		)	(39,517		)	9,541			(55,730		)
LESS: PREFERRED UNIT DIVIDENDS	3,549			4,683			8,200			7,826
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	(26,274	)	$	(44,200	)	$	1,341		$	(63,556	)

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

2

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	9,541		$	(55,730	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	21,938			22,700
Impairment of oil and gas properties	3,074			55,377
Accretion of asset retirement obligations	2,986			15,093
Amortization of debt issue costs	1,592			2,818
Accretion of debt discount	146			128
Unrealized loss (gain) on derivative financial instruments	(381		)	846
Gain on sale of assets	(34,551		)	(35,791		)
Provision on doubtful accounts	16			—
Gain on involuntary conversion of assets	—			(10,633		)
Changes in operating assets and liabilities:
Accounts receivable	16,506			(8,638		)
Escrow receivable, short term	(2,751		)	—
Due from affiliates, net	—			324
Prepaid expenses and other assets	(1,713		)	15,870
Other assets	162			254
Accounts payable and accrued liabilities	(20,782		)	41,197
Gas imbalance	(881		)	316
Settlement of asset retirement obligations	(10,676		)	(17,476		)
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES	(15,774		)	26,655
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	(10,794		)	(78,414		)
Acquisition of oil and gas properties	—			(3,250		)
Sale of oil and gas properties	45,606			52,580
Additions to property and equipment	(52		)	(671		)
Cash assumed in consolidation of Freedom Well Services, LLC	—			473
Proceeds received from insurance recovery	—			13,497
Deposits	—			25
Restricted cash	100			(686		)
Escrow payments, net	(189		)	(17,089		)
Escrow released	26,251			—
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	60,922			(33,535		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on short term notes	2,851			—
Payments on short term notes	(2,364		)	(3,380		)
Borrowing on bank debt	—			9,000
Payments on bank debt	(34,500		)	(36,000		)
Debt issuance costs	—			(1,302		)
Contributions from members	—			50,000
Distributions to members	(14,000		)	—
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES	(48,013		)	18,318
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(2,865		)	11,438
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD	6,227			1,383
CASH AND CASH EQUIVALENTS - END OF PERIOD	$	3,362		$	12,821
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	671		$	11,512
NONCASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations relieved due to sale of properties	$	(18,204	)	$	(22,999	)
Increase in asset retirement due to revaluation	$	—		$	2,341
Paid-in-kind dividends on preferred equity and accrued distributions to members	$	8,200		$	7,826

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

3

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(Unaudited)

NOTE 1—BASIS OF PRESENTATION

Nature of Operations: Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries (collectively, “Black Elk”, "BEEOO", “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, 2013 (the “2013 Form 10-K”).

Reclassifications: Certain reclassifications have been made to conform 2013 balances to our 2014 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 April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU 2014-08 narrows the definition of “discontinued operations” to dispositions that represent a strategic shift that has or will have a significant impact on the entity’s operations and financial results. The ASU requires additional disclosures regarding assets and liabilities held for sale, and income and losses, including gain or loss on sale, and cash flows from discontinued operations. In addition, the ASU requires disclosures for disposals of individually significant components of the business which do not qualify as discontinued operations, including general information about the disposition and disclosure of the pretax profit or loss from the component for the period of disposal and all comparable historic periods presented. ASU 2014-08 is effective for all fiscal years beginning after December 15, 2014, and can be adopted early for certain asset dispositions and reclassifications of assets from “held and used” to “held for sale.”

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.”  ASU 2014-08 narrows the definition of “discontinued operations” to dispositions that represent a strategic shift that has or will have a significant impact on the entity’s operations and financial results.  The ASU requires additional disclosures regarding assets and liabilities held for sale, and income and losses, including gain or loss on sale, and cash flows from discontinued operations.  In addition, the ASU requires disclosures for disposals of individually significant components of the business which do not qualify as discontinued operations, including general information about the disposition and disclosure of the pretax profit or loss from the component for the period of disposal and all comparable historic periods presented.  ASU 2014-08 is effective for all fiscal years beginning after December 15, 2014, and can be adopted early for certain asset dispositions and reclassifications of assets from “held and used” to “held for sale.”

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606).  The update provides guidance concerning the recognition and measurement of revenue from contracts with customers.  Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty

4

of revenues.  The update is effective for the Company beginning in calendar year 2017.  We are evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

NOTE 2— LIQUIDITY, RISKS AND UNCERTAINTIES

               While cash flows were lower than previously projected primarily due to lower production and sales of assets in the 3rd and 4th quarters of 2013, we continued our development operations, in the second quarter of 2014, by supplementing our cash flows from operating activities with funds raised through divestiture of non-key assets.  Additionally, we significantly reduced our workforce and associated general and administrative expenses in connection with our down sized operations.

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $110.0 million at June 30, 2014. The combination of restricted credit availability, lower production since the fourth quarter of 2013, settlement of our plugging and abandonment ("P&A") liabilities and additional collateral requirements related to our surety bonds that secure our P&A obligations led to significant cash reductions in the fourth quarter of 2013 and the first six months of 2014. To increase liquidity, we continue to stretch accounts payable, aggressively pursue accounts receivable and seek for opportunities to sell non-core assets. On March 17, 2014, our Credit Facility was paid in full.

Our primary use of capital has been for the 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 were backed entirely by cash were paid in full on June 8, 2014. We used these letters of credit to back our surety bonds for P&A obligations. We terminated the 100% cash-backed letters of credit and increased our collateral with the surety agencies in the second quarter of 2014 for P&A obligations.

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.

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 can 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.

We consider the control and flexibility afforded by operating our properties under development to be instrumental to our business plan and strategy. To manage our liquidity, we have the ability to delay certain capital commitments, and within certain constraints, we can continue to conserve capital by further delaying or eliminating future capital commitments. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility is one method by which we can balance, on a temporary basis, our capital commitments with our available capital resources.

Virtually all of 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.

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:

5

	June 30, 2014			December 31, 2013
	(Unaudited)
	(in thousands)
Proved properties	$	406,828		$	490,109
Accumulated depreciation, depletion, amortization and impairment	(253,174		)	(293,973		)
Oil and gas properties, net	$	153,654		$	196,136

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

	(in thousands)
Balance at December 31, 2013	$	276,732
Liabilities relieved due to sale of properties	(18,204		)
Liabilities settled	(10,676		)
Accretion expense	2,986
Balance at June 30, 2014	250,838
Less: current portion	(26,746		)
Total Long-Term Asset Retirement Obligations	$	224,092

NOTE 4—ACQUISITIONS AND DIVESTITURES

On March 13, 2014 , the Company entered into a Purchase and Sale Agreement (the “PSA”) with a wholly owned subsidiary of Fieldwood Energy LLC (“Fieldwood”). Pursuant to the PSA, Fieldwood acquired all of the Company’s interest in one operated and 15 non-operated fields in the offshore Gulf of Mexico, for $50 million, prior to normal purchase price adjustments (the “Sale”). Refer to the PSA incorporated by reference herein as Exhibit 10.2 for a more detailed description of the terms of the Sale, including the fields that were sold. The Sale closed on March 17, 2014. Reflected in our June 30, 2014, consolidated financial statements is a preliminary gain of $34.6 million related to Fieldwood.

On March 26, 2013, we completed the sale of four fields to Renaissance Offshore, LLC for approximately $52.5 million prior to normal purchase price adjustments. The proceeds were used to reduce the amount borrowed under the Credit Facility. Reflected in our June 30, 2013, consolidated financial statements is a gain of $35.8 million.

