2013.09.30-10Q

10-Q 1 a20130930-10q.htm 10-Q 2013.09.30-10Q

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 September 30, 2013



¨	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 November 12, 2013, there were 1,361,300 Class A Units, 114,277,308.5 Class B Units, 12,031,250 Class C Units and 104,988,929 Class E Units issued and outstanding.

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2013

TABLE OF CONTENTS



		Page
Part I. Financial Information

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	1

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012	2

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012	3

	Notes to Consolidated Financial Statements	4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37

Item 4.	Controls and Procedures	40

Part II. Other Information

Item 1.	Legal Proceedings	41

Item 1A.	Risk Factors	42

Item 5.	Other Information	43

Item 6.	Exhibits	44

Signatures		46

Exhibit Index		47

(i)

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)



	September 30, 2013			December 31, 2012
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,686		$	1,383
Restricted cash	694			—
Accounts receivable, net of allowance for doubtful accounts of $817 at September 30, 2013 and $509 at December 31, 2012	60,361			46,553
Accounts receivable - insurance recovery	254			3,100
Due from affiliates	273			347
Prepaid expenses and other current assets	11,092			27,972
Current portion of escrow for abandonment costs	4,323			—
Derivative assets	—			2,408
TOTAL CURRENT ASSETS	83,683			81,763
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $265,893 and $191,326 at September 30, 2013 and December 31, 2012, respectively	234,918			260,012
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $4,792 and $1,717 at September 30, 2013 and December 31, 2012, respectively	5,334			1,968
OTHER ASSETS
Debt issue costs, net	1,889			3,230
Asset retirement obligation escrow receivable	20,348			20,348
Escrow for abandonment costs, net of current portion	234,334			215,263
Other assets	7,068			7,880
TOTAL OTHER ASSETS	263,639			246,721
TOTAL ASSETS	$	587,574		$	590,464
LIABILITIES AND MEMBERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	193,419		$	108,736
Derivative liabilities	7,523			—
Asset retirement obligations	32,124			41,572
Current portion of debt and notes payable	243			3,552
TOTAL CURRENT LIABILITIES	233,309			153,860
LONG-TERM LIABILITIES
Gas imbalance payable	2,147			2,521
Dividends payable	—			12,408
Derivative liabilities	1,149			5,091
Asset retirement obligations, net of current portion	270,762			303,933
Debt, net of current portion, net of unamortized discount of $686 and $882 at September 30, 2013 and December 31, 2012, respectively	184,367			201,118
TOTAL LONG-TERM LIABILITIES	458,425			525,071
TOTAL LIABILITIES	691,734			678,931
CLASS E AND CLASS D PREFERRED UNITS	104,989			30,000
COMMITMENTS AND CONTINGENCIES
MEMBERS’ DEFICIT	(209,149		)	(118,467		)
TOTAL LIABILITIES AND MEMBERS’ DEFICIT	$	587,574		$	590,464

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

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUES:
Oil sales	$	50,479		$	50,721		$	136,415		$	165,441
Natural gas sales	12,600			13,289			40,046			36,754
Plant product sales	1,457			2,876			5,831			11,079
Realized (loss) gain on derivative financial instruments	(2,725		)	3,284			(2,573		)	11,189
Unrealized (loss) gain on derivative financial instruments	(5,143		)	(16,129		)	(5,989		)	7,375
Other revenues	7,089			3,084			16,389			8,062
TOTAL REVENUES	63,757			57,125			190,119			239,900
OPERATING EXPENSES:
Lease operating	50,995			43,840			141,168			131,055
Production taxes	173			192			489			744
Workover	1,028			4,395			7,312			10,485
Exploration	—			311			—			1,249
Depreciation, depletion and amortization	10,027			12,302			32,727			36,546
Impairment of oil and gas properties	402			3,681			55,779			6,992
General and administrative	9,621			8,301			28,250			20,668
Gain on involuntary conversion of asset	(7,194		)	—			(17,827		)	—
Accretion of asset retirement obligations	4,458			9,256			19,551			27,228
Loss (gain) on sale of assets	424			—			(35,367		)	120
Other operating expenses	2,704			—			5,117			—
TOTAL OPERATING EXPENSES	72,638			82,278			237,199			235,087
(LOSS) INCOME FROM OPERATIONS	(8,881		)	(25,153		)	(47,080		)	4,813
OTHER INCOME (EXPENSE):
Interest income	30			11			81			305
Miscellaneous expense	(2,674		)	(919		)	(7,620		)	(2,408		)
Interest expense	(6,890		)	(6,514		)	(19,526		)	(19,422		)
TOTAL OTHER EXPENSE, NET	(9,534		)	(7,422		)	(27,065		)	(21,525		)
NET LOSS	(18,415		)	(32,575		)	(74,145		)	(16,712		)
LESS: PREFERRED UNIT DIVIDENDS	4,755			2,232			12,581			5,976
NET LOSS ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	(23,170	)	$	(34,807	)	$	(86,726	)	$	(22,688	)

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

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)



	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(74,145	)	$	(16,712	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	32,727			36,546
Impairment of oil and gas properties	55,779			6,992
Accretion of asset retirement obligations	19,551			27,228
Amortization of debt issue costs	4,595			3,455
Accretion of debt discount	195			171
Unrealized loss (gain) on derivative financial instruments	5,989			(7,375		)
(Gain) loss on sale of assets	(35,367		)	120
Provision on doubtful accounts	308			—
Gain on involuntary conversion of assets	(17,827		)	—
Changes in operating assets and liabilities:
Accounts receivable	(13,086		)	10,514
Due from affiliates, net	74			(1		)
Prepaid expenses and other assets	16,440			(6,920		)
Other assets	464			—
Accounts payable and accrued liabilities	74,560			2,737
Gas imbalance	(16		)	896
Settlement of asset retirement obligations	(41,512		)	(13,623		)
NET CASH PROVIDED BY OPERATING ACTIVITIES	28,729			44,028
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	(112,719		)	(18,153		)
Acquisition of oil and gas properties	(3,250		)	(3,454		)
Sale of oil and gas properties	65,741			(120		)
Additions to property and equipment	(683		)	(252		)
Cash assumed in consolidation of Freedom Well Services, LLC	473			—
Proceeds received from insurance recovery	23,837			—
Deposits	(9		)	(272		)
Restricted cash	(694		)	—
Escrow payments, net	(23,394		)	(38,878		)
NET CASH USED IN INVESTING ACTIVITIES	(50,698		)	(61,129		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on short term notes	348			17,644
Payments on short term notes	(3,827		)	(12,940		)
Borrowing on bank debt	23,168			145,000
Payments on bank debt	(40,168		)	(112,500		)
Debt issuance costs	(2,249		)	(3,022		)
Contributions from members	50,000			—
Distributions to members	—			(16,694		)
NET CASH PROVIDED BY FINANCING ACTIVITIES	27,272			17,488
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,303			387
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD	1,383			17,260
CASH AND CASH EQUIVALENTS - END OF PERIOD	$	6,686		$	17,647
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	11,773		$	12,603
NONCASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations relieved due to sale of properties	$	(22,999	)	$	—
Increase in asset retirement due to revaluation	$	2,341		$	—
Paid-in-kind dividends on preferred equity and accrued distributions to members	$	12,581		$	5,976

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

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(Unaudited)

NOTE 1—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, 2012 (the “2012 Form 10-K”).

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

Principles of Consolidation: The consolidated financial statements include the accounts of Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries, Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corp. Effective January 1, 2013, in accordance with accounting guidelines for consolidation of variable interest entities, we consolidated Freedom Well Services, LLC (“FWS”), as we determined that we are the primary beneficiary of FWS and will have the power to direct the activities of FWS. All material intercompany accounts and transactions have been eliminated in consolidation.

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

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

NOTE 2—LIQUIDITY RISKS AND UNCERTAINTIES

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $(149.6) million at September 30, 2013. The combination of restricted credit availability, lower production since the fourth quarter of 2012, our drilling program, settlement of our plugging and abandonment ("P&A") liabilities and additional collateral requirements related to the surety bonds that secure our P&A obligations led to significant reductions in our working capital in the fourth quarter of 2012 and the first nine months of 2013. To increase liquidity, we stretched accounts payable, aggressively pursued accounts receivable and sold assets. We continue to optimize our production portfolio and recommenced our drilling program in the fourth quarter of 2012, which is substantially complete for 2013. We have completed six operated wells and two non-operated wells in 2013. We expect to drill or complete two non-operated wells during the fourth quarter of 2013. To fund our drilling programs and operations, we expect to continue to raise additional capital over the next several years. To improve our access to funding, 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 Agreement, dated as of December 24, 2010 (the “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 our majority owner, Platinum Partners Value Arbitrage Fund L.P. Also, we are evaluating additional potential asset sales of core and non-core assets to optimize our portfolio and normalize the age of our accounts payable. On March 26, 2013, we sold four producing fields to Renaissance Offshore, LLC ("Renaissance") for approximately $52.5 million subject to

normal adjustments. A portion of the proceeds from the sale were used to reduce the amount borrowed under the Credit Facility by $36 million and the remainder was used for general corporate purposes. Cash collateral securing surety bonds of approximately $9.0 million related to the sold properties were released and received in the third quarter of 2013. The remainder of the cash collateral securing surety bonds for the sold properties was used to increase the collateral with the surety companies relating to bonds that had previously been issued to satisfy the bonding and security requirements of the Bureau of Ocean Energy Management (“BOEM”). We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million subject to normal adjustments.

Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties, settlement of our P&A as well as providing collateral to secure our P&A obligations. As we plug and abandon certain fields and meet the various criteria related to the corresponding escrow accounts, we expect to release funds from the escrow accounts. Also, our letters of credit with Capital One are backed entirely by cash. We use letters of credit to back a portion of our surety bonds for P&A obligations.

On August 30, 2013, we entered into a Limited Waiver and Eleventh Amendment to our Credit Facility to (1) obtain waivers related to our financial covenants for the third and fourth quarters of 2013, (2) extend the maturity date under the credit facility to January 1, 2015, (3) increase the Applicable Margin under the Credit Facility by one percent (for a total increase of two percent when combined with the one percent increase pursuant to the Eighth Amendment), (4) maintain the borrowing base at $25 million, subject to the right of Resource Value Group LLC to require the Administrative Agent to increase the borrowing base up to a maximum of $50 million, and (5) waive our right and the right of the Lenders to request or obtain a borrowing base redetermination prior to the first scheduled redetermination date in 2014. The borrowing base under the Credit Facility was increased to $35 million on September 30, 2013 and as of that date we had $35 million outstanding. Subsequently, the borrowing base was increased to $47 million on October 15, 2013. As of November 14, 2013, we had $45 million drawn on the Credit Facility.

As of September 30, 2013, we were in compliance with all covenants under the Indenture. We believe anticipated capital expenditures in 2013 will exceed the amount provided for in a covenant regarding maximum capital expenditures. However, the Indenture also provides that we may use proceeds from the sale of assets for capital expenditures that we believe is not limited by the previously referenced capital expenditure covenant. In the event our interpretation of the Indenture is not upheld or if our cash proceeds from the sale of assets are not sufficient to reduce our capital expenditures to a level that makes us compliant with the maximum capital expenditure covenant, we have the option under the Indenture to redeem the 13.75% Senior Secured Notes due 2015 (the "Notes"), beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes; however, there can be no assurance that we will have sufficient funds to do so. We also have the option to solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the Indenture, the Indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the Indenture covenant could also result in a cross-default under our credit facility.

