10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 ___________________________________________________

FORM 10-K

___________________________________________________ 

(Mark one)

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

For the fiscal year ended December 31, 2013

or

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

For the transition period from              to             

Commission file no. 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    ¨  Yes    x  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    x  Yes    ¨  No

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.    x  Yes    ¨  No

(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 Website, 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).    x  Yes    ¨  No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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.

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 Act).  ¨  Yes    x  No

As of June 29, 2012, the registrant’s membership interests are currently not listed on an exchange and, therefore, the aggregate market value of the registrant’s membership interests held by non-affiliates on such date cannot be reasonably determined.

As of March 31, 2014, there were 1,361,300 Class A Units, 114,277,308.5 Class B Units, 12,031,250 Class C Units and 109,743,693 Class E Units issued and outstanding.

___________________________________________________ 

DOCUMENTS INCORPORATED BY REFERENCE:

Exhibits incorporated by reference are referred to under Part IV of this annual report.

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC’S

ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2013

TABLE OF CONTENTS

	Page
Cautionary Note Regarding Forward-Looking Statements	ii
PART I
Item 1. Business	1
Item 1A. Risk Factors	17
Item 1B. Unresolved Staff Comments	34
Item 2. Properties	34
Item 3. Legal Proceedings	34
Item 4. Mine Safety Disclosures	36
PART II
Item  5. Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6. Selected Financial Data	37
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	62
Item 8. Financial Statements and Supplementary Data	64
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	93
Item 9A. Controls and Procedures	93
Item 9B. Other Information	94
PART III
Item 10. Directors, Executive Officers and Corporate Governance	96
Item 11. Executive Compensation	97
Item  12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	103
Item 13. Certain Relationships and Related Transactions and Director Independence	105
Item 14. Principal Accountant Fees and Services	107
PART IV
Item 15. Exhibits and Financial Statement Schedules	108
EXHIBIT INDEX

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Form 10-K”) 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-K, 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-K, 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 acquisitions. 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 those described in “Item 1A. Risk Factors.”

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this Form 10-K. 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 this 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, expressed or implied, included in this Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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

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PART I

Except as otherwise indicated or required by the context, references in this Form 10-K to: (1) “we,” “us,” “our,” “Parent” or “Black Elk” refer to the combined business of Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries.

Item 1.        Business

Overview

We are an oil and natural gas company headquartered in Houston, Texas with substantially all of our producing assets located offshore in U.S. federal and Louisiana and Texas state waters in the Gulf of Mexico. We were formed in November 2007 as a limited liability company to acquire, exploit and develop oil and natural gas properties in our area of focus from oil and gas companies that have determined that such assets are noncore for their purposes and desire to remove them from their producing property portfolio or deemphasize their offshore operations. In addition to our acquisition strategy, we continue to grow organically through the exploitation and development of our existing field inventory by the use of drilling, workover, recompletion and other lower-risk development projects to increase reserves and production.

As of December 31, 2013, our leasehold position encompassed approximately 457,065 gross ((223,852) net) acres, 935 gross (444 net) wells and 58 production platforms. As of December 31, 2013, we had estimated total proved oil, natural gas and NGL reserves of 26.0 MMBoe (45% oil) with a PV-10 value of $636 million based on the reserve report as of December 31, 2013 (“NSAI Report”) of Netherland, Sewell & Associates, Inc., independent petroleum engineers (“NSAI”), using U.S. Securities and Exchange Commission (“SEC”) pricing based on the average price as of the first day of each of the twelve months ended December 31, 2013. For 2013, our net daily production averaged approximately 11,388 Boepd.

Our Acquisition History

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

On October 29, 2009, we purchased interests in approximately 35 fields and 350 wells primarily located in U.S. federal waters of the outer continental shelf of the Gulf of Mexico (the “Outer Continental Shelf” or “OCS”) encompassing approximately 195,000 gross (71,000 net) acres (the “W&T Properties”) from W&T Offshore, Inc. (“W&T”). The W&T Properties also included related leases, platforms, equipment and other associated assets. The purchase price was $30 million plus the assumption of approximately $73.3 million of undiscounted asset retirement obligations related to plugging and abandonment (“P&A”) obligations associated with the W&T Properties, subject to customary effective-date adjustments and closing adjustments. The W&T Properties had a PV-10 value of $121.1 million and estimated proved reserves of 8.8 MMBoe, which accounted for approximately 19% of our total PV-10 value and approximately 34% of our total proved reserves at such time.

During the first quarter of 2010, we acquired six fields and added interests in an additional 40 wells spanning approximately 13,900 gross (6,400 net) acres, primarily located within Texas state waters in the Gulf of Mexico from Chroma Oil and Gas, LP. On September 30, 2010, we acquired interests in 27 properties across approximately 195,944 gross (103,130 net) acres (the “Nippon Properties”) in the Gulf of Mexico from Nippon Oil Exploration U.S.A. (“Nippon”). The Nippon Properties included interests in 90 producing wells, 223 wellbores, 41 platforms and 19 producing fields. The purchase price was $5 million plus the assumption of approximately $95.6 million of undiscounted asset retirement obligations related to P&A obligations associated with the Nippon Properties, subject to customary effective-date adjustments and closing adjustments. As of December 31, 2013, the Nippon Properties had a PV-10 value of $31.1 million and estimated proved reserves of 4.9 MMBoe, which accounted for approximately 5% of our total PV-10 value and approximately 19% of our total proved reserves at such time.

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

On May 31, 2011, we acquired certain interests in various properties across approximately 250,126 gross (127,894 net) acres (the “Merit Properties”) in the Gulf of Mexico in Texas and federal waters from Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P. (the “Merit Entities”). In

1

connection with the acquired Merit Properties, we entered into a contribution agreement with Platinum Partners Value Arbitrage Fund L.P., and/or certain of its affiliates (collectively “Platinum”), whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million of our Class D Preferred Units (the “Class D Units”). As of December 31, 2013, the Merit Properties had a PV-10 value of $224.4 million and estimated proved reserves of 9.7 MMBoe, which accounted for approximately 35% of our total PV-10 value and approximately 37% of our total proved reserves at such time.

We have financed our acquisitions to date through a combination of cash flows provided by operating activities, borrowings under lines of credit and 13.75% Senior Secured Notes due 2015 (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-operating property interests at what we believe to be attractive rates of return either because they provided footholds 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.

Our Business Strategies

Our goal is to increase unit holder value by increasing our reserves production and cash flow at an attractive return on invested capital. We seek to achieve this goal through the following strategies:

• Conduct all operations safely using industry best practices, be good stewards of the environment and strive towards being compliant with all regulations. We intend to continue to use experts to ensure all work and operations are continuously conducted in a compliant manner as dictated by our policies and procedures and all applicable regulations. Our safety and environmental management system (“SEMS”) will have continuous learning at its core and seek to be highly effective in every aspect of our work.