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

At June 30, 2014, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) (unaudited)):

	Crude Oil						Natural Gas						Total
Period	Monthly Volume (Bbls)	Contract Price ($/Bbl)	Asset (Liability)		Fair  Value Gain (Loss)		Monthly Volume (MMBtu)	Contract Price ($/MMBtu)	Asset (Liability)		Fair  Value Gain (Loss)		Asset (Liability)		Fair  Value Gain (Loss)
Swaps:			(in thousands)						(in thousands)				(in thousands)
7/14 - 12/14	15,000	65.00	(3,340	)	(3,340	)	—	—	—		—		(3,340	)	(3,340	)
7/14 - 7/14	11,845	88.80	(194	)	(194	)	39,283	4.09	(12	)	(12	)	(206	)	(206	)
8/14 - 8/14	13,165	88.80	(203	)	(203	)	34,246	4.09	(13	)	(13	)	(216	)	(216	)
9/14 - 9/14	16,235	88.80	(235	)	(235	)	29,753	4.09	(10	)	(10	)	(245	)	(245	)
10/14 - 10/14	15,605	88.80	(209	)	(209	)	28,635	4.09	(10	)	(10	)	(219	)	(219	)
11/14 - 11/14	18,525	88.80	(233	)	(233	)	27,081	4.09	(10	)	(10	)	(243	)	(243	)
12/14 - 12/14	22,526	88.80	(263	)	(263	)	34,114	4.09	(14	)	(14	)	(277	)	(277	)
1/15 - 1/15	—	—	—		—		27,838	4.09	(13	)	(13	)	(13	)	(13	)
2/15 - 2/15	—	—	—		—		24,461	4.09	(11	)	(11	)	(11	)	(11	)
3/15 - 3/15	—	—	—		—		26,443	4.09	(9	)	(9	)	(9	)	(9	)
7/14 - 7/14	29,944	87.85	(519	)	(519	)	20,112	4.19	(4	)	(4	)	(523	)	(523	)
8/14 - 8/14	29,068	87.85	(476	)	(476	)	39,283	4.19	(11	)	(11	)	(487	)	(487	)
9/14 - 9/14	23,498	87.85	(361	)	(361	)	34,246	4.19	(9	)	(9	)	(370	)	(370	)
10/14 -10/14	25,026	87.85	(359	)	(359	)	29,753	4.19	(7	)	(7	)	(366	)	(366	)
11/14 - 11/14	20,000	87.85	(270	)	(270	)	28,635	4.19	(8	)	(8	)	(278	)	(278	)
12/14 -12/14	31,000	87.85	(389	)	(389	)	27,081	4.19	(9	)	(9	)	(398	)	(398	)
1/15 - 1/15	—	—	—		—		34,114	4.19	(13	)	(13	)	(13	)	(13	)
2/15 - 2/15	—	—	—		—		27,838	4.19	(10	)	(10	)	(10	)	(10	)
3/15 - 3/15	—	—	—		—		24,461	4.19	(6	)	(6	)	(6	)	(6	)
7/14 - 7/14	30,279	100.72	(222	)	(222	)	245,330	4.47	17		17		(205	)	(205	)
8/14 - 8/14	29,835	100.72	(189	)	(189	)	223,294	4.47	2		2		(187	)	(187	)
9/14 - 9/14	32,336	100.72	(171	)	(171	)	207,094	4.47	6		6		(165	)	(165	)
10/14 - 10/14	31,438	100.72	(136	)	(136	)	202,612	4.47	7		7		(129	)	(129	)
11/14 - 11/14	30,808	100.72	(111	)	(111	)	186,296	4.47	1		1		(110	)	(110	)
12/14 - 12/14	16,382	100.72	(52	)	(52	)	219,770	4.47	(13	)	(13	)	(65	)	(65	)
1/15 - 1/15	—	—	—		—		94,748	4.47	(10	)	(10	)	(10	)	(10	)
2/15 - 2/15	—	—	—		—		104,401	4.47	(8	)	(8	)	(8	)	(8	)
3/15 - 3/15	—	—	—		—		105,796	4.47	1		1		1		1
			(7,932	)	(7,932	)			(176	)	(176	)	(8,108	)	(8,108	)

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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, 2014		Balance Sheet Location	Fair Value at June 30, 2014			Balance Sheet Location	Fair Value at June 30, 2014
Commodity Contracts	Derivative  financial instruments			Derivative  financial instruments				Derivative  financial instruments
	Current	$	34	Current	$	(8,142	)	Current	$	(8,108	)
	Non-current	—		Non-current	—			Non-current	—
Total derivative instruments		$	34		$	(8,142	)		$	(8,108	)
	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, 2013		Balance Sheet Location	Fair Value at December 31, 2013			Balance Sheet Location	Fair Value at December 31, 2013
Commodity Contracts	Derivative financial instruments			Derivative financial instruments				Derivative financial instruments
	Current	$	1,370	Current	$	(9,828	)	Current	$	(8,458	)
	Non-current	—		Non-current	(31		)	Non-current	(31		)
Total derivative instruments		$	1,370		$	(9,859	)		$	(8,489	)

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 Instruments under Accounting Guidance		Three Months Ended   June 30,						Six Months Ended   June 30,
	Statements of Operations Location	2014			2013			2014			2013
Commodity Contracts	Realized (loss) gain on derivative financial instruments	$	(4,366	)	$	(187	)	$	(8,858	)	$	152
Commodity Contracts	Unrealized (loss) gain on derivative financial instruments	(3		)	5,383			381			(846		)
Total derivative instruments		$	(4,369	)	$	5,196		$	(8,477	)	$	(694	)

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

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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, 2014 and December 31, 2013 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, 2014 Using Fair Value Hierarchy
	Fair Value as of June 30, 2014			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	34		$	—	34			$	—
	$	34		$	—	$	34		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(8,142	)	$	—	$	(8,142	)	$	—
	$	(8,142	)	$	—	$	(8,142	)	$	—
	Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy
	Fair Value as of December 31, 2013			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	1,370		$	—	$	1,370		$	—
	$	1,370		$	—	$	1,370		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(9,859	)	$	—	$	(9,859	)	$	—
	$	(9,859	)	$	—	$	(9,859	)	$	—

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, 2014, 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, 2014 was $149.5 million.

Fair Value on a Non-Recurring Basis

Oil and gas properties with a carrying value of $156.8 million were written down to their fair value of $153.7 million, resulting in an impairment charge of $2.2 million and $3.1 million for the three and six months ended June 30, 2014, which is recognized under “ Impairments of oil and gas properties” in the consolidated statements of operations. 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. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

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NOTE 7—DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:

	June 30, 2014			December 31, 2013
	(in thousands)
	(unaudited)
Senior Secured Revolving Credit Facility	$	—		$	34,500
13.75% Senior Secured Notes, net of discount	149,529			149,383
AFCO Credit Corporation-insurance note payable	—			—
Other debt	790			303
Total debt	150,319			184,186
Less: current portion	(759		)	(257		)
Total long-term debt	$	149,560		$	183,929

Senior Secured Revolving Credit Facility

Our Credit Facility was paid in full on March 17, 2014. As of June 30, 2014, we had zero borrowings outstanding in letters of credit issued under the Credit Facility. On June 8, 2014, our letters of credit were paid in full and terminated.

13.75% Senior Secured Notes

On November 23, 2010, we issued $150 million face value of 13.75% Notes discounted at 99.109% (the "Notes"). The net proceeds were used to repay all of the outstanding indebtedness under our prior revolving Credit Facility, to fund BOEM 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, 2014, the recorded value of the Notes was $149.6 million, whichincludes the unamortized discount of $0.5 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)).

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 (excluding FWS) 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 a maximum limit of $60 million for the fiscal year ending December 31, 2012 and 30% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expense for any year thereafter. Compliance is not required until the end of the year.

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For a discussion of the pending cash tender offer to purchase all of the Notes, please see “Notes to Consolidated Financial Statements-Note 11-Subsequent Events” in this Form 10-Q.

The amounts of required principal payments based on our outstanding debt amounts as of June 30, 2014, were as follows:

Period Ending June 30,	(in thousands)
2015	$	760
2016	150,030
2017	—
	150,790
Unamortized discount on 13.75% Senior Secured Notes	(471		)
Total debt	$	150,319

NOTE 8- MEMBERS' DEFICIT

The Member Agreement (the “Agreement”) has four (Class A, B, C, and E) classes of members. Net income (loss) is allocated to the members in accordance with the terms set forth in the Agreement. The Agreement allows for preferred returns to certain members after internal rate of return and return of investment hurdles are met.

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 50.0 million additional Class E Preferred Units (the “Class E Units”) and 3.8 million additional Class B Units to the Platinum Group for an aggregate offering price of $50.0 million. The Class E Units are recorded under "Preferred Units" and the Class B Units are included in "Members Deficit" in the consolidated balance sheets. 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 D Preferred Units were recorded under "Preferred Units" in the consolidated balance sheets. The Class E Units had a preferred return of 20% per annum, which was set to increase to 36% on March 25, 2014. On March 24, 2014, AQR Diversified Arbitrage Fund exercised its right, and we complied, requiring us and PPVA to repurchase all of its Class E Preferred Units for $14.0 million. We obtained waivers to the Class E Preferred Units waiving the incremental preferred return. As a result of the waivers obtained, we issued Class E Units of approximately $8.2 million as paid-in-kind dividends as of June 30, 2014.

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.

West Delta 32

We continue to go through the discovery phases of the civil litigation of the personal injury lawsuits filed as a result of the November 16, 2012, explosion and fire which occurred on our West Delta 32-E platform, located in the Gulf of Mexico approximately 17 miles southeast of Grand Isle, Louisiana. At the time of the explosion, production on the platform had been

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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

Mediation occurred on June 19th and 20th, 2014 for these civil lawsuits in Houston, Texas, and was largely unsuccessful. One suit settled, but the remaining cases are still pending. For each proceeding, we are currently evaluating the plaintiff’s petitions and determining appropriate courses of response with the aid of outside 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. We intend to vigorously defend the Company in these proceedings.