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

Our capital budget may be adjusted in the future as business conditions warrant and the ultimate amount of capital we expend may fluctuate materially based on market conditions and the success of our drilling program as the year progresses. The amount, timing and allocation of capital expenditures are largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. Our planned operations for the remainder of 2013 reflect our expectations for production based on actual production history and new production expected to be brought online, the continuation of commodity prices near current levels and the higher cost of servicing our additional financing and other obligations.

material adverse effect on our financial position, results of operation and cash flows. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through other financing sources; however, there is no assurance that we will be able to do so in the future if required to meet any short-term liquidity needs.

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

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

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

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

NOTE 3—OIL AND GAS PROPERTIES

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



	September 30, 2013			December 31, 2012
	(Unaudited)
	(in thousands)
Proved properties	$	500,811		$	451,338
Accumulated depreciation, depletion, amortization and impairment	(265,893		)	(191,326		)
Oil and gas properties, net	$	234,918		$	260,012

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



	(in thousands)
Balance at December 31, 2012	$	345,505
Revaluation of liability	2,341
Liabilities relieved due to sale of properties	(22,999		)
Liabilities settled	(41,512		)
Accretion expense	19,551
Balance at September 30, 2013	$	302,886
Less: current portion	(32,124		)
Total Long-Term Asset Retirement Obligations	$	270,762

NOTE 4—ACQUISITIONS AND DIVESTITURES

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

NOTE 5—DERIVATIVE INSTRUMENTS

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

At September 30, 2013, 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)
10/13 - 10/13	27,750	$	96.90	$	(140	)	$	(140	)	104,000	$	4.60	$	114		$	114		$	(26	)	$	(26	)
11/13 - 11/13	26,800	96.90		(121		)	(121		)	104,000	4.60		$	106		106			(15		)	(15		)
12/13 - 12/13	27,750	96.90		(101		)	(101		)	104,000	4.60		88			88			(13		)	(13		)
1/14 - 2/14	19,000	96.90		(84		)	(84		)	82,000	4.60		120			120			36			36
10/13 - 10/13	3,259	100.80		(4		)	(4		)	91,166	4.94		132			132			128			128
11/13 - 11/13	—	—		—			—			64,926	4.94		88			88			88			88
12/13 - 12/13	10,042	100.80		1			1			119,462	4.94		141			141			142			142
1/14 - 5/14	10,083	100.80		139			139			129,960	4.94		694			694			833			833
6/14 - 6/14	—	—		—			—			129,960	4.94		133			133			133			133
10/13 - 12/13	19,750	85.90		(905		)	(905		)	47,000	5.00		196			196			(709		)	(709		)
1/14 - 12/14	15,000	65.00		(4,947		)	(4,947		)	—	—		—			—			(4,947		)	(4,947		)
10/13 - 10/13	28,006	88.80		(368		)	(368		)	34,551	4.09		20			20			(348		)	(348		)
11/13 - 11/13	31,605	88.80		(395		)	(395		)	28,939	4.09		15			15			(380		)	(380		)
12/13 - 12/13	38,743	88.80		(448		)	(448		)	37,906	4.09		13			13			(435		)	(435		)
1/14 - 1/14	4,723	88.80		(49		)	(49		)	43,347	4.09		11			11			(38		)	(38		)
2/14 - 2/14	13,313	88.80		(126		)	(126		)	32,636	4.09		8			8			(118		)	(118		)
3/14 - 3/14	8,413	88.80		(71		)	(71		)	46,764	4.09		12			12			(59		)	(59		)
4/14 - 4/14	12,473	88.80		(95		)	(95		)	41,253	4.09		13			13			(82		)	(82		)
5/14 - 5/14	11,793	88.80		(79		)	(79		)	40,391	4.09		11			11			(68		)	(68		)
6/14 - 6/14	15,546	88.80		(92		)	(92		)	20,112	4.09		5			5			(87		)	(87		)
7/14 - 7/14	11,845	88.80		(62		)	(62		)	39,283	4.09		9			9			(53		)	(53		)
8/14 - 8/14	13,165	88.80		(61		)	(61		)	34,246	4.09		7			7			(54		)	(54		)
9/14 - 9/14	16,235	88.80		(66		)	(66		)	29,753	4.09		6			6			(60		)	(60		)
10/14 - 10/14	15,605	88.80		(55		)	(55		)	28,635	4.09		5			5			(50		)	(50		)
11/14 - 11/14	18,525	88.80		(57		)	(57		)	27,081	4.09		3			3			(54		)	(54		)
12/14 - 12/14	22,526	88.80		(56		)	(56		)	34,114	4.09		(1		)	(1		)	(57		)	(57		)
10/13 - 10/13	4,000	87.85		(56		)	(56		)	—	—		—			—			(56		)	(56		)
11/13 - 11/13	250	87.85		(3		)	(3		)	—	—		—			—			(3		)	(3		)
12/13 - 12/13	2,500	87.85		(31		)	(31		)	—	—		—			—			(31		)	(31		)
1/14 - 1/14	46,000	87.85		(523		)	(523		)	—	—		—			—			(523		)	(523		)
2/14 - 2/14	25,000	87.85		(259		)	(259		)	—	—		—			—			(259		)	(259		)
3/14 - 3/14	56,000	87.85		(524		)	(524		)	—	—		—			—			(524		)	(524		)
4/14 - 4/14	45,000	87.85		(382		)	(382		)	—	—		—			—			(382		)	(382		)
5/14 - 5/14	46,000	87.85		(349		)	(349		)	—	—		—			—			(349		)	(349		)
6/14 - 6/14	48,000	87.85		(326		)	(326		)	40,391	4.19		14			14			(312		)	(312		)
7/14 - 7/14	36,000	87.85		(219		)	(219		)	20,112	4.19		6			6			(213		)	(213		)
8/14 - 8/14	34,000	87.85		(186		)	(186		)	39,283	4.19		11			11			(175		)	(175		)
9/14 - 9/14	26,000	87.85		(128		)	(128		)	34,246	4.19		10			10			(118		)	(118		)
10/14 - 10/14	27,000	87.85		(118		)	(118		)	29,753	4.19		8			8			(110		)	(110		)
11/14 - 11/14	20,000	87.85		(78		)	(78		)	28,635	4.19		6			6			(72		)	(72		)
12/14 - 12/14	31,000	87.85		(101		)	(101		)	27,081	4.19		2			2			(99		)	(99		)
1/15 - 1/15	—	—		—			—			34,114	4.19		—			—			—			—
2/15 - 2/15	—	—		—			—			27,838	4.19		—			—			—			—
3/15 - 3/15	—	—		—			—			24,461	4.19		1			1			1			1
1/15 - 1/15	—	—		—			—			27,838	4.09		(3		)	(3		)	(3		)	(3		)
2/15 - 2/15	—	—		—			—			24,461	4.09		(2		)	(2		)	(2		)	(2		)
3/15 - 3/15	—	—		—			—			26,443	4.09		(1		)	(1		)	(1		)	(1		)
10/13 - 10/13	67,513	108.44		181			181			—	—		—			—			181			181
11/13 - 11/13	64,159	108.44		184			184			—	—		—			—			184			184
12/13 - 12/13	45,392	108.44		162			162			—	—		—			—			162			162
1/14 - 1/14	46,006	100.72		(142		)	(142		)	—	—		—			—			(142		)	(142		)
2/14 - 2/14	39,159	100.72		(88		)	(88		)	—	—		—			—			(88		)	(88		)
3/14 - 3/14	36,822	100.72		(55		)	(55		)	—	—		—			—			(55		)	(55		)
4/14 - 4/14	34,069	100.72		(25		)	(25		)	—	—		—			—			(25		)	(25		)
5/14 - 5/14	35,200	100.72		1			1			—	—		—			—			1			1
6/14 - 6/14	31,668	100.72		23			23			—	—		—			—			23			23
7/14 - 7/14	48,509	100.72		64			64			—	—		—			—			64			64
8/14 - 8/14	46,473	100.72		87			87			—	—		—			—			87			87
9/14 - 9/14	45,830	100.72		110			110			—	—		—			—			110			110
10/14 - 10/14	44,282	100.72		125			125			—	—		—			—			125			125
11/14 - 11/14	40,874	100.72		130			130			—	—		—			—			130			130
12/14 - 12/14	26,424	100.72		95			95			—	—		—			—			95			95
				$	(10,673	)	$	(10,673	)				$	2,001		$	2,001		$	(8,672	)	$	(8,672	)

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 September 30, 2013		Balance Sheet Location	Fair Value at September 30, 2013			Balance Sheet Location	Fair Value at September 30, 2013
Commodity Contracts	Derivative financial instruments			Derivative financial instruments				Derivative financial instruments
	Current	$	2,934	Current	$	(10,457	)	Current	$	(7,523	)
	Non-current	376		Non-current	(1,525		)	Non-current	(1,149		)
Total derivative instruments		$	3,310		$	(11,982	)		$	(8,672	)

	Asset Derivatives			Liability Derivatives				Asset (Liability) Derivatives Total
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at December 31, 2012		Balance Sheet Location	Fair Value at December 31, 2012			Balance Sheet Location	Fair Value at December 31, 2012
Commodity Contracts	Derivative financial instruments			Derivative financial instruments				Derivative financial instruments
	Current	$	6,808	Current	$	(4,400	)	Current	$	2,408
	Non-current	1,235		Non-current	(6,326		)	Non-current	(5,091		)
Total derivative instruments		$	8,043		$	(10,726	)		$	(2,683	)

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

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



Derivatives Not Designated as Hedging Instruments under Accounting Guidance		Three Months Ended September 30,						Nine Months Ended September 30,
	Statements of Operations Location	2013			2012			2013			2012
Commodity Contracts	Realized (loss) gain on derivative financial instruments	$	(2,725	)	$	3,284		$	(2,573	)	$	11,189
Commodity Contracts	Unrealized (loss) gain on derivative financial instruments	(5,143		)	(16,129		)	(5,989		)	7,375
Total derivative instruments		$	(7,868	)	$	(12,845	)	$	(8,562	)	$	18,564

NOTE 6—FAIR VALUE MEASUREMENTS

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


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


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


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

As required by accounting guidance for fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular

input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

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



	Fair Value Measurements at September 30, 2013 Using Fair Value Hierarchy
	Fair Value as of September 30, 2013			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	3,310		$	—	$	3,310		$	—
	$	3,310		$	—	$	3,310		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(11,982	)	$	—	$	(11,982	)	$	—
	$	(11,982	)	$	—	$	(11,982	)	$	—

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

At September 30, 2013 and December 31, 2012, management estimates that the derivative contracts had a fair value of $(8.7) million and $(2.7) million, respectively. We estimated the fair value of derivative instruments using internally-developed models that use as their basis readily observable market parameters.

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

As of September 30, 2013, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities approximated their carrying value due to their short-term nature. The estimated fair value of our debt was primarily based on quoted market prices as well as prices for similar debt based on recent market transactions. The fair value of debt at September 30, 2013 was $182.7 million.

Fair Value on a Non-Recurring Basis

Oil and gas properties with a carrying value of $290.7 million were written down to their fair value of $234.9 million, resulting in an impairment charge of $0.4 million and $55.8 million for the three and nine months ended September 30, 2013, respectively, which is recognized under “Impairments of oil and gas properties” in the consolidated statements of operations. As of September 30, 2012, oil and gas properties with a carrying value of $224.4 million were written down to their fair value of $217.4 million, resulting in an impairment charge of $3.7 million and $7.0 million for the three and nine months ended September 30, 2012, respectively. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

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

NOTE 7—DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:



	September 30, 2013			December 31, 2012
	(in thousands)
	(unaudited)
Senior Secured Revolving Credit Facility	$	35,000		$	52,000
13.75% Senior Secured Notes, net of discount	149,314			149,118
AFCO Credit Corporation-insurance note payable	—			3,552
Other debt	296			—
Total debt	184,610			204,670
Less: current portion	(243		)	(3,552		)
Total long-term debt	$	184,367		$	201,118

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. 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 the 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 our majority owner, Platinum Partners Value Arbitrage Fund L.P.