• Continue to pursue strategic acquisitions. We intend to continue to selectively acquire properties in areas that meet certain investment criteria without unintended environmental impact. Our strategy is to acquire and economically maximize properties that are currently producing or have the potential to produce with additional attention and capital resources. We believe that our strategy provides assets to develop and produce with minimal risk, cost or time of traditional exploration. We stringently assess technical information to protect against potential risks as part of our acquisition strategy. Our approach extends the economic life of fields and delivers a greater volume of reserves. We believe strategic opportunities will continue to be available and will generate attractive returns.

• Enhance returns by focusing on operational and cost efficiencies. 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. 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.

• Focus primarily on the Gulf of Mexico. Our experience in the Gulf of Mexico has led us to focus our efforts in that particular region where we are familiar with the regulatory, geological and operational characteristics of this environment. This geographic focus enables us to minimize logistical costs and required staff.

• Expand geographic focus to create a balanced portfolio of onshore and offshore reserves. Our management team has a wide experience base. We intend to leverage that experience and expertise to enhance our reserve and cash flow base. We are continuing to acquire under-capitalized Gulf of Mexico as assets.

• Manage our exposure to commodity price risk. We intend to continue to manage our exposure to commodity price risk in the near term while remaining opportunistic over the long term. 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 decisions 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.

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Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:

• Acquisition execution capabilities. We have a proven track record of identifying, evaluating and executing the purchase of oil and natural gas assets. Since we began operations in 2008, we have completed seven acquisitions which have created significant value relative to the capital employed. We believe that our expertise related to the legal, financial and regulatory aspects of acquisitions allows us to quickly and successfully close transactions.

• Experienced management team. 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 operations. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In the past year, we have developed a drilling team that provides a significant competitive advantage through its experience and knowledge of the Gulf of Mexico.

• Efficient management of our Plugging and Abandonment activities. We consider the evaluation and execution of plugging and abandonment ("P&A") activities to be one of our core competencies. We have an experienced internal team with a dedicated focus on managing our P&A activities and estimating P&A costs associated with acquisition opportunities. Our ongoing effort to manage our P&A liabilities by proactively removing inactive structures, wellbores and pipelines meaningfully reduces our operating expenses, maintenance expenses, insurance premiums and overall risk exposure. We also have an affiliation with a well service and P&A company, which provides us access to reliable equipment and workers on our decks.

• Large inventory of opportunities. We have a large inventory of behind pipe, proved developed non-producing reserves as well as low-risk drilling locations classified as proved undeveloped (“PUD”) reserves. Probable and possible reserve classes also hold the potential to increase our opportunity set once technically fully evaluated.

• Large acreage position. We hold interest in 457,065 gross (223,852 net) acres in the Gulf of Mexico, which will allow us to pursue the deep and ultra-deep potential that exists under current producing horizons.

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Our Operations

Estimated Proved Reserves

The following table sets forth our estimated net proved reserves and the present value of such future cash flows as of December 31, 2013, 2012 and 2011. The Standardized Measure and PV-10 values shown in the table below are not intended to represent the current market value of the estimated oil and natural gas reserves we own.

	At December 31,
	2013			2012			2011
Reserve Data (1):
Estimated net proved reserves:
Oil (MBbls)	11,674			19,268			18,089
Natural gas (MMcf)	77,790			113,093			150,393
NGL (MBbls)	1,373			2,222			2,034
Total estimated net proved reserves (MBoe)	26,012			40,339			45,189
Estimated net proved developed reserves:
Oil (MBbls)	8,933			10,610			10,538
Natural gas (MMcf)	53,907			73,001			83,324
NGL (MBbls)	1,040			1,651			1,291
Total estimated net proved developed reserves (MBoe)	18,957			24,428			25,716
Percent developed	73		%	61		%	57		%
Estimated net proved undeveloped reserves:
Oil (MBbls)	2,741			8,658			7,551
Natural gas (MMcf)	23,883			40,092			67,069
NGL (MBbls)	334			571			743
Total estimated net proved undeveloped reserves (MBoe)	7,056			15,911			19,472
PV-10 (in thousands) (2)	$	635,950		$	1,057,793		$	1,061,408
Standardized measure (in thousands) (2)	$	635,950		$	1,057,793		$	1,061,408

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(1) Our estimated net proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $93.42 per Bbl for oil volumes and $3.67 per Mcf for gas volumes for the year ended December 31, 2013, $91.21 per Bbl for oil volumes and $2.76 per Mcf for gas volumes for the year ended December 31, 2012 and $92.71 per Bbl for oil volumes and $4.12per Mcf for gas volumes for the year ended December 31, 2011 . For oil volumes, the average West Texas Intermediate price is adjusted by field for quality, transportation fees, and regional price differentials. For gas volumes, the average regional spot prices are adjusted by field for energy content, transportation fees and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $107.00 per Bbl of oil, $3.933per Mcf of gas and $40.69 per Bbl of NGL.

(2) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future revenues. However, our PV-10 and our Standardized Measure are equivalent because we are classified as a limited liability company not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our equity holders. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

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There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.

Extensions, discoveries and other additions. These are additions to proved reserves that result from exploratory drilling and the acquisition of new data, including production data, seismic data and well test data.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process. Netherland, Sewell & Associates, Inc., ("NSAI"), our independent petroleum engineers estimated, in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers and definitions and guidelines established by the SEC, 100% of our proved reserve information as of December 31, 2013, 2012 and 2010 included in this Form 10-K. Our internal technical persons and those at NSAI primarily responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, NSAI employed technologies consistent with the standards established by the Society of Petroleum Engineers. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, seismic data and well test data.

Estimated Proved Undeveloped Reserves. Our proved undeveloped reserves at December 31, 2013 are 7.1 MMBoe, consisting of 3.1 MBbls of oil and NGLs and 23.9 Bcf of natural gas. At December 31, 2012, our proved undeveloped reserves were 15.9 MMBoe, consisting of 9.2 MBbls of oil and NGLs and 40.1 Bcf of natural gas. Decreases in proved undeveloped reserves in the past year were primarily due to the reclassification of PUD reserves to proved developed reserves as a result of our 2013 capital campaign. We also had select PUD reserves re-cataloged as unproven due to reaching the five year period. In 2013, we drilled & completed five operated wells and five non-operated wells.

Developed and Undeveloped Acreage

The following table presents the total gross and net developed and undeveloped acreage by region as of December 31, 2013:

	Developed Acres		Undeveloped Acres		Total
	Gross	Net	Gross	Net	Gross	Net
Offshore (1)	457,065	223,852	720	360	457,785	224,212
Total	457,065	223,852	720	360	457,785	224,212

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(1) Our core areas of production in U.S. federal waters in the Gulf of Mexico are the Ship Shoal 176, Vermilion 369/370/408, South Pass 89/86, and High Island A-571 fields.