As previously reported, six investors in Black Elk Energy, LLC (“BEE”) filed a purported derivative complaint on behalf of BEE in the Supreme Court of the State of New York, County of New York, against the Company, John Hoffman, Iron Island Technologies Inc., and various entities and individuals associated with the Company’s majority unit owner (the “Platinum Defendants”). The lawsuit seeks unspecified damages allegedly arising from (1) the dilution of BEE’s ownership interest in the Company through various financing transactions with the Platinum Defendants and the issuance of membership units under management and employee incentive programs; and (2) the alleged mismanagement of the Company in connection with certain alleged safety violations and the West Delta 32 Incident. We believe there are strong defenses to the claims asserted in the lawsuit, and the Company intends to defend the case vigorously. On or about September 24, 2013, Plaintiffs filed a motion for a preliminary injunction to restrain a portion of the proceeds of the Company’s proposed sale of certain oil fields in the Gulf of Mexico. The Court denied the motion on November 15, 2013. On or about November 20, 2013, we filed a motion to dismiss the complaint in its entirety, inter alia, on the grounds that (i) the claims fail to state a cause of action; (ii) the claims are refuted by documentary evidence; (iii) plaintiffs, who are not members of the Company, lack standing to assert a claim for mismanagement of the Company; and (iv) certain claims are barred by the statute of limitations. The motion is now fully briefed. Discovery is at an early stage, with the parties beginning to make rolling document productions.

The arbitration case involving GIS and Black Elk for unpaid invoices for services and materials provided by GIS (the “Invoice Arbitration”) is scheduled for hearing before a single arbitrator on December 1, 2014. The arbitration case for damages to the West Delta 32 Platform (the “Platform Arbitration”) is scheduled for hearing before a three-arbitrator panel on May 12, 2015. The arbitration proceeding initiated by Black Elk against Compass Engineering & Consultants, LLC for damages arising from the explosion of the WD-32 Platform has been abated pending resolution of Compass’ separate lawsuit filed in the United States District for the Western District of Louisiana seeking a declaration that it was not subjected to arbitration.

Vistar Oil Texas LLC Joint Venture

On April 16, 2014, Vistar Oil Texas LLC (“Vistar”) filed a petition against Black Elk in Harris County District Court. This suit alleges that Black Elk breached an Acquisition and Participation Agreement and a Joint Operating Agreement between the parties, primarily by failing to provide Vistar with the funds required to bring several wells into operation in Wilson County, Texas. Vistar alleges damages of approximately $6,500,000, certain lease acquisition costs and promissory note payments required to cover liens placed on the wells. Vistar further alleges that Black Elk is in breach by refusing to provide approximately $10,350,000 to Vistar to acquire additional property. This case is in the beginning stages of discovery.

Operating Leases

We lease office space and certain equipment under non-cancellable operating lease agreements that expire on various dates through 2020.

Approximate future minimum lease payments for operating leases at June 30, 2014 were as follows:

Period Ending June 30,	(in thousands)
2015	$	3,973
2016	2,072
2017	1,808
2018	1,620
2019	1,530
Thereafter	2,326
	$	13,329

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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, 2014, we have funded $19.5 million into the non-operating escrow account, leaving $11.7 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. This escrow obligation was fully funded in 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. This escrow obligation was fully funded in November 2013.

NOTE 10—RELATED PARTY TRANSACTIONS

We pay for certain operating and general and administration expenses on behalf of Black Elk Energy, LLC. At both June 30, 2014 and December 31, 2013, we had receivables from Black Elk Energy, LLC in the amount of $273,430.

On August 30, 2013, we consented to the assignment by Capital One Bank, N.A. and the other lenders of all of their rights and obligations under our Credit Facility to White Elk LLC, as Administrative Agent and Lender, and Resource Value Group LLC, as Lender. Resource Value Group LLC is affiliated with Platinum. As part of this transaction, we paid a required $0.3 million purchase fee on behalf of Platinum pursuant to the Loan Purchase Agreement.

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. Please see "Notes to Consolidated Financial Statements - Note 8 - Member's Deficit" in this Form 10-Q for additional discussion regarding member's contributions.

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, 2014, we have not purchased all of the equipment. We currently have restricted cash of $0.6 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”.

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NOTE 11—SUBSEQUENT EVENTS

Renaissance Sale

On July 10, 2014, we entered into a Purchase and Sale Agreement with Renaissance Offshore, LLC. Pursuant to the Purchase and Sale Agreement, Renaissance will acquire our interests, subject to certain exclusions, in nine fields, seven operated and two non-operated, in the offshore Gulf of Mexico, for $170 million in cash, subject to normal purchase price adjustments (the "Renaissance Sale"). Subject to customary closing conditions, the Renaissance Sale is expected to close in August 2014. The assets to be sold in the Renaissance Sale represent a significant amount of our cash flow, proved reserves and production.

Tender Offer and Consent Solicitation

On July 16, 2014, we commenced a cash tender offer to purchase all of the Notes on the terms and subject to the conditions set forth in an Offer to Purchase and Consent Solicitation Statement dated July 16, 2014. In conjunction with the tender offer, and on the terms and subject to the conditions set forth in the offer documents, we are soliciting consents of holders of the Notes to modify certain of the restrictive covenants contained in the indenture governing the Notes. The Offer and the Consent Solicitation are being made solely by means of the offer documents, which were made available to the holders of Notes. Under no circumstances shall this Quarterly Report on Form 10-Q constitute an offer to purchase or the solicitation of an offer to sell the Notes or a solicitation of consents to the proposed amendments.

Holders of Notes must validly tender their Notes at or before 5:00 p.m., Eastern Standard Time, on August 13, 2014 in order to be eligible to receive the offer consideration. The total consideration for each $1,000 principal amount of Notes purchased pursuant to the Offer will be $1,000 plus accrued and unpaid interest in respect of such purchased Notes from the last interest payment date to, but not including, the applicable payment date for the Notes.

The Offer and the Consent Solicitation are being made in connection with our proposed disposition of certain assets pursuant to the Renaissance Sale. The net proceeds of the Renaissance Sale will be used to fund our purchase of the Notes. If the amount required to purchase all Notes validly tendered before the expiration time (including all accrued and unpaid interest) exceeds the amount of net proceeds from the Renaissance Sale, the Notes validly tendered will be accepted and purchased on a pro rata basis according to the principal amount of Notes tendered by each tendering Holder.

Our obligation to accept for purchase and to pay for Notes validly tendered and not withdrawn pursuant to the tender offer is subject to the satisfaction or waiver, in our discretion, of certain conditions, including, among others, our receipt of consents from the holders of at least a majority in principal amount of the outstanding Notes to the proposed amendments and our receipt of aggregate proceeds in the Renaissance Sale of at least $100 million.

If consents from the holders of at least a majority in principal amount of the outstanding Notes have been validly received prior to the expiration time and the conditions to effectiveness have been satisfied or waived, we will enter into a Second Supplemental Indenture in order to effect the proposed amendments to the indenture. Among other things, the proposed amendments would:

• allow us to apply the net proceeds from the Renaissance Sale to consummate the tender offer and to use any remaining proceeds from the Renaissance Sale to purchase our preferred equity;

• permit the incurrence of indebtedness arising from the performance of our plugging and abandonment obligations and liens on our oil and gas properties to secure such indebtedness; and

• remove the covenant prohibiting us from incurring aggregate capital expenditures in excess of 30% of Consolidated EBITDAX in any fiscal year.

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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 2013 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;

15

• Geological concentration of our reserves;

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

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

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

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

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

• Weather conditions;

• Availability and cost of material and equipment;

• Delays in anticipated 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; 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 2013 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 in this Form 10-Q, 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, 2014, we held an aggregate net interest in approximately 348,962 gross (193,185 net) acres under lease and had an interest in 658 gross wells, 107 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 South Timbalier 8, in 2008, and West Cameron 66 acquisitions in 2008, 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

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or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since our inception, commodity prices have experienced significant fluctuations.

From time to time, we use derivative financial instruments to economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. Our average prices that reflect both the before and after effects of our realized commodity hedging transactions for the three and six months ended June 30, 2014 and 2013 are shown in the table below.

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2014		2013		2014		2013
Oil:
Average price before effects of hedges ($/Bbl)(1)	$	104.77	$	103.98	$	102.87	$	107.00
Average price after effects of hedges ($/Bbl)	86.84		101.43		89.59		104.21
Average price differentials(2)	1.71		9.84		1.98		12.78
Gas:
Average price before effects of hedges ($/Mcf)(1)	$	4.83	$	4.22	$	5.05	$	3.89
Average price after effects of hedges ($/Mcf)	4.79		4.46		4.87		4.23
Average price differentials(2)	0.24		0.20		0.18		0.13

(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.