We have entered into various amendments to the Credit Facility and the Letter of Credit Facility. These amendments have, among other things, (1) changed our amount available for borrowing under the Credit Facility from $35 million to a current borrowing base of $47 million, (2) adjusted the commitments under the Letter of Credit Facility to a current level of approximately $66.6 million, (3) increased the applicable margin with respect to each ABR loan or Eurodollar loan outstanding by a total of 2%, (4) amended certain provisions governing our swap agreements, (5) updated the fees on the letters of credit to 2% on a go-forward basis, (6) updated the “change in control” definition, (7) amended the definition of debt included in the calculation of the covenants, (8) changed the maturity date from December 24, 2013 to January 1, 2015 on the Credit Facility and to June 22, 2014 on the Letter of Credit Facility, (9) added affirmative covenants to be furnished on a weekly basis including updated cash flow projections, updated accounts payable and accounts receivable schedules, and daily production reports for the week, (10) added an affirmative covenant that we would receive certain specified capital contributions from Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”) or entities designated by PPBE during the first quarter of 2013, (11) revised the definition of “Event of Default” to include non-compliance with new affirmative covenants and (12) restricted returns of capital to our unit holders or distributions of our property to our equity interest holders.

On August 30, 2013, we entered into a Limited Waiver and Eleventh Amendment to our Credit Facility (the "Eleventh Amendment") to (1) obtain waivers related to our financial covenants for the third and fourth quarters of 2013, (2) extend the maturity date under the credit facility to January 1, 2015, (3) increase the Applicable Margin under the Credit Facility by one percent (for a total increase of two percent when combined with the one percent increase pursuant to the Eighth Amendment), (4) maintain the borrowing base at $25 million, subject to the right of Resource Value Group LLC to require the Administrative Agent to increase the borrowing base up to a maximum of $50 million and (5) waive our right and the right of the Lenders to request or obtain a borrowing base redetermination prior to the first scheduled redetermination date in 2014. The borrowing base under the Credit Facility was increased to $35 million on September 30, 2013 and as of that date we had $35 million outstanding. Subsequently, the borrowing base was increased to $47 million on October 15, 2013. As of November 14, 2013, we had $45 million drawn on the Credit Facility.

As of September 30, 2013, letters of credit in the aggregate amount of $96.6 million were outstanding under the Letter of Credit Facility. We had $35.0 million in borrowings under the Credit Facility. As of November 14, 2013, we had $2.0 million available for additional borrowings under the Credit Facility.

A commitment fee of 0.5% per annum is computed based on the unused borrowing base and paid quarterly. For each of the three and nine months ended September 30, 2013, we recognized $4,125 in commitment fees, which have been included in

“Interest expense” on the consolidated statements of operations. A letter of credit fee is computed based on the same applicable margin used to determine the interest rate to Eurodollar loans times the stated face amount of each letter of credit.

The Credit Facility is secured by mortgages on at least 80% of the total value of our proved oil and gas reserves. The borrowing base is re-determined semi-annually on or around April 1^st and October 1^st of each year.

The Credit Facility requires us and our subsidiaries to maintain certain financial covenants. Specifically, we may not permit, in each case as calculated as of the end of each fiscal quarter, our total leverage ratio to be more than 2.5 to 1.0, our interest coverage ratio to be less than 3.0 to 1.0, or our payables restriction covenant, which does not allow accounts payable greater than 90 days old to exceed $6.0 million in the aggregate, excluding certain vendors (in each case as defined in our revolving Credit Facility). In addition, we and our subsidiaries are subject to various covenants, including, but not limited to, restrictions on our and our subsidiaries’ ability to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets subject to their security interests, pay dividends, make acquisitions, loans, advances or investments, sell or otherwise transfer assets, enter into transactions with affiliates or change our line of business. As of September 30, 2013, we were not in compliance with the total leverage ratio covenant, the hedging requirement covenant and the interest coverage ratio covenant. Our total leverage ratio was calculated to be 6.0 to 1.0, which was higher than the required maximum of 2.5 to 1.0. Our hedging requirement of our notional volumes exceeded 60% for the months of October and November 2013 by 21% and 13%, respectively, of the reasonably anticipated total volume of projected production from proved, developed, and producing oil and gas properties. Our interest coverage ratio covenant was calculated to be 1.2 to 1.0, which was lower than the minimum 3.0 to 1.0. Our payables restriction covenant was calculated to be $27.2 million which was higher than the maximum of $6.0 million. We received a limited waiver relating to such covenants in the Eleventh Amendment for only the fiscal quarters ended September 30, 2013 and December 31, 2013 as well as a limited waiver and amendment on our Letter of Credit Facility in the Limited Waiver, Tenth Amendment to Letter of Credit Facility Agreement (the "Waiver and Tenth Amendment") for the fiscal quarter ended September 30, 2013.

13.75% Senior Secured Notes

On November 23, 2010, we issued $150 million face value of 13.75% Notes discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under our prior revolving credit facility, to fund 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 September 30, 2013, the recorded value of the Notes was $149.3 million, which includes the unamortized discount of $0.7 million. We incurred underwriting and debt issue costs of $7.2 million, which have been capitalized and are being amortized over the life of the Notes.

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

We have the right to redeem the Notes under various circumstances. If we experience a change of control, the holders of the Notes may require us to repurchase the Notes at 101% of the principal amount thereof, plus accrued unpaid interest. We also have an optional redemption in which we may redeem up to 35% of the aggregate principal amount of the Notes at a price equal to 110.0% of the principal amount, plus accrued interest and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings until December 1, 2013. From December 1, 2013 until December 1, 2014, we may redeem some or all of the Notes at an initial redemption price equal to par value plus one-half the coupon which equals 106.875% plus accrued and unpaid interest to the date of the redemption. On or after December 1, 2014, we may redeem some or all of the Notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption.

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

The Notes require us to maintain certain financial covenants. Specifically, we may not permit our SEC PV-10 to consolidated leverage to be less than 1.4 to 1.0 as of the last day of each fiscal year. In addition, we and our subsidiaries are subject to various covenants, including restricted payments, incurrence of indebtedness and issuance of preferred stock, liens, dividends and other payments, merger, consolidation or sale of assets, transactions with affiliates, designation of restricted and

unrestricted subsidiaries, and a maximum limit for capital expenditures. Our limitation on capital expenditures was amended in conjunction with the Consent Solicitation on May 31, 2011 to 30% of consolidated earnings before interest expense, income taxes, DD&A, impairment of oil and gas properties, and exploration expense for any year thereafter. As of September 30, 2013, we were in compliance with all covenants under the Indenture. We believe anticipated capital expenditures in 2013 will exceed the amount provided for in a covenant regarding maximum capital expenditures. However, the Indenture also provides that we may use proceeds from the sale of assets for capital expenditures that we believe is not limited by the previously referenced capital expenditure covenant. In the event our interpretation of the Indenture is not upheld or if our cash proceeds from the sale of assets are not sufficient to reduce our capital expenditures to a level that makes us compliant with the maximum capital expenditure covenant, we have the option under the Indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes; however, there can be no assurance that we will have sufficient funds to do so. We also have the option to solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the Indenture, the Indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the Indenture covenant could also result in a cross-default under our credit facility.

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



Period Ending September 30,	(in thousands)
2014	$	243
2015	35,030
2016	150,023
	185,296
Unamortized discount on 13.75% Senior Secured Notes	(686		)
Total debt	$	184,610

NOTE 8-PREFERRED UNITS AND MEMBERS' DEFICIT

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 will receive a preferred return of 20% per annum, which will increase from and after March 25, 2014 to 36% per annum (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement). For the nine months ended September 30, 2013, we issued an additional amount of Class E Units of approximately 12.0 million as paid-in-kind dividends to the holders of Class E Units.

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.

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

West Delta 32

On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform (the “West Delta 32 Incident”). The investigation in regards to the West Delta 32 Incident has been concluded by BSEE. On November 4, 2013, BSEE issued its investigation 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.

At BSEE’s direction, we engaged an independent third-party auditor to audit our SEMS program. BSEE participated in the audit and after reviewing the results, it issued a letter to BEEOO stating that “BEEOO’s SEMS meets the intent of BSEE regulations and policies, provided that the Corrective Action Plan (“CAP”) is implemented in accordance with BEEOO’s SEMS Audit Report. We are currently providing regular updates on our CAP progress.

In August 2013, ABSG Consulting (“ABSG”), a third party investigator, concluded that on the day of the West Delta 32 Incident contractors were welding a flange on open piping leading to an oil tank that contained flammable vapors. The piping had not been isolated and made safe for welding activities as required by Black Elk Energy safe work practices. The ABSG report further found that flammable vapors in the piping ignited, and within seconds reached the three oil tanks. The welding work was performed under contract by Grand Isle Shipyard. At the time of the incident, the platform production was shut in and no oil was flowing to or through the platform.

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 BEEOO and ABSG Consulting as part of the investigation of the West Delta Incident.

As of November 12, 2013, several civil lawsuits have been filed as a result of the West Delta 32 Incident. The courts held a status conference ordering procedural matters to be filed on the court’s docket. All civil cases filed both in Texas and Louisiana 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.

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

27.01% of the sale proceeds are placed in an escrow account during the pendency of the litigation. The Judge dismissed the Temporary Restraining Order and set a hearing for the Motion for the Injunction. The court heard oral arguments on the preliminary injunction motion on October 31, 2013 and reserved decision; a ruling is expected later this month. The Company intends to file a motion to dismiss the complaint in its entirety for failure to state a cause of action and based on documentary evidence that refutes the claims.

On April 29, 2013, Grand Isle Shipyards, Inc. (“GIS”) sued BEEOO, Enviro Tech Systems, LLC, Wood Group USA, Inc., and Compass Engineering & Consultants, LLC in the United States District Court for the Eastern District of Louisiana for damages it alleged incurred in connection with the West Delta 32 Incident. GIS specifically sought damages for loss of property and equipment, expenses in the form of indemnity and medical benefits paid to or on behalf of its employees, and for unpaid invoices in connection with the work it performed at West Delta 32. Upon motion by BEEOO, however, the court dismissed GIS’ lawsuit and ordered GIS and BEEOO to first attempt to resolve their claims through mediation, and if that is unsuccessful, then through binding arbitration, pursuant to and in accordance with the MSA. The mediation is scheduled on November 12, 2013. If that is unsuccessful, then the arbitration process will proceed.

Operating Leases

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

During 2012, we entered into two drilling unit contracts. One of the contracts was amended in June 2013 and was extended an additional 180 days to begin in January 2014. The second contract was for the duration of one drill well and was extended to include one additional drill well, which has now been completed. Additionally, we purchased leasehold in South Texas and drilled and completed one well in the third quarter of 2013.

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



Period Ending September 30,	(in thousands)
2014	$	31,860
2015	2,201
2016	2,029
2017	1,740
2018	1,577
Thereafter	3,476
	$	42,883

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 September 30, 2013, we have funded $16.4 million into the non-operating escrow account, leaving $14.8 million to be funded through May 1, 2017.