The gross and net undeveloped acres as of December 31, 2013 will expire April 2016 unless production is established within the spacing units covering the acreage prior to the applicable lease expiration dates.

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Drilling Activity

During the three years ended December 31, 2013, 2012 and 2011, we drilled development and exploratory wells as set forth in the table below. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.

	2013		2012		2011
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive oil	8	4.64	1	0.15	—	—
Productive natural gas	2	1.02	1	0.13	—	—
Dry	1	1	—	—	—	—
Total	11	6.24	2	0.28	—	—

	2013		2012		2011
	Gross	Net	Gross	Net	Gross	Net
Exploratory wells:
Productive oil	—	—	—	—	—	—
Productive natural gas	—	—	—	—	—	—
Dry	—	—	—	—	1	0.10
Total	—	—	—	—	1	0.10

Capital Expenditure Budget

We have a total capital expenditure budget of $33.8 million for 2014, excluding expenditures directly related to acquisitions, which is a 70% decrease over the approximately $113.7 million of capital expenditures invested during 2013. Our 2014 capital expenditure budget will be used for various projects including recompletions, development and drilling. To date, our 2014 capital budget has been funded from cash flow from operations. We are evaluating potential asset sales of core and non-core assets to optimize our portfolio, as well as continuing to review our escrow accounts to determine if there are opportunities to replace our letters of credit, which are 100% cash-backed, with surety bonds. We believe the cash flow from operations and potential divestitures should be sufficient to fund our 2014 capital expenditure budget.

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

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Oil and Natural Gas Hedging” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

We review acquisition opportunities on an ongoing basis. Our ability to make significant 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.

Our Significant Oil and Natural Gas Properties

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We have a geographically diverse asset portfolio in the Gulf of Mexico. Our interests are located offshore in U.S. federal and Louisiana and Texas state waters, with depths ranging from less than ten feet up to 7,036 feet. As of December 31, 2013, our leasehold position encompassed approximately 457,065 gross (223,852 net) acres, 935 gross (444 net) wells and 58 production platforms. As of December 31, 2013, we operated approximately 50% of the fields and 47% of the wells in our asset portfolio.

The following describes our significant properties and interests as of December 31, 2013, which at such time accounted for approximately 52% of our total PV-10 value based on the NSAI Report, and approximately 45% of our total proved reserves, totaling 12.3 MMBoe.

• Ship Shoal 176. We acquired the Ship Shoal 176 field, which is located in approximately 100 feet of water in U.S. federal waters, in the Merit Acquisition. We have a 98% net average working interest in this field and serve as the operator. This field currently contains 12 producing wells and, as of December 31, 2013, had estimated total proved oil and natural gas reserves of 5.0 MMBoe.

• Vermilion 369/370/408. We acquired the Vermilion 408 field, which is located in approximately 400 feet of water in U.S. federal waters, in the Merit Acquisition. We have a 100% net average working interest in this field and serve as the operator. This field currently contains 2 producing wells and, as of December 31, 2013, had estimated total proved oil and natural gas reserves of 1.5 MMBoe.

• South Pass 89/86. We acquired the South Pass 89/86 field, which is located in approximately 388 feet of water in U.S. federal waters, in the W&T Acquisition. We have a 64% net average working interest in this field and are the operator of record. This field currently contains producing wells and, as of December 31, 2013, had estimated total proved oil and natural gas reserves of 0.7 MMBoe.

• High Island A-571. We acquired the High Island A-571 field, which is located in approximately 300 feet of water in U.S. federal waters, in the W&T Acquisition. We have a 81% net average working interest in this field and are the operator of record. This field currently contains 4 producing wells and, as of December 31, 2013, had estimated total proved oil and natural gas reserves of 5.1 MMBoe.

Production, Price and Cost History

Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically during this decade. However, the current economic slowdown reduced this demand during the second half of 2010 and through 2012. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets. See Item 1A. “Risk Factors—If oil and natural gas prices decline, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.”

Although we are not currently experiencing any significant voluntary curtailment of our oil and natural gas production, market, economic, transportation and regulatory factors may in the future materially affect our ability to market our oil or natural gas production. See Item 1A. “Risk Factors—Market conditions or transportation impediments may hinder our access to oil and natural gas markets or delay production.”

The following table sets forth information regarding oil and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2013, 2012 and 2011. For additional information on price calculations, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations.”

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	Year Ended December 31,
	2013		2012		2011
Net sales volumes:
Oil (MBbl)	1,730		1,977		1,991
Natural gas (MMcf)	13,294		17,884		18,188
Plant products (MGal)	8,854		13,588		12,257
Oil equivalents (MBoe)	4,156		5,281		5,314
Average sales price per unit: (1)
Oil (Bbl)	$	102.17	$	110.18	$	105.17
Natural gas (Mcf)	$	4.21	$	3.73	$	4.94
Oil equivalents (Boe)	$	57.90	$	56.50	$	59.30
Costs and expenses per Boe:
Lease operating expenses	$	42.63	$	34.22	$	29.83
Depreciation, depletion, amortization, and impairment	$	29.52	$	14.84	$	11.32
General and administrative expenses	$	8.81	$	5.02	$	4.15

___________________________________

(1) Average prices presented give effect to our hedging. Please see Item 7. “Management’s Discussion and Analysis of Financial Conditions and Results of Operations”—Oil and Natural Gas Hedging” for a discussion of our hedging activities.

The following table sets forth information regarding our average net daily production for the years ended December 31, 2013 and 2012:

	Average Net Daily Production for the Year Ended December 31, 2013			Average Net Daily Production for the Year Ended December 31, 2012
	Bbls	Mcf	Boe	Bbls	Mcf	Boe
Offshore (1)	5,318	36,421	11,388	6,286	48,864	14,429

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(1) Our core areas of production in U.S. federal waters in the Gulf of Mexico are the Ship Shoal 176, Vermilion 408, South Pass 89/86, and High Island A-571.

Productive Wells

The following table presents the total gross and net productive wells by project area and by oil or gas completion as of December 31, 2013:

	Oil Wells		Natural Gas Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Offshore (1)	115	52	119	64	234	116

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(1) Our core areas of production in the U.S. federal waters in the Gulf of Mexico are the Ship Shoal 176, Vermilion 408, South Pass 89/86, and High Island A-571.

Gross wells are the number of wells in which a working interest is owned and net wells are the total of our fractional working interests owned in gross wells.

Marketing and Customers

We generally sell our natural gas and oil at the wellhead to marketing companies. All of our offshore and shallow water production is connected to a pipeline.

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We have been selling to our customers set forth below since our inception and believe that we receive market rates for our natural gas and oil production from such customers. We obtain letters of credit from our customers and discuss the credit worthiness of our customers’ purchasers on an ongoing basis.