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Recent Events

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 ("BOEM") 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

In a meeting held at the BSEE Regional Office on October 30, 2013, BEEOO shared with BSEE representatives that implementation of corrective actions (18 elements and 58 tasks) associated with the PIP has been 100% completed. Other essential work control processes such as our 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, National Pollutant Discharge Elimination System ("NPDES"), Job Safety Analysis ("JSA") and Stop Work Authority ("SWA") will be ongoing and has been incorporated into our training matrix.

On May 22, 2014, we received a letter from BSEE expressing that BEOO completed all the items and elements described in our Performance Improvement Plan. The last remaining task list item is to notify the Lake Charles District upon completion of the Vermilion Block 369 A platform blasting and painting operations. We plan to meet this remaining task list. BSEE recognizes that BEOO has made safety enhancements and implemented changes to our oversight processes on our operated platforms. We plan to continue with cultivating a safety environment in an effort to mitigate risks in all operations as required by statute and regulation.

Additionally, BSEE will continue to regularly inspect our facilities and conduct compliance follow-up inspections to confirm correction of noncompliance issued since the beginning of 2014.

On June 5, 2014, BEEOO notified BSEE Lake Charles District of the completion of the last remaining item on the Performance Improvement Plan, i.e. Vermilion Block 369 platform blasting and painting operations, on June 4, 2014.

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 had a preferred return of 20% per annum, which was set to increase to 36% on March 25, 2014 (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement). On March 24, 2014 AQR Diversified Arbitrage Fund exercised its right, and we complied, requiring us and PPVA to repurchase all of its Class E Preferred Units for $14.0 million. We obtained waivers to the Class E Preferred Units waiving the incremental preferred return. As a result of the waivers obtained, we issued an additional amount of Class E Units of approximately $8.2 million as paid-in-kind dividends as of June 30, 2014.

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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 Waivers And Amendments

On August 15, 2013, we entered into a Limited Waiver, Ninth Amendment to Letter of Credit Facility Agreement to (1) obtain waivers related to certain covenants in the Letter of Credit Facility for the fiscal quarter ended June 30, 2013, (2) reduce the commitments and cap the outstanding principal balance under the Letter of Credit Facility at approximately $105.7 million and (3) reduce the maximum principal amount available under the Third Amended and Restated Note dated November 8, 2012 from $200.0 million to approximately $105.7 million.

On November 14, 2013, we entered into the Waiver and Tenth Amendment on our Letter of Credit Facility to (1) obtain waivers related to our financial covenants for the third quarter of 2013, (2) cap the outstanding principal balance under the Letter of Credit Facility at approximately $66.6 million, (3) no longer issue or renew existing Letters of Credit and (4) remove the financial covenant requirements and the restriction of asset sales.

As of June 30, 2014, we had zero borrowings outstanding in letters of credit issued under this Credit Facility. Our letters of credit have been paid in full and terminated on June 8, 2014.

Revolving Credit Facility Waivers and Amendments

On March 17, 2014, our credit facility was paid in full.

Liquidity, Risks and Uncertainties

While cash flows were lower than previously projected primarily due to lower production and sales of assets in the third and fourth quarters of 2013, we continued our development operations, in the first quarter of 2014, by supplementing our cash flows from operating activities with funds raised through divestiture of non-key assets.  Additionally, we significantly reduced our workforce and associated general and administrative expenses to match our down sized operations.

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately$110.0 million at June 30, 2014. The combination of restricted credit availability, lower production since the fourth quarter of 2013, our drilling program, settlement of our P&A liabilities and additional collateral requirements related to our surety bonds that secure our P&A obligations led to significant cash reductions in the year 2013 and into the first quarter of 2014. To increase liquidity, we stretched accounts payable, aggressively pursued accounts receivable and sold non-core assets. We have worked closely with our vendors during this time and are working to normalize the age of accounts payables.

In 2013 we realized approximately $131.8 million in sales proceeds (subject to customary closing adjustments) which we used to reduce our credit facility and fund our 2013 capital expenditures. On March 17, 2014 our Credit Facility was paid in full.

Our primary use of capital has been for the 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. Our letters of credit with Capital One that were backed entirely by cash were paid in full on June 8, 2014. We used these letters of credit to back our surety bonds for P&A obligations. We terminated the 100% cash-backed letters of credit and increased our collateral with the surety agencies in the second quarter of 2014 for P&A obligations.

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On July 10, 2014, we entered into a Purchase and Sale Agreement with Renaissance Offshore, LLC. Pursuant to the

Purchase and Sale Agreement, Renaissance will acquire our interests, subject to certain exclusions, in nine fields, seven

operated and two non-operated, -in the offshore Gulf of Mexico, for $170 million in cash, subject to normal purchase price

adjustments (the "Renaissance Sale"). Subject to customary closing conditions, the Renaissance Sale is expected to close in

August 2014. The assets to be sold in the Renaissance Sale represent a significant amount of our cash flow, proved reserves and

production.

On July 16, 2014, we commenced a cash tender offer to purchase all of the Notes on the terms and subject to the

conditions set forth in an Offer to Purchase and Consent Solicitation Statement dated July 16, 2014. In conjunction with the

tender offer, and on the terms and subject to the conditions set forth in the offer documents, we are soliciting consents of

holders of the Notes to modify certain of the restrictive covenants contained in the indenture governing the Notes. The Offer

and the Consent Solicitation are being made solely by means of the offer documents, which were made available to the

holders of Notes. Under no circumstances shall this Quarterly Report on Form 10-Q constitute an offer to purchase or the

solicitation of an offer to sell the Notes or a solicitation of consents to the proposed amendments.

Holders of Notes must validly tender their Notes at or before 5:00 p.m., Eastern Standard Time, on August 13, 2014 in

order to be eligible to receive the offer consideration. The total consideration for each $1,000 principal amount of Notes

purchased pursuant to the Offer will be $1,000 plus accrued and unpaid interest in respect of such purchased Notes from the

last interest payment date to, but not including, the applicable payment date for the Notes.

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.

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.

We consider the control and flexibility afforded by operating our properties under development to be instrumental to our business plan and strategy. To manage our liquidity, we have the ability to delay certain capital commitments, and within certain constraints, we can continue to conserve capital by further delaying or eliminating future capital commitments. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility is one method by which we can match, on a temporary basis, our capital commitments to our available capital resources.

Virtually all of 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.

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, 2014 and 2013:

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2014			2013			2014		2013
Average daily sales:
Oil (Bopd)	2,628			4,231			3,377		4,437
Natural gas (Mcfpd)	20,033			36,764			23,513		38,939
Plant products (Galpd)	17,094			24,741			18,659		28,419
Oil equivalents (Boepd)	6,374			10,947			7,740		11,604
Average realized prices(1):
Oil ($/Bbl)	$	86.84		$	101.43		$	89.59	$	104.21
Natural gas ($/Mcf)	4.79			4.46			4.87		4.23
Plant products ($/Gallon)	0.89			0.83			0.93		0.85
Oil equivalents ($/Boe)	53.23			56.03			56.13		56.14
Costs and Expenses:
Lease operating expense ($/Boe)	47.06			47.15			38.50		42.93
Production tax expense ($/Boe)	(0.05		)	0.19			0.05		0.15
General and administrative expense ($/Boe)	9.44			9.42			9.09		8.87
Net (loss) income (in thousands)	(22,725		)	(39,517		)	9,541		(55,730		)
Adjusted EBITDA(2) (in thousands)	1,511			2,407			18,505		8,902

(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, West Delta 32 costs, unrealized loss (gain) 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 or cash flows as determined by GAAP, and should not be considered as an alternative to net loss, operating loss or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as a measure of our liquidity. We present Adjusted EBITDA because it is frequently used by securities analysts, investors and other interested parties in the evaluation of high-yield issuers, many of whom present Adjusted EBITDA when reporting their results. Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results or cash flows as reported under GAAP. Because of these limitations, Adjusted EBITDA should not be considered as a measure 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,
	2014			2013			2014			2013
	(in thousands)
Net (loss) income	$	(22,725	)	$	(39,517	)	$	9,541		$	(55,730	)
Adjusted EBITDA	$	1,511		$	2,407		$	18,505		$	8,902
Reconciliation of Net (loss) income to Adjusted EBITDA
Net (loss) income	$	(22,725	)	$	(39,517	)	$	9,541		$	(55,730	)
Interest expense, net	5,957			6,218			12,151			12,481
Surety and letter of credit fees	1,952			2,380			3,484			4,559
West Delta 32 costs	11			3,847			247			—
Unrealized loss (gain) on derivative instruments	3			(5,383		)	(381		)	846
Accretion of asset retirement obligations	1,909			7,569			2,986			15,093
Depreciation, depletion and amortization	8,174			11,145			21,938			22,700
Impairment of oil and gas properties	2,161			22,414			3,074			55,377
Gain on involuntary conversion of assets	—			(8,250		)	—			(10,633		)
Provision for doubtful accounts	—			—			16			—
Loss (gain) on sale of assets	4,069			1,984			(34,551		)	(35,791		)
Adjusted EBITDA	$	1,511		$	2,407		$	18,505		$	8,902