The obligations under the W&T Escrow Accounts are fully guaranteed by an affiliate of Platinum. W&T Offshore Inc. (“W&T”) has a first lien on the entirety of the W&T Escrow Accounts, and BP Corporation North America Inc. and Platinum are pari passu second lien holders. Once P&A obligations with respect to the interest in properties acquired from the W&T Acquisition have been fully satisfied, the lien on the W&T Escrow Accounts will be automatically extinguished. W&T also has a second priority lien with respect to the interest in properties acquired from the W&T Acquisition (with Platinum and BNP Paribas sharing a first priority lien), which lien will be released once the W&T Escrow Accounts have been fully funded. On December 19, 2012, we entered into a Third Amendment to Purchase and Sale Agreement (the “Third Amendment”) with W&T. Pursuant to the Third Amendment, we caused performance bonds (the “ARGO Bonds”) in an aggregate amount of $32.6 million to be issued by Argonaut Insurance Company to W&T to guaranty our performance of certain plugging and abandonment obligations. Upon receipt of the ARGO Bonds, W&T (i) released its rights to any money held in an escrow account established to secure our performance of certain plugging and abandonment obligations with respect to the Operated Properties Escrow Account, (ii) released the security interest and deposit account control agreement formerly securing its rights in the Operated Properties Escrow Account and (iii) authorized the escrow agent to release such funds from the Operated Properties Escrow Account to or at our direction. In addition, we and W&T agreed that until the funding of an escrow account

established to our performance of certain plugging and abandonment obligations with respect to certain non-operated properties is complete, we may not obtain reductions of the ARGO Bonds under any circumstances without W&T’s consent.

Pursuant to the purchase agreement for the Maritech Acquisition, we are required to fund an escrow account (the “Maritech Escrow Account”), relating to the properties that were acquired, of $13.1 million to be used for future P&A costs that may be incurred on such properties. As of September 30, 2013, we have funded $11.3 million, leaving $1.8 million to be funded through February 2014.

In regards to the Merit Acquisition, we are required to establish an escrow account to secure the performance of our P&A obligations and other indemnity obligations with respect to P&A and/or decommissioning of the acquired wells and facilities. We paid $33 million in surety bonds at closing and are required to, over time, deposit in the escrow account an amount equal to $60 million, which is to be paid in 30 equal monthly installments payable on the first day of each month commencing on June 1, 2011. As of September 30, 2013, we have funded $56.0 million, leaving $4.0 million to be funded through November 2013.

NOTE 10—GAIN ON INVOLUNTARY CONVERSION

High Island 443 A-2

The claim was approved and paid by insurance underwriters. We recorded a receivable of $3.1 million for reimbursement, after a deductible of $0.5 million, under our insurance policy at December 31, 2012 and received the funds during the first quarter of 2013. As of September 30, 2013, we recorded a receivable of $0.3 million for additional reimbursement and received these final funds in October 2013. The claim has been finalized. We received a total of approximately $24.1 million, net of the deductible, in cash for the claim during 2013.

NOTE 11—RELATED PARTY TRANSACTIONS

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

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. See Note 8.

On May 28, 2013, FWS entered into an equipment lease agreement with Pea and Eigh Company, LLC (“Pea and Eigh”), a related party of Platinum. The lease began on July 1, 2013 and is payable in monthly installments of approximately $35,000, maturing on December 31, 2013, with an option to purchase the equipment for $1.5 million. As of September 30, 2013, 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”.

In October 2010, Freedom Logistics LLC (“Freedom”) was formed by Platinum, our majority equity holder, and Freedom HHC Management, LLC, the members of which are Messrs. John Hoffman (our President and Chief Executive Officer) and David Cantu (a former employee), for the purpose of holding certain aircraft equipment, including two helicopters. On October 8, 2010, we guaranteed the loan that Freedom used to purchase two helicopters in the aggregate principal amount of $3.2 million. The loan was paid off in December 2012 in connection with the sale of Freedom. Before the sale, Freedom provided us with aircraft services, which were prepaid on a monthly basis. As of December 31, 2012, we had a receivable of $0.3 million from Freedom. The receivable was paid on February 26, 2013.

NOTE 12—SUBSEQUENT EVENTS

Option to Purchase Golden Gate Oil. On November 14, 2013, we entered into a Purchase Option Agreement with the owners of Golden Gate Oil LLC pursuant to which we have the option to purchase 100% of the equity of Golden Gate for an aggregate purchase price equal to $60 million plus the amount of any advances made to Golden Gate by its members after October 29, 2013 plus the principal, interest and fees outstanding under certain debt of Golden Gate. Golden Gate and its principal owner are affiliated with Platinum.

The Golden Gate Oil Project is located in the Santa Maria Oil Basin, Santa Barbara, California. The Project is an in-fill horizontal opportunity, targeting the highly fractured Monterrey Shale oil reservoir.

Letter of Credit Facility Amendment. 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.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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


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


•	Future financial and operating performance and results;


•	Business strategy and budgets;


•	Market prices;


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


•	Technology;


•	Financial strategy;


•	Amount, nature and timing of capital expenditures;


•	Drilling of wells and the anticipated results thereof;


•	Oil and natural gas reserves;


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


•	Competition and government regulations;


•	Operating costs and other expenses;


•	Cash flow and anticipated liquidity;


•	Prospect development;


•	Property acquisitions and sales; and


•	Plans, forecasts, objectives, expectations and intentions.

These forward-looking statements are based on our current expectations and assumptions about future events and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisition. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are described in “Item 1A. Risk Factors” in this Form 10-Q and our 2012 Form 10-K.

These factors include risks summarized below:


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


•	Oil and natural gas price volatility;


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


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


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


•	Cash flow and liquidity;


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


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


•	Geological concentration of our reserves;


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


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


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


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


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


•	Weather conditions;


•	Availability and cost of material and equipment;


•	Delays in anticipated drilling start-up dates;


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


•	Ability to find and retain skilled personnel;


•	Strength and financial resources of competitors;


•	Potential defects in title to our properties;


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


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


•	Environmental risks;


•	Changes in interest rates;


•	Developments in oil and natural gas-producing countries;


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


•	Possible referral to the Bureau of Ocean Energy Management to revoke our status as an operator on all of our existing facilities pursuant to a letter received from BSEE on November 21, 2012; and


•	Worldwide political and economic conditions.

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

Should one or more of the risks or uncertainties described in “Item 1A. Risk Factors” in this Form 10-Q and our 2012 Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statement.

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

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

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 September 30, 2013, we held an aggregate net interest in approximately 490,370 gross (239,190 net) acres under lease and had an interest in 1,059 gross wells, 268 of which are producing.

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

Black Elk Energy Offshore Operations, LLC and Black Elk Energy Land Operations, LLC were formed on November 20, 2007 as operating subsidiaries of Black Elk Energy, LLC. Black Elk Energy, LLC subsequently assigned its interests in Black Elk Energy Land Operations, LLC to Black Elk Energy Offshore Operations, LLC. Black Elk Energy Offshore Operations, LLC currently has three wholly owned domestic subsidiaries: (i) Black Elk Energy Land Operations, LLC, which is a guarantor under our Indenture, (ii) Black Elk Energy Finance Corp., which is the co-issuer of the Notes and (iii) Freedom Well Services, LLC. Neither Black Elk Energy Land Operations, LLC nor Black Elk Energy Finance Corp has any material assets or operations. Black Elk Energy, LLC owns a minority interest in Black Elk Energy Offshore Operations, LLC.

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

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

Our revenue, profitability and future growth rate depend significantly on factors beyond our control, such as economic, political and regulatory developments, and environmental hazards, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil

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

From time to time, we use derivative financial instruments to economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. Our average prices that reflect both the before and after effects of our realized commodity hedging transactions for the three and nine months ended September 30, 2013 and 2012 are shown in the table below.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Oil:
Average price before effects of hedges ($/Bbl)⁽¹⁾	$	110.41	$	102.92	$	108.24	$	107.93
Average price after effects of hedges ($/Bbl)	102.01		103.06		103.41		105.99
Average price differentials⁽²⁾	4.59		10.76		10.07		11.81

Gas:
Average price before effects of hedges ($/Mcf)⁽¹⁾	$	3.74	$	3.06	$	3.85	$	2.63
Average price after effects of hedges ($/Mcf)	4.07		3.80		4.18		3.64
Average price differentials⁽²⁾	0.19		0.18		0.16		0.09


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


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

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

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

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

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

Recent Events

Potential Sale of Class B Units

On September 16, 2013, we entered into a Subscription Agreement with Asiasons Capital Limited (“Asiasons”) for the sale of 9,960,159 of our Class B Units for an aggregate purchase price of approximately US$50 million (based on a fixed price for Asiasons ordinary shares of 1.1948 Singapore Dollars and a fixed exchange rate of one U.S. Dollar to 1.27 Singapore

Dollars). The Subscription Agreement provides that Asiasons will pay for the Class B Units by issuing 53,146,970 ordinary shares in Asiasons to us and will also issue an aggregate of 3,482,386 ordinary shares to Jett Capital Advisors LLC as a broker’s fee in connection with the transaction. The ordinary shares of Asiasons are listed on the Singapore Exchange Securities Trading Limited (SGX Symbol: 5ET).

The issuance of the Class B Units and the closing of the transaction are subject to customary closing conditions, including satisfactory completion by us and by Asiasons of financial, legal and operational due diligence on the other party, board approvals, accuracy of representations and warranties, and listing approval of the ordinary shares on the Singapore Exchange.

We have been informed that the Singapore Exchange has notified Asiasons that it does not have sufficient authority to issue the ordinary shares to us as contemplated by the Subscription Agreement. The Subscription Agreement has not been terminated, but the proposed sale of Class B Units on the terms set forth in the Subscription Agreement is unlikely to occur. We are engaged in discussions with Asiasons to determine whether the parties can reach agreement on the terms of a new investment.

Safety and Environmental Management Systems (“SEMS”) Audit

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

Phase I started with a request from M&H to provide SEMS Program Manual and all documents incorporated by reference. These documents were reviewed for compliance with the requirements of 30 CFR Part 250 Subpart S and API RP 75 (incorporated by reference). Phase 2 kicked off on February 13, 2013 with a review of preliminary findings from Phase 1 and an analysis of SEMS records and documentation to determine how effectively the SEMS was implemented. The Phase 3 Offshore Audit started on March 4, 2013 and covered 19 platforms across our Gulf of Mexico asset areas (East, Central, and West). The final audit phase was completed on March 13, 2013. The Audit Closeout Meeting occurred on March 25, 2013 on schedule with the plan submitted to BSEE. We submitted the Final Audit Report to BSEE on April 10, 2013. The Corrective Action Plan (“CAP”) was submitted to BSEE on April 11, 2013. We received a letter from BSEE on April 24, 2013 stating that the review was complete and that our SEMS meets the intent of the regulations and policies provided that the CAP is implemented in accordance with the SEMS Audit Report. On September 27, 2013 Black Elk advised BSEE that our SEMS CAP was complete.

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.

Based on the receipt of requested work and operation permits along with our interactions with BSEE and our corrective actions discussed above, we believe that we have improved our safety and compliance performance.

High Island 443 A-2

On September 27, 2012, an incident occurred on our High Island 443 A-2 ST well which required the closing of the blind/shear rams to properly shut in and maintain control of the well due to several days of unsuccessful attempts to repair a small hydrocarbon leak on a conductor riser. Additional surface diagnostics found the inner casing strings to be most likely compromised. On October 12, 2012, the BSEE advised us to plug and abandon the well. We have well control insurance and pursued reimbursement for this incident and the claim was approved. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drill are also insurance recoverable. We recorded a receivable of $3.1 million for reimbursement, after a deductible of $0.5 million, under our insurance policy at December 31, 2012 and received the funds during the first quarter of 2013. As of September 30, 2013, we recorded a receivable of $0.3 million for reimbursement and received these funds in October 2013. The claim has been finalized. We received a total of approximately $24.1 million, net of the deductible, in cash for the claim.