The following purchasers and operators accounted for 10% or more of our oil and natural gas sales:

	Year Ended December 31,
	2013		2012		2011
Shell Trading (US) Company	62	%	18	%	51	%
JP Morgan Ventures Energy Corporation	—	%	41	%	8	%

Please read Item 1A. “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Sales to a small number of customers represent a substantial portion of our revenues. The loss of any of our major customers could significantly harm our financial condition.”

Delivery Commitments

Substantially all of our production is sold pursuant to month-to-month marketing contracts that can be terminated by either party at any time and do not contain specific volume or pricing on other than a market basis.

Competition

The oil and gas industry is highly competitive. We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of these competitors are large, well-established companies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, please read Item 1A, Risk Factors—Competition for oil and natural gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.”

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our credit facility, liens to secure our P&A obligations, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties.

Seasonality

In the past, the demand for and price of natural gas increased during the winter months and decreased during the summer months. However, these seasonal fluctuations were somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas. With the development of the shale plays, seasonality is less a factor. Oil was also impacted by generally higher prices during winter months but has more recently been affected by geopolitical events and the global recession. Seasonal weather changes have also affected our operations. Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which may require us to evacuate personnel and shut-in production until these storms

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subside. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of production facilities, thereby delaying sales of our oil and natural gas.

Insurance

We maintain insurance programs to provide coverage for a high percentage of our assets in the event of physical damage and well control events. While we may not obtain insurance for some risks if we believe the cost of available insurance is excessive relative to the risks presented, we intend to continue to pursue a strong risk mitigation program by maintaining comprehensive insurance coverage related to our exposure to operational and weather related risks.

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 (the “West Delta 32 Incident”). At the time of the explosion, production on the platform had been shut in while crews of independent contractors performed maintenance and construction on the platform. Three workers died as a result of the explosion and subsequent fire, and others sustained varying degrees of personal injuries. For additional information, please see “Risk Factors” under Item 1A of this Form 10-K and “Legal Proceedings” under Item 3 of this Form 10-K.

Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.

Drilling and Production

Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the surface use and restoration of properties upon which wells are drilled; and

• the plugging and abandoning of wells.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a

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production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain onsite security regulations and other appropriate permits issued by the Bureau of Land Management (the “BLM”) or other appropriate federal or state agencies.

Transportation and Sales of Oil

Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act (“ICA”). The ICA requires that pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC. Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning in 2010, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 2.65%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids transportation rates may result in lower revenue and cash flows for us.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a nondiscriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. As a result, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity or for new shippers. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. Nonetheless, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Transportation and Sales of Natural Gas

The transportation and sale for resale of natural gas in interstate commerce is regulated by the FERC under the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”), and regulations issued under those statutes.

The FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and nondiscriminatory basis. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although the FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. To the extent that the FERC issues an order which reclassifies transmission facilities as gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by the FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.

With regard to our physical sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission (the “CFTC”). See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires certain natural gas market participants to report information regarding physical natural gas transactions for each calendar year and to indicate whether they report prices. See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”

The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

State Natural Gas Regulation

Various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Certain states also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations in which we can drill.

Other Federal Laws and Regulations Affecting Our Industry

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (the “EPAct 2005”). EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by the FERC, and furthermore provides the FERC with additional civil penalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million

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per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, the FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to the FERC’s jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of the FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

FERC Market Transparency Rules. On December 26, 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order No. 704”). Under Order No. 704, wholesale buyers and sellers of more than 2.2 MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Federal Trade Commission (FTC) and Commodity Futures Trading Commission (CFTC) Regulations. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to liquids swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to liquids purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation.

Environmental and Occupational Health and Safety Regulation

Our exploitation, development and production operations in the U.S. Gulf of Mexico are subject to various federal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require us to acquire permits to conduct exploitation, drilling and production operations; restrict the amounts and types of substances that we may release into the environment or the manner in which we handle or dispose of our wastes in connection with oil and natural gas drilling and production; cause us to incur significant capital expenditures to install pollution control or safety-related equipment at our operating facilities; limit or prohibit our construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose on us specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; impose obligations on us to reclaim and abandon well sites, and expose us to substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly operational requirements or waste handling, disposal, cleanup and remediation requirements for the oil and natural gas industry could have a significant impact on

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our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on our financial condition or results of operations, we cannot provide any assurance that we will be able to remain in compliance in the future with respect to existing or new laws and regulations or the terms and conditions of required permits or that such future compliance will not have a material adverse effect on our business and operating results.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, amended from time to time, to which our business operations are subject to and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Releases of Oil

The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening U.S. waters, including the Outer Continental Shelf or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill.

OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the Outer Continental Shelf, although the Secretary of Interior may increase this amount up to $150 million in certain situations. The OPA also currently limits the liability of a responsible party for an offshore facility to economic damages, excluding all oil spill response costs, to $75 million, although this limit does not apply if a federal safety, construction or operating regulation was violated. Congress has, from time to time, considered adopting revisions to the OPA to make it more stringent. In the aftermath of the Deepwater Horizon incident in the U.S. Gulf of Mexico, Congress considered a variety of amendments to the OPA, including an increase in the minimum level of financial responsibility to $300 million, an elimination of all liability limitations on damages, and enhancements to safety and spill-response requirements. While the legislation failed to pass, it is possible that similar legislation could be introduced and adopted by Congress in the future. Additional state regulation in these areas is also possible.

If OPA was amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located on the Outer Continental Shelf or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. Any adoption of more stringent financial responsibility, safety or spill response requirements or the elimination of liability limitations under OPA would likely increase the cost of operations for our offshore activities, including insurance costs, and expose us to increased liability, which could have an adverse effect on our results of operations. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be held strictly liable for costs and damages, which could be material to our results of operations and financial position.

Water Discharges

The Federal Clean Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (“EPA”) or an analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal

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penalties, as well as require remedial or mitigation measures, for noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The federal Outer Continental Shelf Lands Act, as amended (“OCSLA”), authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Included among these regulations are requirements mandating the preparation of spill contingency plans and the establishment of air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms and structures. Violations of lease conditions or regulations related to the environment issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.

Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as “hazardous substances.” These classes of persons, referred to as potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at onshore disposal sites owned and operated by others.

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage and disposal of solid and hazardous waste and can require cleanup of hazardous waste disposal sites. While there exists an exclusion under RCRA from the definition of hazardous wastes for certain materials generated in the exploration, development or production of oil and natural gas, these wastes may be regulated by the EPA and state environmental agencies as non-hazardous solid wastes. Other wastes handled at exploration, development and production sites may not fall within this regulatory exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,” thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. In September 2010, a non-governmental organization filed a petition with the EPA, requesting them to reconsider the RCRA exemption for exploration, production and development wastes. To date, the EPA has not taken any action on the petition. If legislation is enacted or regulatory changes adopted that remove this RCRA exemption, it could have a significant impact on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”) which requires federal agencies, including the U.S. Department of Interior (“DOI”), to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits or other approvals that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Air Emissions

The federal Clean Air Act and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. Over the next

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several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues.