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The following table sets forth certain information with respect to oil and gas operations for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30,											Six Months Ended June 30, 2013
	2014			2013			Change			% Change		2014			2013			Change			% Change
PRODUCTION:
Oil (MBbl)	239			385			(146		)	(38	)%	611			803			(192		)	(24	)%
Natural gas (MMcf)	1,823			3,346			(1,523		)	(46	)%	4,256			7,048			(2,792		)	(40	)%
Plant products (MGal)	1,556			2,251			(695		)	(31	)%	3,377			5,144			(1,767		)	(34	)%
Total (MBoe)	580			996			(416		)	(42	)%	1,401			2,100			(699		)	(33	)%
REVENUES:
Oil sales	$	25,057		$	40,035		$	(14,978	)	(37	)%	$	62,881		$	85,936		$	(23,055	)	(27	)%
Natural gas sales	8,802			14,109			(5,307		)	(38	)%	21,474			27,445			(5,971		)	(22	)%
Plant product sales and other revenue	1,380			1,858			(478		)	(26	)%	3,133			4,375			(1,242		)	(28	)%
Realized (loss) gain on derivative financial instruments	(4,366		)	(187		)	(4,179		)	2,235	%	(8,858		)	152			(9,010		)	(5,928	)%
Unrealized (loss) gain  on derivative financial instruments	(3		)	5,383			(5,386		)	(100	)%	381			(846		)	1,227			(145	)%
Other revenues	6,551			5,177			1,374			27	%	13,388			9,300			4,088			44	%
TOTAL REVENUES	37,421			66,375			(28,954		)	(44	)%	92,399			126,362			(33,963		)	(27	)%
OPERATING EXPENSES:
Lease operating	27,297			46,971			(19,674		)	(42	)%	53,940			90,173			(36,233		)	(40	)%
Production taxes	(28		)	189			(217		)	(115	)%	69			316			(247		)	(78	)%
Workover	283			4,224			(3,941		)	(93	)%	618			6,284			(5,666		)	(90	)%
Depreciation, depletion and amortization	8,174			11,145			(2,971		)	(27	)%	21,938			22,700			(762		)	(3	)%
Impairment of oil and gas properties	2,161			22,414			(20,253		)	(90	)%	3,074			55,377			(52,303		)	(94	)%
General and administrative	5,473			9,388			(3,915		)	(42	)%	12,730			18,629			(5,899		)	(32	)%
Gain on involuntary conversion of asset	—			(8,250		)	8,250			(100	)%	—			(10,633		)	10,633			(100	)%
Accretion of asset retirement obligations	1,909			7,569			(5,660		)	(75	)%	2,986			15,093			(12,107		)	(80	)%
Loss (gain) on sale of assets	4,069			1,984			2,085			105	%	(34,551		)	(35,791		)	1,240			(3	)%
Other operating expenses	2,776			1,423			1,353			95	%	5,350			2,413			2,937			122	%
TOTAL OPERATING EXPENSES	52,114			97,057			(44,943		)	(46	)%	66,154			164,561			(98,407		)	(60	)%
(LOSS) INCOME FROM OPERATIONS	(14,693		)	(30,682		)	15,989			(52	)%	26,245			(38,199		)	64,444			(169	)%
OTHER INCOME (EXPENSE):
Interest income	13			29			(16		)	(55	)%	36			51			(15		)	(29	)%
Miscellaneous expense	(2,035		)	(2,564		)	529			(21	)%	(4,466		)	(4,946		)	480			(10	)%
Interest expense	(6,010		)	(6,300		)	290			(5	)%	(12,274		)	(12,636		)	362			(3	)%
TOTAL OTHER EXPENSE, NET	(8,032		)	(8,835		)	803			(9	)%	(16,704		)	(17,531		)	827			(5	)%
NET (LOSS) INCOME	$	(22,725	)	$	(39,517	)	$	16,792		(42	)%	$	9,541		$	(55,730	)	$	65,271		(117	)%

Production

Oil and natural gas production. Total oil, natural gas and plant product production of 580 MBoe decreased 416 MBoe, or 42%, and 1,401 MBoe decreased 699 MBoe, or 33%, during the three and six months ended June 30, 2014 compared to the same periods in 2013 as a result of asset sales, pipeline repairs, and natural decline.

Revenues

Total revenues. Total revenues for the three and six months ended June 30, 2014 of $37.4 million and $92.4 million decreased $28.9 million, or 44%, and $33.9 million, or 27% , respectively, over the comparable periods in 2013.

Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, decreased $19.4 million, or 31.7%, and $26.2 million, or 20.6%, for the three and six months ended June 30, 2014, respectively, compared to the same periods in 2013. The decrease was primarily due to the impact of recent divestitures of properties and various gas pipeline shut partially offset by higher oil sales and the consolidation of Freedom Well Services, LLC.

We entered into certain oil and natural gas commodity derivative contracts in 2014 and 2013. We realized (losses) gains on these derivative contracts in the amounts of $(4.4) million and $(8.9) million for the three and six months ended June 30, 2014, respectively, and $(0.2) million and $0.2 million for the three and six months ended June 30, 2013, respectively. We

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recognized unrealized gains (losses) of $(3) thousand and $0.4 million for the three and six months ended June 30, 2014, respectively, and $5.4 million and $(0.8) million in the same periods of 2013.

Excluding hedges, we realized average oil prices of $104.77 per barrel and $102.87 per barrel and gas prices of $4.83 per Mcf and $5.05 per Mcf for the three and six months ended June 30, 2014, respectively. For the same periods in 2013, 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. Oil prices were lower on a quarter and year-to-date basis that were partially offset by slightly higher gas prices compared to 2013. 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, 2014 were $27.3 million, or $47.06 per Boe, and $53.9 million, or $38.50 per Boe. For the three and six months ended June 30, 2013, our lease operating costs were $47.0 million, or $47.15 per Boe, and $90.2 million, or $42.93 per Boe, respectively. Lease operating expenses decreased by $19.7 million and $(36.2) million for the three and six months ended June 30, 2014, respectively, compared to the same periods in 2013, primarily as a result of the 2013 Renaissance transaction and the recent Fieldwood transaction. The increase in cost per Boe during 2014 was primarily attributable to decreased production.

Workover costs. Our workover costs for the three and six months ended June 30, 2014 were $0.3 million and $0.6 million, a decrease of $3.9 million and $5.7 million compared to the second quarter of 2013, respectively. For the six months ended June 30, 2014, South Timbalier 8, Vermillin 369/370, South Pass 86/87/89, and East Cameron 334/335 were the primary workover expense projects.

Depreciation, depletion, amortization and impairment. DD&A expense was $8.2 million, or $14.09 per Boe, and $21.9 million, or $15.66 per Boe, for the three and six months ended June 30, 2014, respectively. For the three and six months ended June 30, 2013, DD&A was $11.1 million, or $11.19 per Boe and $22.7 million, or $10.8 per Boe, respectively. The decrease in DD&A for the three and six months ended June 30, 2014 was a result of lower production and reduced asset basis as a result of the impairments recorded in 2014 and 2013. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded $2.2 millions and $3.1 million impairment for the three and six months ended June 30, 2014 and $22.4 million and $55.4 million in the same periods in 2013, respectively.

General and administrative expenses. G&A expense was $5.5 million, or $9.44 per Boe, and $12.7 million, or $9.09 per Boe, for the three and six months ended June 30, 2014, respectively, and $9.4 million, or $9.42 per Boe, and $18.6 million million, or $8.87 per Boe, for the same periods in 2013. The decrease in G&A expense for the three and months ended June 30, 2014 was primarily the result of headcount reductions, restructuring overhead and insurance contracts, and costs related to our consolidation of Freedom Well Services, LLC. G&A expense for the six month ended June 30, 2013 reflects a reclassification of surety fees from G&A expenses to miscellaneous expense.

Accretion expense. We recognized accretion expense of $1.9 million and $3.0 million for the three and six months ended June 30, 2014, respectively, compared to $7.6 million and $15.1 million for the three and six months ended June 30, 2013. The decrease in accretion expense is a result of P&A activity incurred during 2013 and the six months ended June 30, 2014, decreased asset retirement liability due to the sale of properties during 2013 and the three months ended March 31, 2014, and a revision to the discount rate used to calculate accretion. As the Company had fully funded our operating escrow accounts, we have prospectively adjusted the accretion rate to be reflective.