Capital Contributions

In the first quarter of 2013, we entered into contribution agreements with PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”) or entities designated by PPBE (together, the “Platinum Group”) pursuant to which we have issued 50 million additional Class E Units and 3.8 million additional Class B Units to the Platinum Group for an aggregate offering price of $50.0 million. In addition, we also agreed to issue an additional 43 million Class E Units in exchange for $30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class E Units will receive a preferred return of 20% per annum, which will increase from and after March 25, 2014 to 36% per annum (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement). For the nine months ended September 30, 2013, we issued an additional amount of Class E Units of approximately 12.0 million as paid-in-kind dividends to the holders of Class E Units.

Operating Agreement Amendment

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

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

Letter of Credit Facility Amendment and Credit Facility Amendments

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.

increase of two percent when combined with the one percent increase pursuant to the Eighth Amendment), (4) maintain the borrowing base at $25 million, subject to the right of Resource Value Group LLC to require the Administrative Agent to increase the borrowing base up to a maximum of $50 million, and (5) waive our right and the right of the Lenders to request or obtain a borrowing base redetermination prior to the first scheduled redetermination date in 2014. The borrowing base under the Credit Facility was increased to $35 million on September 30, 2013 and as of that date we had $35 million outstanding. Subsequently, the borrowing base was increased to $47 million on October 15, 2013. As of November 14, 2013, we had $45 million drawn on the Credit Facility.

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.

Drilling Update

We successfully completed seven wells and had one drilling rig on a non-operated property as of September 30, 2013. All of the completed wells encountered pay equal to or above our expectations. Our rig activity during the remainder of 2013 will be dependent on oil and gas prices. Accordingly, our rig count may increase or decrease.

Liquidity Risks and Uncertainties

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $(149.6) million at September 30, 2013. The combination of restricted credit availability, lower production since the fourth quarter of 2012, our drilling program, settlement of our plugging and abandonment ("P&A") liabilities and additional collateral requirements related to the surety bonds that secure our P&A obligations led to significant reductions in our working capital in the fourth quarter of 2012 and the first nine months of 2013. To increase liquidity, we stretched accounts payable, aggressively pursued accounts receivable and sold assets. We continue to optimize our production portfolio and recommenced our drilling program in the fourth quarter of 2012, which is substantially complete for 2013. We have completed six operated wells and two non-operated wells in 2013. We expect to drill or complete two non-operated wells during the fourth quarter of 2013. To fund our drilling programs and operations, we expect to continue to raise additional capital over the next several years. To improve our access to funding, 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 Agreement, dated as of December 24, 2010 (the “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 our majority owner, Platinum Partners Value Arbitrage Fund L.P. Also, we are evaluating additional potential asset sales of core and non-core assets to optimize our portfolio and normalize the age of our accounts payable. On March 26, 2013, we sold four producing fields to Renaissance Offshore, LLC for approximately $52.5 million subject to normal adjustments. A portion of the proceeds from the sale were used to reduce the amount borrowed under the Credit Facility by $36 million and the remainder has been and will be used for general corporate purposes. Cash collateral securing surety bonds of approximately $9.0 million related to the sold properties were released and received in the third quarter of 2013. The remainder of the cash collateral securing surety bonds for the sold properties was used to increase the collateral with the surety companies relating to bonds that had previously been issued to satisfy the bonding and security requirements of the BOEM. We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million subject to normal adjustments.

As of September 30, 2013, we were in compliance with all covenants under the Indenture. We believe anticipated capital expenditures in 2013 will exceed the amount provided for in a covenant regarding maximum capital expenditures. However, the Indenture also provides that we may use proceeds from the sale of assets for capital expenditures that we believe is not limited by the previously referenced capital expenditure covenant. In the event our interpretation of the Indenture is not upheld or if our cash proceeds from the sale of assets are not sufficient to reduce our capital expenditures to a level that makes us compliant with the maximum capital expenditure covenant, we have the option under the Indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes; however, there can be no assurance that we will have sufficient funds to do so. We also have the option to solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the Indenture, the Indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the Indenture covenant could also result in a cross-default under our credit facility.

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

prices or operating cost levels could have a material adverse effect on our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet our commitments as they come due.

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

How We Evaluate Our Operations

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

The following table contains certain financial and operational data for each of the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Average daily sales:
Oil (Bopd)	4,969			5,357			4,617			5,595
Natural gas (Mcfpd)	36,595			47,177			38,149			51,075
Plant products (Galpd)	16,484			34,206			24,397			38,900
Oil equivalents (Boepd)	11,461			14,034			11,556			15,033
Average realized prices⁽¹⁾:
Oil ($/Bbl)	$	102.01		$	103.06		$	103.41		$	105.99
Natural gas ($/Mcf)	4.07			3.80			4.18			3.64
Plant products ($/Gallon)	0.96			0.91			0.88			1.04
Oil equivalents ($/Boe)	58.62			54.35			56.97			54.49
Costs and Expenses:
Lease operating expense ($/Boe)	48.36			33.95			44.75			31.82
Production tax expense ($/Boe)	0.16			0.15			0.15			0.18
General and administrative expense ($/Boe)	9.12			6.43			8.95			5.02
Net loss (in thousands)	(18,415		)	(32,575		)	(74,145		)	(16,712		)
Adjusted EBITDA⁽²⁾ (in thousands)	9,126			17,233			25,722			70,943


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

(2)

Adjusted EBITDA is defined as net loss 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.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Net loss	$	(18,415	)	$	(32,575	)	$	(74,145	)	$	(16,712	)
Adjusted EBITDA	$	9,126		$	17,233		$	25,722		$	70,943
Reconciliation of Net loss to Adjusted EBITDA
Net loss	$	(18,415	)	$	(32,575	)	$	(74,145	)	$	(16,712	)
Interest expense, net	6,813			6,601			19,293			19,435
Surety and letter of credit fees	2,458			1,839			7,017			4,709
West Delta 32 costs	4,702			—			12,397			—
Unrealized loss (gain) on derivative instruments	5,143			16,129			5,989			(7,375		)
Accretion of asset retirement obligations	4,458			9,256			19,551			27,228
Depreciation, depletion and amortization	10,027			12,302			32,727			36,546
Impairment of oil and gas properties	402			3,681			55,779			6,992
Gain on involuntary conversion of assets	(7,194		)	—			(17,827		)	—
Provision for doubtful accounts	308			—			308			—
Loss (gain) on sale of assets	424			—			(35,367		)	120
Adjusted EBITDA	$	9,126		$	17,233		$	25,722		$	70,943

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



	Three Months Ended September 30, 2012											Nine Months Ended September 30, 2012
	2013			2012			Change			% Change		2013			2012			Change			% Change
PRODUCTION:
Oil (MBbl)	457			493			(36		)	(7	)%	1,260			1,533			(273		)	(18	)%
Natural gas (MMcf)	3,367			4,340			(973		)	(22	)%	10,415			13,995			(3,580		)	(26	)%
Plant products (MGal)	1,517			3,147			(1,630		)	(52	)%	6,660			10,659			(3,999		)	(38	)%
Total (MBoe)	1,054			1,291			(237		)	(18	)%	3,155			4,119			(964		)	(23	)%
REVENUES:
Oil sales	$	50,479		$	50,721		$	(242	)	—	%	$	136,415		$	165,441		$	(29,026	)	(18	)%
Natural gas sales	12,600			13,289			(689		)	(5	)%	40,046			36,754			3,292			9	%
Plant product sales and other revenue	1,457			2,876			(1,419		)	(49	)%	5,831			11,079			(5,248		)	(47	)%
Realized (loss) gain on derivative financial instruments	(2,725		)	3,284			(6,009		)	(183	)%	(2,573		)	11,189			(13,762		)	(123	)%
Unrealized (loss) gain on derivative financial instruments	(5,143		)	(16,129		)	10,986			(68	)%	(5,989		)	7,375			(13,364		)	(181	)%
Other revenues	7,089			3,084			4,005			130	%	16,389			8,062			8,327			103	%
TOTAL REVENUES	63,757			57,125			6,632			12	%	190,119			239,900			(49,781		)	(21	)%
OPERATING EXPENSES:
Lease operating	50,995			43,840			7,155			16	%	141,168			131,055			10,113			8	%
Production taxes	173			192			(19		)	(10	)%	489			744			(255		)	(34	)%
Workover	1,028			4,395			(3,367		)	(77	)%	7,312			10,485			(3,173		)	(30	)%
Exploration	—			311			(311		)	(100	)%	—			1,249			(1,249		)	(100	)%
Depreciation, depletion and amortization	10,027			12,302			(2,275		)	(18	)%	32,727			36,546			(3,819		)	(10	)%
Impairment of oil and gas properties	402			3,681			(3,279		)	(89	)%	55,779			6,992			48,787			698	%
General and administrative	9,621			8,301			1,320			16	%	28,250			20,668			7,582			37	%
Gain on involuntary conversion of asset	(7,194		)	—			(7,194		)	100%		(17,827		)	—			(17,827		)	100%
Accretion of asset retirement obligations	4,458			9,256			(4,798		)	(52	)%	19,551			27,228			(7,677		)	(28	)%
Loss (gain) on sale of assets	424			—			424			100%		(35,367		)	120			(35,487		)	(29,573	)%
Other operating expenses	2,704			—			2,704			100%		5,117			—			5,117			100%
TOTAL OPERATING EXPENSES	72,638			82,278			(9,640		)	(12	)%	237,199			235,087			2,112			1	%
(LOSS) INCOME FROM OPERATIONS	(8,881		)	(25,153		)	16,272			(65	)%	(47,080		)	4,813			(51,893		)	(1,078	)%
OTHER INCOME (EXPENSE):
Interest income	30			11			19			173	%	81			305			(224		)	(73	)%
Miscellaneous expense	(2,674		)	(919		)	(1,755		)	191	%	(7,620		)	(2,408		)	(5,212		)	216	%
Interest expense	(6,890		)	(6,514		)	(376		)	6	%	(19,526		)	(19,422		)	(104		)	1	%
TOTAL OTHER EXPENSE, NET	(9,534		)	(7,422		)	(2,112		)	28	%	(27,065		)	(21,525		)	(5,540		)	26	%
NET LOSS (INCOME)	$	(18,415	)	$	(32,575	)	$	14,160		(43	)%	$	(74,145	)	$	(16,712	)	$	(57,433	)	344	%

Production

Oil and natural gas production. Total oil, natural gas and plant product production of 1,054 MBoe and 3,155 MBoe decreased 237 MBoe, or 18%, and 964 MBoe, or 23%, respectively, during the three and nine months ended September 30, 2013 compared to the same periods in 2012 as a result of downtime in the fields requiring hot work, which was delayed due to the BSEE requirements for approval after the West Delta 32 incident, pipeline repairs, and the asset field sales to Renaissance on March 26, 2013 and July 31, 2013. The year-to-date variance was also a result of a longer winter weather season. Production volumes were 45% oil and natural gas liquids (“NGLs”) and 55% natural gas in the nine months ended September 30, 2013.

Revenues

Total revenues. Total revenues for the three and nine months ended September 30, 2013 of $63.8 million and $190.1 million increased $6.6 million, or 12%, and decreased $49.8 million, or 21%, respectively, over the comparable periods in 2012.

Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, increased $1.7 million, or 2%, and decreased $22.7 million, or 10%, respectively, for the three and nine months ended September 30, 2013 compared to

the same periods in 2012. The increase for the quarter was related to our consolidation of Freedom Well Services, LLC in 2013 and higher oil, gas and plant product prices partially offset by lower oil, gas, and plant product production. The year-to-date decrease was primarily a result of lower oil, gas and plant product production and lower plant product prices partially offset by higher oil and gas prices and the consolidation of Freedom Well Services, LLC.

We entered into certain oil and natural gas commodity derivative contracts in 2013 and 2012. We realized (losses) gains on these derivative contracts in the amounts of $(2.7) million and $(2.6) million for the three and nine months ended September 30, 2013, respectively, and $3.3 million and $11.2 million for the three and nine months ended September 30, 2012, respectively. We recognized unrealized gains (losses) of $(5.1) million and $(6.0) million for the three and nine months ended September 30, 2013, respectively, and $(16.1) million and $7.4 million in the same periods of 2012.

Excluding hedges, we realized average oil prices of $110.41 per barrel and $108.24 per barrel and gas prices of $3.74 per Mcf and $3.85 per Mcf for the three and nine months ended September 30, 2013, respectively. For the same periods in 2012, excluding hedges, we realized average oil prices of $102.92 per barrel and $107.93 per barrel and gas prices of $3.06 per Mcf and $2.63 per Mcf, respectively. We expect commodity prices to remain volatile in the future.

Operating Expenses

Lease operating costs. Our lease operating costs for the three and nine months ended September 30, 2013 were $51.0 million, or $48.36 per Boe, and $141.2 million, or $44.75 per Boe. For the three and nine months ended September 30, 2012, our lease operating costs were $43.8 million, or $33.95 per Boe, and $131.1 million, or $31.82 per Boe, respectively. Lease operating expenses increased by $7.2 million and $10.1 million for the three and nine months ended September 30, 2013, respectively, compared to the same periods in 2012, primarily as a result of the West Delta 32 Incident. The increase in cost per Boe during 2013 was primarily attributable to decreased production.

For the three and nine months ended September 30, 2013, non-recurring expenses relating to the West Delta 32 Incident included repair and incident investigation costs of $4.4 million and $11.0 million, respectively. In 2013, we remediated a significant number of Incidents of Noncompliance (“INCs”) and expect the amount of non-recurring expenses incurred in the future to be less.

Workover costs. Our workover costs for the three and nine months ended September 30, 2013 were $1.0 million and $7.3 million, a decrease of $3.4 million compared to the third quarter of 2012 and a decrease of $3.2 million compared to the first nine months in 2012. For the nine months ended September 30, 2013, Ship Shoal 198, South Timbalier 203, South Marsh 23 and Vermilion 119 were the primary workover expense projects.

Exploration. Our exploration expenses for the three and nine months ended September 30, 2012 were $0.3 million and $1.2 million, respectively. There were no exploration costs for the same period in 2013. Exploration costs for 2012 included expenses to drill a non-operated well, South Pelto 13, which was unsuccessful.

Depreciation, depletion, amortization and impairment. DD&A expense was $10.0 million, or $9.51 per Boe, and $32.7 million, or $10.37 per Boe, for the three and nine months ended September 30, 2013, respectively. For the three and nine months ended September 30, 2012, DD&A was $12.3 million, or $9.53 per Boe, and $36.5 million, or $8.87 per Boe. The decrease in DD&A for the three and nine months ended September 30, 2013 was a result of lower production and reduced asset basis as a result of the impairments recorded in 2013 and 2012. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded a $0.4 million and $55.8 million impairment for the three and nine months ended September 30, 2013 and a $3.7 million and $7.0 million impairment for the same periods in 2012, respectively. The impairments recorded during the three months ended September 30, 2013 resulted primarily from additional costs for High Island 443 and South Timbalier 8 as a well was determined to be uneconomic. These impairments were partially offset by the partial reduction of a liability and impairment associated with Garden Banks 602 as we elected to non-consent on a deep water well. The Garden Banks 602 impairment was initially recorded in the first quarter of 2013. Additionally, for the nine months ended September 30, 2013, we recorded impairments related to (1) South Padre 833 field as the operator will plug and abandon the field and (2) additional costs for High Island 443 in which a significant portion of the costs associated with the drilling of this well are recoverable under our insurance policies and the impairment will be partially offset by the "Gain on Involuntary Conversion of Assets" discussed below.

General and administrative expenses. G&A expense was $9.6 million, or $9.12 per Boe, and $28.3 million, or $8.95 per Boe, for the three and nine months ended September 30, 2013 and $8.3 million, or $6.43 per Boe, and $20.7 million, or $5.02 per Boe, for the same periods in 2012. The increase in G&A expense for the three and nine months ended September 30, 2013 was due to an increase in staff, primarily in our drilling and safety groups, and related administrative costs, in addition to higher legal fees relating to the West Delta 32 incident of $0.3 million and $1.4 million, respectively, severance costs, consultant expenses and costs related to our consolidation of Freedom Well Services, LLC. The increases in G&A expense were partially

offset by recording the 2013 surety fees in the amounts of $1.5 million and $4.3 million to “Miscellaneous expense” for the three and nine months ended September 30, 2013, respectively. Additionally, the three months ended September 30, 2013 was also lower compared to the same prior year period due to a decrease in bonus expense.

Gain on involuntary conversion of asset. On September 27, 2012, an incident occurred on our High Island 443 A-2 ST well which required the closing of the blind/shear rams to properly shut in and maintain control of the well due to several days of unsuccessful attempts to repair a small hydrocarbon leak on a conductor riser. Additional surface diagnostics found the inner casing strings to be most likely compromised. On October 12, 2012, the BSEE advised us to plug and abandon the well. We have well control insurance and pursued reimbursement for this incident and the claim was approved. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drill are also insurance recoverable. We recorded a gain of $(7.2) million and $(17.8) million as of the three and nine months ended September 30, 2013, respectively, The claim has been finalized. We received a total of approximately $24.1 million, net of the deductible, in cash for the claim during 2013.

Accretion expense. We recognized accretion expense of $4.5 million and $19.6 million for the three and nine months ended September 30, 2013, respectively, compared to $9.3 million and $27.2 million for the three and nine months ended September 30, 2012, respectively. The decrease in accretion expense in 2013 was primarily attributable to P&A activity that was performed in 2012 and 2013 and the extended life of the remaining assets, partially offset by increased liability, in the fourth quarter of 2012.

Loss (gain) on sale of assets. Loss (gain) on sale of assets of $0.4 million and $(35.4) million for the three and nine months ended September 30, 2013, respectively, was primarily related to the sale of four fields to Renaissance for approximately $52.5 million subject to normal purchase price adjustments on March 26, 2013 and the sale of an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million.

Other operating expenses. Other operating expenses of $2.7 million and $5.1 million for the three and nine months ended September 30, 2013, respectively, were related to our consolidation of Freedom Well Services, LLC. There were no other operating expenses for the same periods in 2012.

Miscellaneous expense. Miscellaneous expense of $2.7 million and $7.6 million for the three and nine months ended September 30, 2013, respectively, compared to $0.9 million and $2.4 million for the three and nine months ended September 30, 2012, respectively, was primarily due to the surety fee reclassification of $1.5 million and $4.3 million for the three and nine months ended September 30, 2013, respectively, as mentioned above under “General and administrative expenses”.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from our members, proceeds from the offering of our senior notes, which closed in November 2010, borrowings under our lines of credit, cash flows from operations and asset sales. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drill were also insurance recoverable. We received a total of $24.1 million, net of the deductible, in cash for the claim. Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties and settlement of our P&A liabilities as well as providing collateral to secure our P&A obligations. To improve our access to funding, 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 a new lender group.

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

Senior Secured Revolving Credit Facility

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 are guaranteed by our existing subsidiaries and are secured on a first-priority basis by all of our and our subsidiaries’ assets, in the case of the Credit Facility, and by cash collateral, in the case of the Letter of Credit Facility. The Credit Facility matures on January 1, 2015 and June 22, 2014 on the Letter of Credit Facility. The Credit Facility is subject to certain customary fees and expenses of the lenders and administrative agent thereunder.

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 the 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 our majority owner, Platinum Partners Value Arbitrage Fund L.P.

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

by 21% and 13%, respectively, of the reasonably anticipated total volume of projected production from proved, developed, and producing oil and gas properties. Our interest coverage ratio covenant was calculated to be 1.2 to 1.0, which was lower than the minimum 3.0 to 1.0. Our payables restriction covenant was calculated at $27.2 million which was higher than the maximum of $6.0 million. We received a limited waiver relating to such covenants in the Eleventh Amendment for the fiscal quarters ended September 30, 2013 and December 31, 2013 as well as a limited waiver on our Letter of Credit Facility in the Waiver and Tenth Amendment for the fiscal quarter ended September 30, 2013.

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

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.

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

We have the right or the obligation to redeem the Notes under various conditions. If we experience a change of control, the holders of the Notes may require us to repurchase the Notes at 101% of the principal amount thereof, plus accrued unpaid interest. We also have an optional redemption in which we may redeem up to 35% of the aggregate principal amount of the Notes at a price equal to 110.0% of the principal amount, plus accrued and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings until December 1, 2013. From December 1, 2013 until December 1, 2014, we may redeem some or all of the Notes at an initial redemption price equal to par value plus one-half the coupon which equals 106.875% plus accrued and unpaid interest to the date of the redemption. On or after December 1, 2014, we may redeem some or all of the Notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption.

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

As of September 30, 2013, we were in compliance with all covenants under the Indenture. We believe anticipated capital expenditures in 2013 will exceed the amount provided for in a covenant regarding maximum capital expenditures. However, the Indenture also provides that we may use proceeds from the sale of assets for capital expenditures that we believe is not limited by the previously referenced capital expenditure covenant. In the event our interpretation of the Indenture is not upheld or if our cash proceeds from the sale of assets are not sufficient to reduce our capital expenditures to a level that makes us compliant with the maximum capital expenditure covenant, we have the option under the Indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes; however, there can be no assurance that we will have sufficient funds to do so. We also have the option to solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the Indenture, the Indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the Indenture covenant could also result in a cross-default under our credit facility.

Member Contributions

$30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class E Units will receive a preferred return of 20% per annum, which will increase from and after March 25, 2014 to 36% per annum (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement). For the nine months ended September 30, 2013, we issued an additional amount of Class E Units of approximately 12.0 million as paid-in-kind dividends to the holders of Class E Units.

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

Capital Expenditures

We expect total capital expenditures to be approximately $99.5 million for 2013 (excluding expenditures directly related to any acquisitions or costs to be reimbursed by insurance). Approximately $89.6 million (excluding expenditures directly related to any acquisitions or costs reimbursed by insurance) was expended in the first nine months of 2013 for various projects including recompletions and drilling, and the remaining $9.9 million will be used for drilling and development during the remainder of the year.

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

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

Cash Flows

The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the six months ended September 30, 2013 and 2012:



	Nine Months Ended September 30,
	2013			2012
Net cash provided by operating activities	$	28,729		$	44,028
Net cash used in investing activities	(50,698		)	(61,129		)
Net cash provided by financing activities	27,272			17,488
Net increase (decrease) in cash and equivalents	$	5,303		$	387

Cash flows provided by operating activities. Cash provided by operating activities totaled $28.7 million during the nine months ended September 30, 2013 compared to $44.0 million during the nine months ended September 30, 2012. Significant components of net cash provided by operating activities during the nine months ended September 30, 2013 included $36.9 million of changes in operating assets and liabilities and $66.0 million of non-cash items, primarily DD&A expense, impairment and accretion of asset retirement obligations partially offset by the net loss, gain on sale of assets and gain on involuntary conversion of assets.