Climate Change Legislation and Regulatory Initiatives

In response to certain scientific studies suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”) and including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic changes, the EPA published its finding in December 2009 that emissions of GHGs presented an endangerment to public health and the environment. Based on these findings, the EPA has adopted rules under existing provisions of the Clean Air Act requiring a reduction in emissions of GHGs from motor vehicles and requiring certain construction and operating permit reviews for GHG emissions from certain stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG emission sources in the United States including, among others, certain onshore and offshore oil and natural gas production facilities on an annual basis.

In addition, Congress has, from time to time, actively considered legislation and almost one-half of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

Employee Health and Safety

Our operations are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. In addition, the OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes require that we organize and maintain information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with these applicable requirements.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our compliance with existing requirements has not had a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2013, 2012 and 2011. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2013 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that future compliance with existing environmental laws and regulation or that the passage of new, more stringent environmental laws and regulations in the future will not have a materially adverse effect on our business activities, financial condition or results of operations.

Employees

As of December 31, 2013, we had 152 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good.

Offices

We currently lease approximately 23,000 square feet of office space in Houston, Texas at 11451 Katy Freeway, Suite 500, where our principal offices are located. This lease expires on December 31, 2020. We believe that our facilities are adequate for our current operations and that additional lease space can be obtained if needed.

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Available Information

We are required to file annual, quarterly and current reports and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F. Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.

We also make available on our website at www.blackelkenergy.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website, other than the documents listed below, is not incorporated by reference into this Form 10-K.

Item 1A.    Risk Factors

Risks Related to the Oil and Natural Gas Industry and Our Business

We may be subject to claims and liability as a result of our ownership of the West Delta 32-E Platform, which suffered an explosion and fire in November 2012, resulting in loss of life and other injuries.

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. At the time of the explosion, production on the platform had been shut in while crews of independent contractors performed maintenance and construction on the platform. Three workers died as a result of the explosion and subsequent fire, and others sustained varying degrees of personal injuries. An investigation by the BSEE, in coordination with the U.S. Coast Guard, is ongoing. As a result of the investigation, it is possible that BSEE could issue Incidents of Non-Compliance, assess penalties, enjoin Black Elk from operating part or all of West Delta 32, or take other enforcement action. The United States Chemical Safety and Hazard Investigation Board has also made inquiry regarding the incident, but has not yet formally opened an investigation. Additionally, civil lawsuits relating to the explosion have been filed and are pending in both state and federal courts.

On November 21, 2012, BSEE sent us a letter requiring us to take certain actions and to improve our performance. The letter made reference to, among other things, the November 16, 2012 incident. BSEE stated in the letter that if we did not improve our performance, we would be subject to additional enforcement action up to and including possible referral to the Bureau of Ocean Energy Management to revoke our status as an operator on all of our existing facilities. We have undertaken the actions BSEE required of us in the November 21 letter and have been regularly reporting to BSEE our progress on those required improvements.

As more facts become known, it is possible that we may be required to recognize a liability related to the West Delta 32 Incident, and that liability could be material to our financial position, results of operations or cash flows, including, without limitation, our ability to obtain debt, equity or other financing on acceptable terms, or at all. In addition, our credit agreement contains covenants limiting our ability to incur additional debt or pledge additional assets, subject to exceptions. These limitations could adversely affect our ability to obtain additional financing for any future liabilities that may arise in connection with the West 32 Platform Incident.

We have been named as a defendant in various litigation matters as a result of the West Delta 32 Incident. The outcome of existing and future claims could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

As of April 10, 2013, four civil lawsuits have been filed by certain investors and by or on behalf of certain injured or deceased workers against the Company, entities affiliated with PPVA Black Elk (Equity) LLC, the Company’s majority unit holder, and Iron Island Technologies. The lawsuits assert, among other things, gross mismanagement of the Company, safety violations and personal injuries and wrongful death. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment and/or injunctive relief. For each proceeding, we are currently evaluating the plaintiff’s petitions and determining appropriate courses of response with the aid of legal counsel.

Additional proceedings related to the West Delta 32 Incident may be filed against us. These proceedings may involve civil claims for damages or governmental investigative, regulatory or enforcement actions. The adverse resolution of any proceedings related to the West Delta 32 Incident could subject us to significant monetary damages, fines and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

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The nature of our business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

We are engaged in exploration and development drilling activities, which by their nature carry a high degree of risk. These activities may be unsuccessful for many reasons. Our drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the U.S. Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of an oil or gas well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.

Our business involves a variety of inherent operating risks, including:

• fires;

• explosions;

• blow-outs and surface cratering;

• uncontrollable flows of gas, oil and formation water;

• natural disasters, such as hurricanes and other adverse weather conditions;

• pipe, cement, subsea well or pipeline failures;

• casing collapses;

• mechanical difficulties, such as lost or stuck oil field drilling and service tools;

• abnormally pressured formations; and

• environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures and discharges of toxic gases or well fluids.

If we experience any of these problems, wellbores, platforms, gathering systems and processing facilities could be affected, which could adversely impact our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:

• injury or loss of life;

• severe damage to and destruction of property, natural resources and equipment;

• pollution and other environmental damage;

• clean-up responsibilities;

• regulatory investigations and penalties;

• suspension of our operations; and

• repairs to resume operations.

Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

By conducting operations only along the Texas and Louisiana state waters in the U.S. Gulf of Mexico and adjacent waters on and beyond the Outer Continental Shelf, our lack of diversification may:

• subject us to numerous economic, competitive and regulatory developments, any or all of which may have a substantial adverse impact upon the particular industry in which we operate; and

• result in our dependency upon a single or limited number of hydrocarbon basins.

In addition, the geographic concentration of our properties means that some or all of our properties could be affected by the same event should the U.S. Gulf of Mexico experience:

• severe weather, including tropical storms and hurricanes;

• delays or decreases in production, the availability of equipment, facilities or services;

• delays or decreases in the availability of capacity to transport, gather or process production; or

• changes in the regulatory environment.

Because all our properties could experience the same condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.

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Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are almost exclusively in the U.S. Gulf of Mexico.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. As of December 31, 2013, our estimated total asset retirement obligations were $276.7 million.

Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations may be satisfied many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from severe weather.

In addition to the “Notices to Lessees and Operators” (“NTLs”) discussed below, BOEMRE issued an NTL effective October 15, 2010 that established a more stringent regimen for the timely decommissioning of what is known as “idle iron”—wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease—in the U.S. Gulf of Mexico. Historically, many oil and natural gas producers in the U.S. Gulf of Mexico delayed the plugging, abandoning or removal of such idle iron until they met the final decommissioning regulatory requirement, which had been established as being within one year after the lease expires or terminates, a time period that sometimes was years after use of the idle iron had been discontinued. The determination of productive lease termination dates was generally based on management’s estimate as to when it would become likely that production, including from future development activities, would cease on the lease. The issued NTL, however, set forth more stringent standards for decommissioning timing requirements. Under the new standard, any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations.