Gain on sale of assets. We recognized a loss (gain) on the sale $4.1 million and $(34.6) million for the three and six months ended June 30, 2014 related to the Apache settlement and the sale to Fieldwood Energy LLC (“Fieldwood”), respectively. Fieldwood acquired all of the Company’s interest in one operated and 15 non-operated fields in the offshore Gulf of Mexico, for $50 million, subject to normal purchase price adjustments. The Sale closed on March 17, 2014.

Other operating expenses. Other operating expenses of $2.8 million and $5.4 million for the three and six months ended June 30, 2014, compared to $1.4 million and $2.4 million for the three and six months ended June 30, 2013, increase was related to our consolidation of Freedom Well Services, LLC.

Miscellaneous expense. Miscellaneous expense is $2.0 million and $4.5 million for the three and six months ended June 30, 2014, compared to $2.6 million and $4.9 million for the three and six months ended June 30, 2013, respectively. Miscellaneous expense for the three and six months ended June 30, 2013 reflects reclassification of surety fees from G&A expense to miscellaneous expense. Miscellaneous expense for the three and six months ended June 30, 2014 reflects a decrease in surety and escrow fees and a settlement loss of $0.8 million incurred in the first quarter of 2013. The settlement loss of $0.8

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million related to final settlement on outstanding accounts payable and accounts receivable between Black Elk Energy and Fieldwood, Apache and W&T Offshore.

Liquidity and Capital Resources

The combination of restricted credit availability, declining production since the fourth quarter of 2012, settlement of our plugging and abandonment (P&A) liabilities and additional collateral requirements related to our surety bonds that secure our P&A obligations led to significant reductions in cash beginning in the fourth quarter of 2012 and continuing throughout the second quarter of 2014.  To increase liquidity, we continue to stretch accounts payable, aggressively pursued accounts receivable and seek opportunities to divest non-core assets.  During the remainder of 2014, we expect to continue to sell non-core assets in an effort to improve our liquidity position.

As of June 30, 2014 our primary use of capital has been for exploitation of oil and natural gas properties as well as providing collateral to secure our P&A obligations. As we abandon certain fields and meet the various criteria related to the corresponding escrow accounts, we expect to release funds from the escrow accounts. Furthermore, we no longer use letters of credit to back our surety bonds for P&A obligations. Our surety bonds are now backed by the surety agencies.

The amount, timing and allocation of capital expenditures are largely discretionary and within our control. In 2014 we have decided to defer a significant portion of our identified 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 will monitor and adjust our future capital expenditures to respond to changes in prices, availability of financing, industry conditions, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Senior Secured Revolving Credit Facility

On December 24, 2010, we entered into a Credit Facility comprised of a senior secured revolving credit facility of up to $35 million 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 4.75% to 5.5%, or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 3.25% to 4.00%. The applicable margin is computed based on the borrowing based utilization percentage in effect from time to time. The borrowing base under our 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 were 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 Credit Facility, and by cash collateral, in the case of the Letter of Credit Facility. On March 17, 2014 the Credit Facility was paid in full.

We have entered into various amendments to the Letter of Credit Facility. These amendments have, among other things, (1) adjusted the commitments under the Letter of Credit Facility to a current level of approximately $66.6 million, (2) updated the fees on the letters of credit to 2% on a go-forward basis, (3) changed the maturity date from June 22, 2014 on the Letter of Credit Facility.

At March 31, 2014, letters of credit in the aggregate amount of $66.6 million were outstanding under the Letter of Credit Facility. As of June 30, 2014, these letters of credit were paid in full and closed.

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.

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 BOEM 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.

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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, 2014, the recorded value of the Notes was $149.5 million, which includes the unamortized discount of $0.5 million.

Renaissance Sale

On July 10, 2014, we entered into a Purchase and Sale Agreement with Renaissance Offshore, LLC. Pursuant to the

Purchase and Sale Agreement, Renaissance will acquire our interests, subject to certain exclusions, in nine fields, seven

operated and two non-operated, in the offshore Gulf of Mexico, for $170 million in cash, subject to normal purchase price

adjustments (the "Renaissance Sale"). Subject to customary closing conditions, the Renaissance Sale is expected to close in

August 2014. The assets to be sold in the Renaissance Sale represent a significant amount of our cash flow, proved reserves and

production.

Tender Offer and Consent Solicitation

On July 16, 2014, we commenced a cash tender offer to purchase all of the Notes on the terms and subject to the conditions set forth in an Offer to Purchase and Consent Solicitation Statement dated July 16, 2014. In conjunction with the tender offer, and on the terms and subject to the conditions set forth in the offer documents, we are soliciting consents of holders of the Notes to modify certain of the restrictive covenants contained in the indenture governing the Notes. The Offer and the Consent Solicitation are being made solely by means of the offer documents, which were made available to the holders of Notes. Under no circumstances shall this Quarterly Report on Form 10-Q constitute an offer to purchase or the solicitation of an offer to sell the Notes or a solicitation of consents to the proposed amendments.

Holders of Notes must validly tender their Notes at or before 5:00 p.m., Eastern Standard Time, on August 13, 2014 in order to be eligible to receive the offer consideration. The total consideration for each $1,000 principal amount of Notes purchased pursuant to the Offer will be $1,000 plus accrued and unpaid interest in respect of such purchased Notes from the last interest payment date to, but not including, the applicable payment date for the Notes.

The Offer and the Consent Solicitation are being made in connection with our proposed disposition of certain assets pursuant to the Renaissance Sale. The net proceeds of the Renaissance Sale will be used to fund our purchase of the Notes. If the amount required to purchase all Notes validly tendered before the expiration time (including all accrued and unpaid interest) exceeds the amount of net proceeds from the Renaissance Sale, the Notes validly tendered will be accepted and purchased on a pro rata basis according to the principal amount of Notes tendered by each tendering Holder.

Our obligation to accept for purchase and to pay for Notes validly tendered and not withdrawn pursuant to the tender offer is subject to the satisfaction or waiver, in our discretion, of certain conditions, including, among others, our receipt of consents from the holders of at least a majority in principal amount of the outstanding Notes to the proposed amendments and our receipt of aggregate proceeds in the Renaissance Sale of at least $100 million.

If consents from the holders of at least a majority in principal amount of the outstanding Notes have been validly received prior to the expiration time and the conditions to effectiveness have been satisfied or waived, we will enter into a Second

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Supplemental Indenture in order to effect the proposed amendments to the indenture. Among other things, the proposed amendments would:

• allow us to apply the net proceeds from the Renaissance Sale to consummate the tender offer and to use any remaining proceeds from the Renaissance Sale to purchase our preferred equity;

• permit the incurrence of indebtedness arising from the performance of our plugging and abandonment obligations and liens on our oil and gas properties to secure such indebtedness; and

• remove the covenant prohibiting us from incurring aggregate capital expenditures in excess of 30% of Consolidated EBITDAX in any fiscal year.

Member 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 had a preferred return of 20% per annum, which was set to increase on 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 24, 2014 AQR Diversified Arbitrage Fund exercised its right, and we complied, requiring us and PPVA to repurchase all of its Class E Preferred Units for $14.0 million. We obtained waivers to the Class E Preferred Units waiving the incremental preferred return. As a result of the waivers obtained, we issued an additional amount of Class E Units of approximately $8.2 million as paid-in-kind dividends as of June 30, 2014.

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.

Stock Split. 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.

Operating Agreement Amendment. In April 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.

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. Please see “—Oil and Natural Gas Hedging” and “—Quantitative and Qualitative Disclosures About Market Risk.”

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, 2014 and 2013:

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	Six Months Ended June 30,
	2014			2013
Net cash (used in) provided by operating activities	$	(15,774	)	$	26,655
Net cash provided by (used in) investing activities	60,922			(33,535		)
Net cash (used in) provided by financing activities	(48,013		)	18,318
Net (decrease) increase in cash and equivalents	$	(2,865	)	$	11,438

Cash flows (used in ) provided by operating activities. Cash used in operating activities totaled $(15.8) million during the six months ended June 30, 2014 compared to $26.7 million provided by operating activities during the six months ended June 30, 2013. Significant components of net cash (used in) provided by operating activities during the six months ended June 30, 2014 included $(20.1) million of changes in operating assets and liabilities and $(5.2) million of non-cash items, primarily DD&A expense, impairment and accretion of asset retirement obligations partially offset by the net gain on sale of assets. Cash provided by operating activities in the comparable period of 2013 were attributed tochanges in operating assets and liabilities and 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.

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) provided by investing activities. Cash provided by investing activities was $60.9 million in the six months ended June 30, 2014 was primarily attributable to the sale to Fieldwood Energy LLC partially offset by additions to the oil and gas properties during the period and the funding of the future P&A obligations through escrow. Cash used in investing activities in the comparable period of 2013 were attributed to oil and gas property additions associated with the capital drilling program during the period and the funding of the future P&A obligations through escrow partially offset by the sale proceeds of the sale of four fields to Renaissance Offshore and proceeds received from insurance recovery for HI 443.