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

Cash flows used in investing activities. Cash used in investing activities was $50.7 million in the nine months ended September 30, 2013 was primarily attributable to $112.7 million in oil and gas property additions associated with the capital drilling program during the period and the $23.4 million funding of the future P&A obligations through escrow partially offset by the sale proceeds of $65.7 million related to the asset sales to Renaissance Offshore, LLC and $23.8 million in proceeds

received from insurance recovery for HI443. Cash used in investing activities in the comparable period of 2012 totaling $61.1 million was attributable to $18.2 million in oil and gas property additions and the $38.9 million funding of the future P&A obligations through escrow.

Cash flows provided by (used in) financing activities. Cash flows provided by financing activities of $27.3 million in the nine months ended September 30, 2013 were attributable to $50.0 million in contributions from the Platinum Group and PPVA Equity and $23.2 million of borrowings under the Credit Facility partially offset by $40.2 million of payments on the Credit Facility and $3.8 million in payments on short-term notes. Cash flows provided by financing activities of $17.5 million ended September 30, 2012 were attributable to $145.0 million of borrowings on the Credit Facility and $17.6 million borrowings on short term notes partially offset by $112.5 million of payments on the Credit Facility, $12.9 million in payments on short-term notes, $16.7 million of tax distributions to members and $3.0 million of debt issue costs.

Asset Retirement Obligations

As many as four times per year, we review and, to the extent necessary, revise our asset retirement obligation estimates. As of September 30, 2013, we had a decrease in our asset retirement obligations primarily as a result of the asset sales to Renaissance Offshore, LLC and in P&A work performed in 2013 partially offset by a revaluation of the liability and accretion expense. For the three and nine months ended September 30, 2013, we recognized $4.5 million and $19.6 million in accretion expense, respectively.

At September 30, 2013 and December 31, 2012, we recorded total asset retirement obligations of $302.9 million and $345.5 million, respectively, and have funded approximately $238.7 million and $215.3 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds. As of September 30, 2013 and December 31, 2012, we also have a guaranteed escrow amount of $20.3 million for certain fields which will be refunded to us once we have completed our P&A obligations on the entire field. The escrow is guaranteed by TETRA Technologies, Inc.

Contractual Obligations

We have various contractual obligations in the normal course of our operations and financing activities. The following schedule summarizes our contractual obligations and other contractual commitments at September 30, 2013:



	Payments Due by Period
	Total		Less than 1 Year		1 - 3 Years		3 -5 Years		After 5 Years
	(in thousands)
Contractual Obligations
Total debt and notes payable	$	185,296	$	243	$	185,053	$	—	$	—
Interest on debt and notes payable	47,882		23,170		24,712		—		—
Operating leases (1)	42,883		31,860		4,230		3,317		3,476
Total contractual obligations	276,061		55,273		213,995		3,317		3,476
Other Obligations
Asset retirement obligations (2)	302,886		32,124		95,011		87,387		88,364
Total obligations (3)	$	578,947	$	87,397	$	309,006	$	90,704	$	91,840


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


(2)	Asset retirement obligations will be partially funded via the escrow. The obligations reflected above are discounted.


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

Off-Balance Sheet Arrangements

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

Oil and Gas Hedging

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

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

At September 30, 2013, commodity derivative instruments were in place covering approximately 75% of our projected oil sales volumes and 24% of our projected natural gas volumes through 2013.

Please see “Notes to Consolidated Financial Statements—Note 5—Derivative Instruments” in this Form 10-Q for additional discussion regarding the accounting applicable to our hedging program.

Critical Accounting Policies

“Management’s Discussion and Analysis of Financial Condition” is based upon our consolidated financial statements, which have been prepared in conformity with GAAP. The preparation of these statements requires that we make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. We base these estimates on historical experience and on assumptions that we consider reasonable under the circumstances; however, reported results could differ from the current estimates under different assumptions and/or conditions. We have disclosed the areas requiring the use of management’s estimates in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2012 Form 10-K.

Inflation and Changes in Prices

Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the three and nine months ended September 30, 2013, we received an average of $110.41 and $108.24 per barrel of oil and $3.74 and $3.85 per Mcf of natural gas, respectively, before consideration of commodity derivative contracts, compared to $102.92 and $107.93 per barrel of oil and $3.06 and $2.63 per Mcf of natural gas, respectively, in the three and nine months ended September 30, 2012. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

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 nine months ended September 30, 2013, our annual revenue would increase or decrease by approximately $16.8 million for each $10.00 per barrel change in oil prices and $13.9 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging. Based on our total annual production for the year ended December 31, 2012, our revenues would have increased or decreased by approximately $19.8 million for each $10.00 per barrel change in oil prices and $17.9 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging.

To partially reduce price risk caused by these market fluctuations, we hedge a significant portion of our anticipated oil and natural gas production as part of our risk management program. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While hedging limits the downside risk of adverse price movements, it also may limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions.

At September 30, 2013, the fair value of our commodity derivatives were included in our consolidated balance sheets for approximately $7.5 million as current liabilities and $1.1 million as long-term liabilities. At December 31, 2012, the fair value of our commodity derivatives was approximately $2.4 million and $5.1 million, which were recorded as current assets and long-term liabilities, respectively. For the three and nine months ended September 30, 2013, we realized net decreases in oil and natural gas revenues related to hedging transactions of approximately $(2.7) million and $(2.6) million, respectively, and increases for the same periods in 2012 of $3.3 million and $11.2 million, respectively.

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



Remaining Contract Term: Oil	Contract Type	Notational Volume in Bbls/Month	NYMEX Strike Price
December 2013 - December 2013	Swap	27,750	$	96.90
October 2013 - October 2013	Swap	27,750	$	96.90
November 2013 - November 2013	Swap	26,800	$	96.90
October 2013 - December 2013	Swap	19,750	$	85.90
January 2014 - February 2014	Swap	19,000	$	96.90
January 2014 - December 2014	Swap	15,000	$	65.00
January 2014 - May 2014	Swap	10,083	$	100.80
December 2013 - December 2013	Swap	10,042	$	100.80
October 2013 - October 2013	Swap	3,259	$	100.80
October 2013 - October 2013	Swap	28,006	$	88.80
November 2013 - November 2013	Swap	31,605	$	88.80
December 2013 - December 2013	Swap	38,743	$	88.80
January 2014 - January 2014	Swap	4,723	$	88.80
February 2014 - February 2014	Swap	13,313	$	88.80
March 2014 - March 2014	Swap	8,413	$	88.80
April 2014 - April 2014	Swap	12,473	$	88.80
May 2014 - May 2014	Swap	11,793	$	88.80
June 2014 - June 2014	Swap	15,546	$	88.80
July 2014 - July 2014	Swap	11,845	$	88.80
August 2014 - August 2014	Swap	13,165	$	88.80
September 2014 - September 2014	Swap	16,235	$	88.80
October 2014 - October 2014	Swap	15,605	$	88.80
November 2014 - November 2014	Swap	18,525	$	88.80
December 2014 - December 2014	Swap	22,526	$	88.80
October 2013 - October 2013	Swap	4,000	$	87.85
November 2013 - November 2013	Swap	250	$	87.85
December 2013 - December 2013	Swap	2,500	$	87.85
January 2014 - January 2014	Swap	46,000	$	87.85
February 2014 - February 2014	Swap	25,000	$	87.85
March 2014 - March 2014	Swap	56,000	$	87.85
April 2014 - April 2014	Swap	45,000	$	87.85
May 2014 - May 2014	Swap	46,000	$	87.85
June 2014 - June 2014	Swap	48,000	$	87.85
July 2014 - July 2014	Swap	36,000	$	87.85
August 2014 - August 2014	Swap	34,000	$	87.85
September 2014 - September 2014	Swap	26,000	$	87.85
October 2014 - October 2014	Swap	27,000	$	87.85
November 2014 - November 2014	Swap	20,000	$	87.85
December 2014 - December 2014	Swap	31,000	$	87.85
October 2013 - October 2013	Swap	67,513	$	108.44
November 2013 - November 2013	Swap	64,159	$	108.44
December 2013 - December 2013	Swap	45,392	$	108.44
January 2014 - January 2014	Swap	46,006	$	100.72
February 2014 - February 2014	Swap	39,159	$	100.72
March 2014 - March 2014	Swap	36,822	$	100.72
April 2014 - April 2014	Swap	34,069	$	100.72
May 2014 - May 2014	Swap	35,200	$	100.72
June 2014 - June 2014	Swap	31,668	$	100.72
July 2014 - July 2014	Swap	48,509	$	100.72
August 2014 - August 2014	Swap	46,473	$	100.72
September 2014 - September 2014	Swap	45,830	$	100.72
October 2014 - October 2014	Swap	44,282	$	100.72
November 2014 - November 2014	Swap	40,874	$	100.72
December 2014 - December 2014	Swap	26,424	$	100.72



Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month	NYMEX Strike Price
January 2014 - June 2014	Swap	129,960	$	4.94
December 2013 - December 2013	Swap	119,462	$	4.94
October 2013 - December 2013	Swap	104,000	$	4.60
October 2013 - October 2013	Swap	91,166	$	4.94
January 2014 - February 2014	Swap	82,000	$	4.60
November 2013 - November 2013	Swap	64,926	$	4.94
October 2013 - December 2013	Swap	47,000	$	5.00
October 2013 - October 2013	Swap	34,551	$	4.09
November 2013 - November 2013	Swap	28,939	$	4.09
December 2013 - December 2013	Swap	37,906	$	4.09
January 2014 - January 2014	Swap	43,347	$	4.09
February 2014 - February 2014	Swap	32,636	$	4.09
March 2014 - March 2014	Swap	46,764	$	4.09
April 2014 - April 2014	Swap	41,253	$	4.09
May 2014 - May 2014	Swap	40,391	$	4.09
June 2014 - June 2014	Swap	20,112	$	4.09
July 2014 - July 2014	Swap	39,283	$	4.09
August 2014 - August 2014	Swap	34,246	$	4.09
September 2014 - September 2014	Swap	29,753	$	4.09
October 2014 - October 2014	Swap	28,635	$	4.09
November 2014 - November 2014	Swap	27,081	$	4.09
December 2014 - December 2014	Swap	34,114	$	4.09
January 2015 - January 2015	Swap	27,838	$	4.09
February 2015 - February 2015	Swap	24,461	$	4.09
March 2015 - March 2015	Swap	26,443	$	4.09
June 2014 - June 2014	Swap	40,391	$	4.19
July 2014 - July 2014	Swap	20,112	$	4.19
August 2014 - August 2014	Swap	39,283	$	4.19
September 2014 - September 2014	Swap	34,246	$	4.19
October 2014 - October 2014	Swap	29,753	$	4.19
November 2014 - November 2014	Swap	28,635	$	4.19
December 2014 - December 2014	Swap	27,081	$	4.19
January 2015 - January 2015	Swap	34,114	$	4.19
February 2015 - February 2015	Swap	27,838	$	4.19
March 2015 - March 2015	Swap	24,461	$	4.19

For a further discussion of our hedging activities, please see “Notes to Consolidated Financial Statements—Note 5—Derivative Instruments” in this Form 10-Q.