The development of any additional requirements imposing an accelerated schedule for the performance of plugging, abandoning and removal activities may materially increase our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. In addition, the potential increase in decommissioning activity in the U.S. Gulf of Mexico over the next few years as a result of the NTL could result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related asset retirement obligations. For additional information about our asset retirement obligations, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Asset Retirement Obligations.”

Oil and natural gas prices are volatile and a decline in oil and natural gas prices would affect our financial results and impede growth.

Our future revenues, profitability and cash flow depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

• domestic and foreign supplies of oil and natural gas;

• price and quantity of foreign imports of oil and natural gas;

• actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

• level of consumer product demand;

• level of global oil and natural gas exploration and production;

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• domestic and foreign governmental regulations;

• level of global oil and natural gas inventories;

• political conditions in or affecting other oil-producing and natural gas-producing countries, particularly those in the Middle East, South America, Africa and Russia;

• weather conditions;

• technological advances affecting oil and natural gas consumption;

• overall U.S. and global economic conditions; and

• price and availability of alternative fuels.

Any substantial or extended decline in oil and natural gas prices would render uneconomic a significant portion of our exploitation, development and exploitation projects. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil or natural gas prices or demand for oil or natural gas may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.

If oil and natural gas prices decline, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.

There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings. We account for our natural gas and oil exploitation and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploitation and development costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings.

Write downs could occur if oil and gas prices decline , if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs , changes in estimate of asset retirement obligations or deterioration in our drilling results. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. It is likely that the cumulative effect of a write-down could also negatively impact the value of our securities.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

We review our oil and gas properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that require us to record an impairment of the book values associated with

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oil and gas properties. For the years ended December 31, 2013 and 2012, we recorded impairments of $79.1million and $31.0 million, respectively.

Our actual recovery of reserves may substantially differ from our proved reserve estimates.

This Form 10-K contains estimates of our oil and natural gas reserves. Estimating oil and natural gas reserves is complex and inherently imprecise and subjective. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary and the accuracy of any reserve estimates and related future production is a function of the quality and reliability of available data and engineering and geological interpretation and judgment. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, which are based on our subjective estimates at the time such assumptions are made. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and natural gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies or variances in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized herein. For example, future production estimated from the development of proved undeveloped reserves is dependent upon an assumed level of development capital expenditures, which may be reduced in the event of declines in oil and gas prices, constraints in capital availability or changes in capital spending priorities. Accordingly, actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary, perhaps significantly, from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploitation and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Consequently, the inclusion of these estimates in this Form 10-K should not be regarded as a representation by us, the placement agents or any other person that the estimates will actually be achieved. You are cautioned not to place undue reliance on the estimates.

As of December 31, 2013, approximately 27% of our total proved reserves were undeveloped and there can be no assurance that all of those reserves will ultimately be developed or produced.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. At December 31, 2013, approximately 27% of our total estimated proved reserves were classified as proved undeveloped ("PUD"). The future development of these undeveloped reserves into proved developed reserves is highly dependent upon our ability to fund estimated total capital development costs. We cannot be sure that these estimated costs are accurate or that we will have the ability to fund the capital expenditures. The lack of access to capital may cause us to write off PUDs as a result of the five year rule. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.

In addition, we have seven offshore federal leases located in the deep waters of the U.S. Gulf of Mexico. We are unsure what effect, if any, the BOEMRE’s regulation of the drilling of wells using BOPs or surface BOPs on a floating facility will have on these leases and our estimated proved reserves. We are also unsure what effect, if any, future amendments to the OPA will have on these leases and our other offshore operations. However, it is possible that due to changes in regulation we will be unable to develop any or all of our proved undeveloped reserves. For additional information, see “—BP PLC’s Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the U.S. Gulf of Mexico, some of which may be unforeseeable” below.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net revenues from our proved reserves (referred to elsewhere as the PV-10 value) is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we currently base the estimated discounted future net revenues from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

• the volume, pricing and duration of our oil and natural gas hedging contracts;

• supply of and demand for oil and natural gas;

• actual prices we receive for oil and natural gas;

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• our actual operating costs in producing oil and natural gas;

• the amount and timing of our capital expenditures and decommissioning costs;

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimate.

We may be limited in our ability to maintain or book additional proved undeveloped reserves under the SEC’s rules.

We have included in this Form 10-K certain estimates of our proved reserves as of December 31, 2013 prepared in a manner consistent with our and our independent petroleum consultant’s interpretation of the SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies. Included within these SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped reserves.

Unless we replace oil and natural gas reserves, our future reserves and production will decline.

Our future oil and natural gas production will depend on our success in finding or acquiring additional reserves. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploitation an development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire additional reserves.

Relatively short production periods or reserve lives for U.S. Gulf of Mexico properties subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the U.S. Gulf of Mexico during the initial few years when compared to other regions in the United States. Typically, 50% of the reserves of properties in the U.S. Gulf of Mexico are depleted within three to four years. Due to high initial production rates, production of reserves from reservoirs in the U.S. Gulf of Mexico generally decline more rapidly than from other producing reservoirs. Our existing operations are in the U.S. Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced

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commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services typically fluctuates based on demand for those services. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our business, financial condition or results of operations.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Prospects that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

Market conditions or transportation impediments may hinder access to oil and natural gas markets or delay production.

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. In offshore operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms that we own or operate or that are owned and operated by others and, where facilities are owned and operated by others, the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut-in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues. Restrictions on our ability to sell our oil and natural gas may have several other adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possible loss of a lease due to lack of production. In the event that we encounter restrictions in our ability to tie our production to a gathering system, we may face considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.

We are not the operator on all our current properties and we will not be the operator on all of our future properties and therefore will not be in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on certain of such properties.

As of December 31, 2013, we operated approximately 50% of the fields and 47% of the wells in our asset portfolio; however, as we carry out our planned drilling program, we will not serve as operator of all planned wells. We conduct and will conduct many of our operations through joint ventures in which we share control with other parties. We are not the well operator for several of our joint ventures. There is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with those of the project or us. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

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• the timing and amount of capital expenditures;

• the availability of suitable drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

• the operator’s expertise and financial resources;

• approval of other participants in drilling wells;

• selection of technology; and

• the rate of production of the reserves.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Over the past several years, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of our vendors’, customers’ and counterparties’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors, customers and counterparties liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could reduce our cash flows.

Our offshore operations involve special risks that could affect our operations adversely.

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.

Our insurance may not protect us against all business and operating risks.