Cash flows (used in) provided by financing activities. Cash flows used in financing activities of $48.0 million in the six months ended June 30, 2014 were attributable to $34.5 million of payments on the Credit Facility and $14.0 million distribution to members. Cash flows provided by financing activities of $18.3 million ended June 30, 2013 were attributable to contributions from Platinum Group and PPVA and borrowings under the Credit Facility partially offset by payments on the Credit Facility and short-term notes.

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, 2014, we had a decrease of $25.9 million in our asset retirement obligations primarily as a result of the asset sales to Fieldwood Energy, LLC and recognized $3 million in accretion expense. For the three and six months ended June 30, 2013, we decreased our assets retirement obligations primarily as a result of the sale of four fields to Renaissance Offshore, LLC and in P&A work performed in 2013.

At June 30, 2014 and December 31, 2013, we have total asset retirement obligations of $250.8 million and $276.7 million, respectively, and have funded approximately $231.0 million and $235.4 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds. As of June 30, 2014 and December 31, 2013, 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, 2014:

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	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	$	150,319	$	759	$	149,560	$	—	$	—
Interest on debt and notes payable	29,229		20,635		8,594		—		—
Operating leases (1)	13,329		3,973		3,880		3,150		2,326
Total contractual obligations	192,877		25,367		162,034		3,150		2,326
Other Obligations
Asset retirement obligations (2)	250,838		26,746		136,772		11,525		75,795
Total obligations (3)	$	443,715	$	52,113	$	298,806	$	14,675	$	78,121

(1) Consists of 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. The obligations reflected above are discounted.

(3) Does not include 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.

Oil and Gas Hedging

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

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

Please see “Notes to Consolidated Financial Statements—Note 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2013 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, 2014, we received an average of $104.77 and $102.87 per barrel of oil and $4.83 and $5.05 per Mcf of natural gas, respectively, before consideration of commodity derivative contracts, compared to $103.98 and $107.0 per barrel of oil and $4.22 and $3.89 per Mcf of natural gas, in the three and six months ended June 30, 2013, respectively. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

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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, 2014, our annual revenue would increase or decrease by approximately $12.2 million for each $10.00 per barrel change in oil prices and $8.5 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging. Based on our production for the six month ended June 30, 2013, our revenues would have increased or decreased by approximately $16.1 million for each $10.00 per barrel change in oil prices and $14.1 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, 2014, the fair value of our commodity derivatives included in our consolidated balance sheets represent a net current liability of $8.1 million. At December 31, 2013, the fair value of our commodity derivatives was approximately $8.5 million and $0.3 million, which were recorded as current liabilities and long-term liabilities, respectively. For the three and six months ended June 30, 2014, we realized net decrease in oil and natural gas revenues related to hedging transactions of approximately $4.4 million and $8.9 million, and (decreases) increases for the same periods in 2013 of ($0.2) and $0.2 million, respectively.

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As of June 30, 2014, we maintained the following commodity derivative contracts:

Remaining Contract Term: Oil	Contract Type	Notational Volume in Bbls/Month	NYMEX Strike Price
July 2014 - December 2014	Swap	15,000	$	65.00
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 2014 - July 2014	Swap	29,944	$	87.85
August 2014 - August 2014	Swap	29,068	$	87.85
September 2014 - September 2014	Swap	23,498	$	87.85
October 2014 - October 2014	Swap	25,026	$	87.85
November 2014 - November 2014	Swap	20,000	$	87.85
December 2014 - December 2014	Swap	31,000	$	87.85
July 2014 - July 2014	Swap	30,279	$	100.72
August 2014 - August 2014	Swap	29,835	$	100.72
September 2014 - September 2014	Swap	32,336	$	100.72
October 2014 - October 2014	Swap	31,438	$	100.72
November 2014 - November 2014	Swap	30,808	$	100.72
December 2014 - December 2014	Swap	16,382	$	100.72

Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month	NYMEX Strike Price
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
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
July 2014 - July 2014	Swap	245,330	$	4.47
August 2014 - August 2014	Swap	223,294	$	4.47
September 2014 - September 2014	Swap	207,094	$	4.47
October 2014 - October 2014	Swap	202,612	$	4.47
November 2014 - November 2014	Swap	186,296	$	4.47
December 2014 - December 2014	Swap	219,770	$	4.47
January 2015 - January 2015	Swap	94,748	$	4.47
February 2015 - February 2015	Swap	104,401	$	4.47
March 2015 - March 2015	Swap	105,796	$	4.47

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

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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 $16.4 million at June 30, 2014 and $17.0 million at December 31, 2013. 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 $23.1 million at June 30, 2014 and $35.2 million at December 31, 2013. We also have credit risk associated with our financially settled crude oil and natural gas swaps. As of June 30, 2014, 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.

Item 4. Controls and Procedures

The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the U.S. Securities and Exchange Commission, and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

As required by Rule 15d-15(b) under the Exchange Act, management annually reviews our accounting policies and practices, and as a result of such review, identified it had an ineffective financial reporting process and inconsistent review of certain routine accrual calculations and journal entries. As a result of these material weaknesses (as further discussed below), our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures as of June 30, 2014 were not effective at a reasonable level of assurance, based on the evaluation of these controls and procedures required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act. Notwithstanding the material weaknesses further discussed below, our Chief Executive Officer and Chief Financial Officer believe that the financial statements included in this report fairly present in all material respects (and in accordance with U.S. generally accepted accounting principles) our financial condition, results of operations and cash flows for the periods presented.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as that term is defined by Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control over financial reporting is designed under the supervision of our Chief Executive Officer and Chief Financial Officer in order to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of the changes within the organization and internal reporting.

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal controls over financial reporting pursuant to Rule 13a-15(c) under the Securities Exchange Act as of the end of the period covered by the 2013 Form 10-K. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management evaluated the effectiveness of our internal control over financial reporting as of June 30, 2014. In making this evaluation, management used the criteria established in 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In connection with such evaluation, our management identified material weaknesses in our control environment based on the criteria established in the 1992 Internal Control-Integrated Framework issued by the COSO. A material weakness is a control deficiency, or a combination of control

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deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements will not be prevented or detected.

The material weaknesses identified were related to our continued lack of sufficient control over financial accounting and reporting processes, specifically our inconsistent review of certain routine accrual calculations and journal entries, whereas in prior year, the matter related to accounting for non-routine and non-systematic transactions. Significant turnover and reduction in force in late 2013 and early 2014 caused the above-mentioned control deficiencies and resulted in the recording of certain adjustments prior to the issuance of our consolidated financial statements included in the 2013 Form 10-K. Because of these material weaknesses, management has concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2013.

Remediation of a Material Weakness

As discussed in our 2012 Form 10-K, our management concluded that our internal control over financial reporting was not effective as of December 31, 2012, as a result of a material weakness related to our lack of a sufficient control over our financial accounting and reporting processes regarding the accounting for non-routine and non-systematic transactions. As of December 31, 2012, management concluded that our control over the selection and application of our accounting policies related to non-routine and non-systematic transactions were ineffective to ensure that such transactions were recorded in accordance with U.S. generally accepted accounting principles. Specifically, the updated asset portion of the revised estimate of our asset retirement obligations were not included in the impairment computation of Net Book Value. We began implementing certain measures in 2013 to address this material weakness and continued to develop remediation plans and implemented additional measures throughout the remainder of 2013 and through the filing of the Form 10-K, including the appointment our Chief Financial Officer in January 2014, assessing the adequacy of processes and procedures underlying the specific areas discussed above, expanding and strengthening our controls surrounding the accounting for non-routine and non-systematic transactions and strengthening our policies, procedures and controls surrounding accrued expenses ensuring cooperation and coordination with departments outside of the accounting department.

The Company believes that the steps described above have enhanced the overall effectiveness of our internal control over financial reporting and remediated the previously identified material weakness.

Changes in Internal Control Over Financial Reporting.

As a result of the material weaknesses identified during the period covered by this Form 10-Q, management has implemented and will continue to implement changes to our internal controls that are both organizational and process-focused in an effort to improve the control environment, including as it relates to our application of accounting principles regarding our financial reporting process and review and approval of certain routine transactions. The changes to our control environment through the date of this Form 10-Q include, among others:

• Appointment of our Chief Financial Officer in January 2014;

• Re-evaluation of key processes that support our financial reporting function;

• Changes in certain process owners due to turnover and reduction in force.

We will continue our efforts to improve our control environment and to focus on improving our processes and systems to help ensure that our financial reporting, operational and business requirements are met in a timely manner going forward.

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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.