Credit Risk

We monitor our risk of loss associated with non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through joint interest receivables, which totaled $17.4 million at September 30, 2013 and $17.8 million at December 31, 2012. Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have an interest. We also have exposure to credit risk from the sale of our oil and natural gas production that we market to energy marketing companies and refineries, the receivables totaled $39.1 million at September 30, 2013 and $27.2 million at December 31, 2012. We also have credit risk associated with our financially settled crude oil and natural gas swaps. As of September 30, 2013, all of our swaps were with BP Energy Company as the counterparty.

In order to minimize our exposure to credit risk, we request prepayment of costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. We also have the right to place a lien on our co-owners interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. In addition, we monitor our exposure to counterparties on oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each

counterparty’s credit worthiness. We historically have not required our counterparties to provide collateral to support oil and natural gas sales receivables owed to us.

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility, which 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 grid when the borrowing based utilization percentage is at its highest level. Based on the $35.0 million outstanding under the Credit Facility as of September 30, 2013, an increase of 100 basis points in the underlying interest rate would have had a $0.4 million impact on our annual interest expense. However, there is no guarantee that we will not borrow additional amounts under the Credit Facility in the future, and, in the event we borrow amounts and interest rates significantly increase, the interest that we would be required to pay would be more significant. We do not believe our variable interest rate exposure warrants entry into interest rate hedges and, therefore, we have not hedged our interest rate exposure. However, to reduce our exposure to changes in interest rates for our borrowings under the Credit Facility, we may in the future enter into interest rate risk management arrangements for a portion of our outstanding debt to alter our interest rate exposure.

Item 4. Controls and Procedures

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

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


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


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

Remediation. To remediate this material weakness, during 2013, management has and will continue executing the remediation program that began during early 2013, which includes assessing the adequacy of processes and procedures underlying the specific areas discussed above, expanding and strengthening our controls surrounding the 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.

Changes in Internal Control Over Financial Reporting. Other than the measures described above under “Remediation” and the appointment of our Chief Financial Officer, Bruce Koch, on April 16, 2013, there has not been any change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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.

The United States Chemical Safety and Hazard investigation board has also made inquiry of us regarding the incident but indicated that they will not open an investigation. 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. 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.

Civil Litigation. As of November 12, 2013, several civil lawsuits have been filed as a result of the West Delta 32 Incident. The courts held a status conference ordering procedural matters to be filed on the court’s docket. All civil cases filed both in Texas and Louisiana 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.

company and that the defendants’ alleged gross mismanagement harmed BEE by allegedly causing a credit rating downgrade and a prospective buyer to reduce an alleged offer price for our company. The plaintiffs seek an unspecified amount of damages on behalf of BEE in connection with these claims. On July 26, 2013, in response to a motion to dismiss by PPVA Black Elk (Equity) LLC and its affiliated entities, the court dismissed all claims against all defendants. The claims were dismissed with prejudice to re-filing in Texas.

In the previously reported investor plaintiff civil matter, the same plaintiffs filed a Temporary Restraining Order and Preliminary Injunction in the Supreme Court of the State of New York, County of New York, restraining BEEOO from dispersing any proceeds from the sale of 43 oil and gas offshore fields being marketed at an oil and gas clearing house until 27.01% of the sale proceeds are placed in an escrow account during the pendency of the litigation. The Judge dismissed the Temporary Restraining Order and set a hearing for the Motion for the Injunction. The court heard oral arguments on the preliminary injunction motion on October 31, 2013 and reserved decision; a ruling is expected later this month. The Company intends to file a motion to dismiss the complaint in its entirety for failure to state a cause of action and based on documentary evidence that refutes the claims.

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

Item 1A. Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Risk Factors” in our 2012 Form 10-K. The risks described in the 2012 Form 10-K could materially and adversely affect our business, financial condition, cash flows, and results of operations. Except as set forth below, there have been no material changes to the risks described in the 2012 Form 10-K. We may experience additional risks and uncertainties not currently known to us, or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

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

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

Item 5. Other Information

As of September 30, 2013, we were not in compliance with the financial covenants set forth in Section 9.01(a), (b) and (c) of the Letter of Credit Agreement dated December 24, 2010 (as amended by that First Amendment dated May 31, 2011 and that Second Amendment dated December 30, 2011, and as further amended, restated, supplemented or modified from time to time, the “Letter of Credit Agreement”) as our payables restriction covenant was calculated to be $27.2 million which was higher than our maximum of $6 million, our total leverage ratio was calculated to be 6.0 to 1.0 which was higher than the required 2.5 to 1.0 and our interest coverage ratio was calculated to be 1.2 to 1.0 which was lower than the required 3.0 to 1.0. We received a waiver for the period for the fiscal quarter ended September 30, 2013. The Letter of Credit Agreement also (1) capped the outstanding principal balance under the Letter of Credit Facility at approximately $66.6 million, (2) removed the obligation to issue or renew existing Letters of Credit and (3) removed the financial covenant requirements and the restriction of asset sales.

The foregoing description of the Letter of Credit Agreement, is qualified in its entirety by the full text of such agreement which is filed as Exhibit 10.11 to this Quarterly Report on Form 10-Q and incorporated by reference herein.

Item 6. Exhibits

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

Form 10-Q.



Exhibit Number	Description

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

3.2	Certificate of Amendment of Black Elk Energy Offshore Operations, LLC, dated as of January 29, 2008 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).

3.3	Second Amended and Restated Limited Liability Company Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of July 13, 2009 (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).

3.4	First Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated August 19, 2010 (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).

3.5	Second Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 31, 2011 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).

3.6	Third Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of January 25, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on January 31, 2013).

3.7	Fourth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of February 12, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on February 19, 2013).

3.8	Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of April 9, 2013 (incorporated by reference to Exhibit 3.10 to the Form 8-K filed with the Securities and Exchange Commission on April 15, 2013).

3.9	Sixth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 3, 2013 (incorporated by reference to Exhibit 3.1 to the Form 10-K filed with the Securities and Exchange Commission on May 9, 2013).

10.1	Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and Renaissance Offshore, LLC, effective as of July 31, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on August 6, 2013).

10.2	Tenth Amendment to Credit Agreement, effective as of July 31, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on August 6, 2013).

10.3	Letter Loan Purchase Agreement, dated as of July 31, 2013, by and among the Company, PPVA Black Elk Equity LLC, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on August 6, 2013).

10.4	Guaranty, dated as of July 31, 2013, by Platinum Partners Value Arbitrage Fund L.P., Platinum Montaur Life Sciences, LLC, Meserole Group LLC, PPVA Black Elk Investors LLC and DMRJ Group LLC in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders to that certain Credit Agreement dated December 24, 2010, as amended (incorporated by reference to Exhibit 10.4 to the Form 8-K filed with the Securities and Exchange Commission on August 6, 2013).

10.5	Limited Waiver and Ninth Amendment to Letter of Credit Facility Agreement and Amendment to Note, effective as of August 15, 2013, by and among the Company, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on August 21, 2013).



Exhibit Number	Description

10.6	Loan Purchase and Sale Agreement, dated as of August 30, 2013, by and among Capital One Bank, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto, and White Elk LLC, as new Administrative Agent and Lender, and Resource Value Group LLC, as new Lender (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on September 6, 2013).

10.7	Omnibus Assignment and Assumption of Loans, Loan Documents and Related Liens and Security Interests and Appointment of Agent, dated as of August 30, 2013, by and among, Capital One, N.A., in its capacity as Administrative Agent for the Lenders, Issuing Bank and Collateral Agent and Mortgagee for the Secured Parties and First Lien Agent, Second Lien Agent and Facility Swap Agent under the Intercreditor Agreements, the Lenders signatory thereto, White Elk LLC, Resource Value Group LLC, on behalf of one or more beneficial holders of the Loans, and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on September 6, 2013).

10.8	Limited Waiver and Eleventh Amendment to Credit Agreement, effective as of August 30, 2013, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, White Elk LLC, as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on September 6, 2013).

10.9	Subscription Agreement, dated as of September 16, 2013, by and between Black Elk Energy Offshore Operations, LLC and Asiasons Capital Limited (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on September 20, 2013).

10.10	Supplemental Agreement, dated as of September 26, 2013, by and between Black Elk Energy Offshore Operations, LLC and Asiasons Capital Limited (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 3, 2013).

*10.11	Limited Waiver, Tenth Amendment to Letter of Credit Facility Agreement, effective as of November 14, 2013, by and among the Company, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders.

*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.

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

EXHIBIT INDEX

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

Form 10-Q.



Exhibit Number	Description

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

3.2	Certificate of Amendment of Black Elk Energy Offshore Operations, LLC, dated as of January 29, 2008 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).

3.3	Second Amended and Restated Limited Liability Company Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of July 13, 2009 (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).

3.4	First Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated August 19, 2010 (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).

3.5	Second Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 31, 2011 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).

3.6	Third Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of January 25, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on January 31, 2013).

3.7	Fourth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of February 12, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on February 19, 2013).

3.8	Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of April 9, 2013 (incorporated by reference to Exhibit 3.10 to the Form 8-K filed with the Securities and Exchange Commission on April 15, 2013).

3.9	Sixth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 3, 2013 (incorporated by reference to Exhibit 3.1 to the Form 10-K filed with the Securities and Exchange Commission on May 9, 2013).

10.1	Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and Renaissance Offshore, LLC, effective as of July 31, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on August 6, 2013).

10.2	Tenth Amendment to Credit Agreement, effective as of July 31, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on August 6, 2013).

10.3	Letter Loan Purchase Agreement, dated as of July 31, 2013, by and among the Company, PPVA Black Elk Equity LLC, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on August 6, 2013).



10.4	Guaranty, dated as of July 31, 2013, by Platinum Partners Value Arbitrage Fund L.P., Platinum Montaur Life Sciences, LLC, Meserole Group LLC, PPVA Black Elk Investors LLC and DMRJ Group LLC in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders to that certain Credit Agreement dated December 24, 2010, as amended (incorporated by reference to Exhibit 10.4 to the Form 8-K filed with the Securities and Exchange Commission on August 6, 2013).

10.5	Limited Waiver and Ninth Amendment to Letter of Credit Facility Agreement and Amendment to Note, effective as of August 15, 2013, by and among the Company, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on August 21, 2013).

10.6	Loan Purchase and Sale Agreement, dated as of August 30, 2013, by and among Capital One Bank, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto, and White Elk LLC, as new Administrative Agent and Lender, and Resource Value Group LLC, as new Lender (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on September 6, 2013).

10.7	Omnibus Assignment and Assumption of Loans, Loan Documents and Related Liens and Security Interests and Appointment of Agent, dated as of August 30, 2013, by and among, Capital One, N.A., in its capacity as Administrative Agent for the Lenders, Issuing Bank and Collateral Agent and Mortgagee for the Secured Parties and First Lien Agent, Second Lien Agent and Facility Swap Agent under the Intercreditor Agreements, the Lenders signatory thereto, White Elk LLC, Resource Value Group LLC, on behalf of one or more beneficial holders of the Loans, and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on September 6, 2013).

10.8	Limited Waiver and Eleventh Amendment to Credit Agreement, effective as of August 30, 2013, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, White Elk LLC, as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on September 6, 2013).

10.9	Subscription Agreement, dated as of September 16, 2013, by and between Black Elk Energy Offshore Operations, LLC and Asiasons Capital Limited (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on September 20, 2013).

10.10	Supplemental Agreement, dated as of September 26, 2013, by and between Black Elk Energy Offshore Operations, LLC and Asiasons Capital Limited (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 3, 2013).

*10.11	Limited Waiver, Tenth Amendment to Letter of Credit Facility Agreement, effective as of November 14, 2013, by and among the Company, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders.

*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.