We do not maintain insurance for all of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially and, in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Therefore, we will not be fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.

As a result of a number of catastrophic events like the terrorist attacks on September 11, 2001 and Hurricanes Katrina, Rita, Gustav and Ike, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered extensive damage from Hurricanes Katrina, Rita, Gustav and Ike. As a result, insurance costs have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is as severe as it was in 2005, insurance underwriters may no longer insure U.S. Gulf of Mexico assets against weather-related damage. Our business interruption insurance may not be economically available in the future, which could adversely impact business prospects in the U.S. Gulf of Mexico and adversely impact our operations. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

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We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

• our ability to acquire seismic data;

• our ability to obtain leases or options on properties for which we have seismic data;

• our ability to identify and acquire new properties;

• our ability to develop existing prospects;

• our ability to continue to retain and attract skilled personnel;

• our ability to maintain or enter into new relationships with project partners and independent contractors;

• the results of our drilling program;

• hydrocarbon prices; and

• our access to capital.

We may not be successful in upgrading our technical, operations and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.

We are dependent on contractors and sub-contractors for our daily operational and service needs on individual fields and platforms. If these parties fail to satisfy their obligations to us or if we are unable to maintain these relationships, our revenue, profitability and growth prospects could be adversely affected.

We depend on a limited number of contractors and subcontractors in conducting our business. If one or more of these subcontractors experience financial or operational difficulties, we could experience an interruption in our operations. There is a risk that we may have disputes with our subcontractors arising from, among other things, the quality and timeliness of work performed by the subcontractors. Although we believe alternative subcontractors are available, our operating results could temporarily suffer until we engage one or more of those alternative subcontractors. Moreover, in engaging alternative subcontractors in exigent circumstances, our production costs could increase markedly.

Sales to a small number of customers represent a substantial portion of our revenues. The loss of any of our major customers could significantly harm our financial condition.

We derive a substantial portion of our revenues from a relatively small number of customers. For the year ended December 31, 2013, Shell Trading (US) Company was our largest purchaser of oil and natural gas, accounting for approximately 62% of our revenues, with United Energy Trading, LLC as the next largest purchaser, accounting for approximately 6% of our revenues. It is likely that a small number of customers will continue to account for a substantial portion of our revenues in the future. If we were to lose one of our major customers or experience a deterioration in our relationships with any of these customers, our financial condition could be significantly harmed. Additionally, if any of our top customers were to suffer financial difficulties, whether as a result of downturns in the markets, loss of market share in which they operate or otherwise, our financial condition could be significantly harmed.

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

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

Risks Related to Our Indebtedness and Access to Capital and Financing

Our level of indebtedness and our negative working capital may limit our ability to borrow additional funds, fund our

operations or capitalize on acquisition or other business opportunities.

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We had outstanding indebtedness under our Indenture of $149.5 million. We had a net working capital deficit of approximately $109.5 million at December 31, 2013. In March 2014 we paid all outstanding indebtedness under our revolving credit facility and terminated the facility. 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 during 2013. To increase liquidity, we stretched accounts payable, aggressively pursued accounts receivable and sold assets. Liquidity is essential in our business, and our inability to pay trade creditors in a timely manner could impair our ability to develop and operate our properties.

Our substantial indebtedness and our negative working capital could have adverse consequences.

• For example, it could: impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general business activities or other purposes;

• increase our vulnerability to general adverse economic and industry conditions;

• result in higher interest expense in the event of increases in interest rates since some of our debt is at variable rates of interest;

• have a material adverse effect if we fail to comply with financial and restrictive covenants in any of our debt agreements, including an event of default if such event is not cured or waived;

• require us to dedicate a substantial portion of future cash flow to payments of our indebtedness, accounts payable and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate requirements;

• limit our flexibility in planning for, or reacting to, changes in our business and industry; and place us at a competitive disadvantage to those who have proportionately less debt.

If we are unable to meet future debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity or sell assets. We may then be unable to obtain such financing or capital or sell assets on satisfactory terms, if at all.

The covenants in the Indenture governing the Notes and our credit facility could negatively impact our financial condition,results of operations and business prospects and prevent us from fulfilling our obligations under the notes.

The covenants contained in the Indenture governing the Notes and the agreement governing our credit facility could have

important consequences for our operations, including:

• limiting our ability to use our cash flow from operations for capital expenditures;

• requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness,

• thereby reducing the availability of cash flow for working capital, capital expenditures and other general business

• activities;

• limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions

• and general corporate and other activities;

• limiting management’s discretion in operating our business;

• limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• limiting our ability to hedge our production;

• detracting from our ability to withstand successfully a downturn in our business or the economy generally; and

• placing us at a competitive disadvantage against less leveraged competitors.

If we breach any covenants under our Indenture or credit facility, a default could occur. We obtained a limited waiver from our lenders relating to such covenants for the fiscal quarter ending December 31, 2013. The waiver will not apply to any future fiscal quarter.

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In the future, if we breach a covenant, or are otherwise in default under our Indenture or credit facility, and we are unable to obtain a waiver, certain of our debt holders would be entitled to declare all amounts borrowed under the breached agreement to become immediately due and payable, which could also cause the acceleration of obligations under certain other agreements and/or the termination of the agreement. In the event of acceleration of our outstanding indebtedness, we cannot assure that we would be able to repay our debt or obtain new financing to refinance our debt. Even if new financing is made available to us, it may not be on terms acceptable to us.

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

Our ability to make payments on our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash in the future. We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may be required to:

• refinance all or a portion of our debt;

• obtain additional financing;

• sell some of our assets or operations;

• reduce or delay capital expenditures, research and development efforts and acquisitions; or

• revise or delay our strategic plans.

If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure that we would be able to take any of these actions, that these actions would enable us to continue to satisfy our capital requirements or that these actions would be permitted under the terms of the our various debt instruments.

We have substantial P&A obligations and 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.

As of December 31, 2013, our estimated total asset retirement obligations were $276.7 million. Development of any legal requirements imposing an accelerated schedule for the performance of plugging, abandoning and removal activities, such as the BOEMRE NTL issued on September 15, 2010, may materially increase our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. (For additional information, see “—Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are almost exclusively in the U.S. Gulf of Mexico”).

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. 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.

We also have various obligations to fund escrow accounts for future P&A costs that may be incurred on properties that we have acquired. Many of these escrow accounts have been fully funded or secured by the issuance of performance bonds to guaranty our performance of the related P&A obligations. With respect to our acquisition of properties from W&T Offshore, Inc., as of December 31, 2013, we had funded $17.5 million into a non-operating escrow account, and are obligated to fund an additional $13.7 million in the escrow account through May 1, 2017.

We may not be able to obtain funding in the capital markets on terms we find acceptable

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The credit crisis and related turmoil in the global financial systems during 2008-09 had an impact on our business and our financial condition, and we may face additional challenges if economic and financial market conditions deteriorate in the future.