Regulatory Investigation and Audit. On November 4, 2013, BSEE issued its investigative report (the “BSEE Panel Report 2013-002”) on the West Delta 32 Incident. The report recommends that contractors Wood Group Production Service Network, Grand Isle Shipyard, and Compass Engineering Consultants, as well as Black Elk Energy be issued the following types of Incidents of Non-Compliance: G-110, G-112, G-116, G-303, G-310, G-311, G-312, and E-100. The report also recommends that contractor Wood Group Production Service Network and Black Elk Energy be issued the additional following types of Incidents of Non-Compliance: G-309 and G-317. The report states that BSEE will issue Incidents of Non-Compliance based upon evidence contained in the report and/or other relevant evidence. No Incidents of Non-Compliance have been issued yet, and Black Elk Energy has and will continue to fully cooperate with BSEE. Black Elk Energy will be carefully reviewing the BSEE Panel Report 2013-002 over the coming weeks.

On October 15, 2013, the Department of Justice, U.S. Attorney’s Office issued a subpoena pertaining to all physical evidence collected and maintained by Black Elk Energy and ABS Consulting as part the investigation of the WD-32 platform incident. . Further, on March 25, 2014, a second subpoena was issued by the U.S. Attorney’s Office requesting records and documents for specific time periods still part of their investigation of the WD-32 incident. 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 explosion and fire that occurred on our West Delta 32-E platform on November 16, 2012. 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

    In a meeting held at the BSEE Regional Office on October 30, 2013, BEEOO shared with BSEE representatives that implementation of corrective actions (18 elements and 58 tasks) associated with the Performance Improvement Plan ("PIP") has been 100% completed. Other essential work control processes such as our 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, National Pollutant Discharge Elimination System ("NPDES"), Job Safety Analysis ("JSA") and Stop Work Authority ("SWA") will be ongoing and has been incorporated into our training matrix.

On May 22, 2014, we received a letter from BSEE expressing that BEOO completed all the items and elements described in our Performance Improvement Plan. The last remaining task list item is to notify the Lake Charles District upon completion of the Vermilion Block 369 A platform blasting and painting operations. We plan to meet this remaining task list. BSEE recognizes that BEOO has made safety enhancements and implemented changes to our oversight processes on our operated platforms. We plan to continue with cultivating a safety environment and effort to mitigate risks in all operations as required by statute and regulation.

Additionally, BSEE will continue to regularly inspect our facilities and conduct compliance follow-up inspections to

confirm correction of Noncompliance issued since the beginning of 2014.

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On June 5, 2014, BEEOO notified BSEE Lake Charles District of the completion of the last remaining item on the

Performance Improvement Plan, i.e. Vermilion Block 369 platform blasting and painting operations, on June 4, 2014.

Civil Litigation. As of August 14, 2014, several civil lawsuits have been filed as a result of the West Delta 32 Incident. The lawsuits that were filed in Texas have been transferred to the United States District Court for the Eastern District of Louisiana, and all cases have been consolidated for discovery purposes in that Court. The first plaintiff’s case will be tried in either December of 2014 or January of 2015. All civil cases filed as a result of the West Delta 32 Incident are being defended by insurance defense counsel. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

As previously reported, six investors in Black Elk Energy, LLC (“BEE”) filed a purported derivative complaint on behalf of BEE in the Supreme Court of the State of New York, County of New York, against the Company, John Hoffman, Iron Island Technologies Inc., and various entities and individuals associated with the Company’s majority unit owner (the “Platinum Defendants”). The lawsuit seeks unspecified damages allegedly arising from (1) the dilution of BEE’s ownership interest in the Company through various financing transactions with the Platinum Defendants and the issuance of membership units under management and employee incentive programs; and (2) the alleged mismanagement of the Company in connection with certain alleged safety violations and the West Delta 32 Incident. We believe there are strong defenses to the claims asserted in the lawsuit, and the Company intends to defend the case vigorously. On or about September 24, 2013, Plaintiffs filed a motion for a preliminary injunction to restrain a portion of the proceeds of the Company’s proposed sale of certain oil fields in the Gulf of Mexico. The Court denied the motion on November 15, 2013. On or about November 20, 2013, we filed a motion to dismiss the complaint in its entirety, inter alia, on the grounds that (i) the claims fail to state a cause of action; (ii) the claims are refuted by documentary evidence; (iii) plaintiffs, who are not members of the Company, lack standing to assert a claim for mismanagement of the Company; and (iv) certain claims are barred by the statute of limitations. The motion is now fully briefed. Discovery is at an early stage, with the parties beginning to make rolling document productions.

The arbitrations cases involving GIS and Black Elk for unpaid invoices for services and materials provided by GIS(the “Invoice Arbitration”) is scheduled for hearing before a single arbitrator on December 1, 2014.The arbitration case for damages to the West Delta 32 Platform (the “Platform Arbitration”) is scheduled for hearing before a three-arbitrator panel on May 12, 2015. The arbitration proceeding initiated by Black Elk against Compass Engineering & Consultants, LLC for damages arising from the explosion of the WD-32 Platform has been abated pending resolution of Compass’ separate lawsuit filed in the United States District for the Western District of Louisiana seeking a declaration that it was not subjected to arbitration.

On April 16, 2014, Vistar Oil Texas LLC (“Vistar”) filed a petition against Black Elk in Harris County District Court. This suit alleges that Black Elk breached an Acquisition and Participation Agreement and a Joint Operating Agreement between the parties, primarily by failing to provide Vistar with the funds required to bring several wells into operation in Wilson County, Texas. Vistar alleges damages of approximately $6,500,000, certain lease acquisition costs and promissory note payments required to cover liens placed on the wells. Vistar further alleges that Black Elk is in breach by refusing to provide approximately $10,350,000 to Vistar to acquire additional property. This case has just begun discovery. We believe we have strong potential defenses and counterclaims, and intend to defend ourselves vigorously.

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 2013 Form 10-K and the risk factor set forth below. The risks described in the 2013 Form 10-K and below 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 2013 Form 10-K. We may experience additional risks and uncertainties not currently known to us, or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial

condition, cash flows and results of operations.

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We may not be able to generate sufficient cash flow to meet our debt service obligations.

The oil and gas properties to be sold in the Renaissance Sale represent a significant amount of our cash flow, proved reserves and production. Our ability to make payments on the Notes and to fund planned capital expenditures will depend on our ability to generate cash in the future. We cannot assure you that our business will generate sufficient cash flow from operations to service the Notes that are not purchased pursuant to the tender offer for the Notes, or that future borrowings will be available to us in an amount sufficient to enable us to make payments on such Notes or to fund our other capital needs. If our business does not generate sufficient cash flow from operations to service the Notes, we may be required to:

• refinance all or a portion of the Notes;

• obtain additional financing;

• sell some of our assets or operations; reduce or delay capital expenditures, research and development efforts and acquisitions; or

• revise or delay our strategic plans.

However, we cannot assure you that we would be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that implementing any such alternative financing plans would allow us to meet our payment obligations under the Notes. Our inability to generate sufficient cash flow to satisfy our payment obligations under the Notes or to obtain alternative financings, could materially and adversely affect our business, financial condition, results of operations and prospects.

If we default on the remaining Notes, holders of the Notes will be secured only to the extent of the value of the assets underlying their security interest. To prevent foreclosure, we may be motivated to commence voluntary bankruptcy proceedings or holders of Notes or various other interested persons may be motivated to institute bankruptcy proceedings against us. The commencement of such bankruptcy proceedings would expose the holders to additional risks, including additional restrictions on exercising rights against collateral. To the extent that the claims of the holders exceed the value of the assets securing the Notes and other liabilities, those claims will rank equally with the claims of the holders of any outstanding senior unsecured indebtedness. As a result, if the value of the assets pledged as security for the Notes and other liabilities is less than the value of the claims of the holders and other liabilities, those claims may not be satisfied in full before the claims of our unsecured creditors are paid.

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Item 6. Exhibits

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

Form 10-Q.

Exhibit Number	Description
3.1	Certificate of Formation of Black Elk Energy Offshore Operations, LLC, dated as of November 20, 2007 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011, 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, 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, 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, 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, File No. 333-174226).
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, File No. 333-174226).
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, File No. 333-174226).
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, File No. 333-174226).
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, File No. 333-174226).

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Exhibit Number	Description
*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.

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

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SIGNATURES

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

		BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC (Registrant)
Date:	August 14, 2014	By:	/s/ Jeff Shulse
			Jeff Shulse
			Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

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EXHIBIT INDEX

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

Form 10-Q.

Exhibit Number	Description
3.1	Certificate of Formation of Black Elk Energy Offshore Operations, LLC, dated as of November 20, 2007 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011, 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, 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, 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, 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, File No. 333-174226).
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, File No. 333-174226).
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, File No. 333-174226).
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, File No. 333-174226).
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, File No. 333-174226).

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*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.

§ 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