Historically, we have used contributions from our members, cash flow from operations and borrowings under our credit facility to fund our capital expenditures. We are currently unable to borrow any additional amounts under our credit facility. Our credit facility matures on January 1, 2015 and our Notes are payable in full on December 1, 2015.

Further, the credit crisis in 2008-09 made it more difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets increased substantially while the availability of funds from those markets generally diminished significantly. Also, as a result of concerns about the general stability of financial markets and the solvency of specific counterparties, the cost of obtaining money from the credit markets increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity or on terms similar to existing debt or at all, or, in some cases, ceased to provide any new funding. A return of these conditions could materially and adversely affect our company.

We and our subsidiaries may be able to incur substantially more debt. This could further increase our leverage and

attendant risks.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the Indenture governing our Notes and our credit facility do not fully prohibit us or our subsidiaries from doing so. At December 31, 2013, we and our subsidiaries collectively had approximately:

• $183.9 million of secured indebtedness, net of unamortized discounts; and

• $0.3 million of unsecured short-term indebtedness.

If new debt or liabilities are added to our current debt level, the related risks that we now face could increase.

An increase in interest rates may increase the cost of servicing our indebtedness and could reduce our profitability.

Indebtedness we may incur under our credit facility bears interest at variable rates. As a result, any increase in interest rates, whether because of an increase in market interest rates or an increase in our own cost of borrowing, would increase the cost of servicing our indebtedness and could materially reduce the availability of debt financing, which may result in increases in the interest rates and borrowing spreads at which lenders are willing to make future debt financing available to us. The impact of such an increase would be more significant than it would be for some other companies because of our substantial indebtedness.

Our exploitation, development and production projects require substantial capital expenditures. We may be unable to obtain necessary capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploitation, development, production and acquisition of oil and natural gas reserves. Improvement in commodity prices may result in an increase in our actual capital expenditures. Conversely, a significant decline in product prices could result in a decrease in our capital expenditures. We intend to finance our future capital expenditures primarily through cash flows from operations and contributions from our members. Our financing needs may require us to alter or increase our capitalization substantially. The issuance of additional debt may require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

• our proved reserves;

• the level of oil and natural gas we are able to produce from existing wells;

• the prices at which our oil and natural gas are sold;

• our ability to locate, acquire and produce new reserves;

• the willingness of the lenders under our credit facility to lend; and

• our access to capital and ability to obtain financing.

If our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by operations is not sufficient to meet

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our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves and could adversely affect our business, financial condition and results of operations.

Risks Related to Our Risk Management Activities

Our hedging activities could result in financial losses or could reduce our net income.

To achieve more predictable cash flows and to reduce the impact of oil and natural gas price volatility on our operations, we have and may continue to enter into hedging arrangements for a significant portion of our oil and natural gas production.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:

• a counterparty may not perform its obligation under the applicable derivative instrument;

• production is less than expected;

• there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

• the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Oil and Natural Gas Hedging” for additional information on our oil and natural gas hedges.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of falling commodity prices, such as in late 2008, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

If we are unable to effectively manage the commodity price risk of our production if energy prices fall, our anticipated cash flows will be negatively impacted.

Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Therefore, there is the possibility that we may be unable to find counterparties willing to enter into derivative arrangements with us or be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we fail to manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves.

Risks Related to Our Acquisition Strategy

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We plan to pursue acquisitions as part of our growth strategy and there are inherent risks in connection with the acquisition of oil and natural gas properties, including that the acquisition may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our growth has been attributable in large part to acquisitions of producing properties and undeveloped leasehold interests. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. The terms of the Indenture governing the Notes and our credit facility contain restrictive covenants that limit our ability to finance acquisitions and other investments and to engage in other activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of our debts. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.

Successful acquisitions of oil and natural gas properties require an assessment of numerous factors that are inherently inexact and may be inaccurate, including, without limitation, those relating to:

• acceptable prices for available properties;

• amounts of recoverable reserves;

• estimates of future oil and natural gas prices;

• estimates of future exploratory, development and operating costs;

• estimates of the costs and timing of plugging and abandonment; and

• estimates of potential environmental and other liabilities.

In connection with such a potential acquisition, we perform a review of the subject properties that we believe is generally consistent with industry practices. However, such assessments are inexact and their accuracy is inherently uncertain and such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made. We are generally not able to obtain contractual indemnification for pre-closing liabilities, including environmental liabilities, and we normally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are primarily located in the U.S. Gulf of Mexico, we may pursue acquisitions or properties located in other geographic areas.

Our acquisition strategy may be stretching our existing resources.

Since our inception, we have made three major acquisitions, the W&T Acquisition, the Nippon Acquisition, and the Merit Acquisition, among other smaller acquisitions. Future transactions may prove to stretch our internal resources and infrastructure. As a result, we may need to invest in additional resources, which will increase our costs. Any further acquisitions we make over the short term would likely exacerbate these risks.

Competition for oil and natural gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors are major or independent oil and natural gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than us. We actively compete with other companies when acquiring new leases or oil and natural gas properties. For example, new offshore leases may be acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay. If we are unable to compete successfully for acquisitions, our future revenues and growth may be diminished or restricted.

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Risks Related to Environmental and Other Regulations

Our operations may incur substantial costs and expenses to comply with environmental and other government laws and regulations.

Oil and natural gas exploration, development and production operations in the United States and the U.S. Gulf of Mexico are subject to extensive federal, regional, state and local laws and regulations. Companies operating in the U.S. Gulf of Mexico are subject to laws and regulations that (1) address, among other items, land use and lease permit restrictions, bonding and other financial assurance mechanisms related to drilling and production activities, spacing of wells, unitization and pooling of properties, plugging and abandonment of wells and removal of associated infrastructure after production has ceased, operational reporting and taxation, and environmental and occupational health and safety matters; and (2) impose liability for, and require investigation and remediation of, releases of oil and hazardous or other regulated substances, including at third-party owned off-site disposal facilities where we may have disposed of wastes, and could expose us to significant incurred expenses and damages, including natural resource damages, and fines and penalties for any violation or noncompliance with any of the applicable laws or regulations.

We may incur significant capital and operating expenditures or perform other corrective actions at our wells and facilities to comply with the requirements of these environmental and occupational health and safety laws and regulations or the terms or conditions of permits issued pursuant to such requirements. Our compliance with future laws or regulations, or with any adverse change in the interpretation or enforcement of existing laws and regulations, could increase such compliance costs. Regulatory limitations and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations.

Additionally, our oil and natural gas exploitation, development and production operations are subject to stringent laws and regulations governing the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things:

• require the acquisition of a permit before drilling or other regulated activities commence;

• restrict the types, quantities and concentration of materials that can be released into the environment in connection with drilling and production activities;

• limit or prohibit exploration or drilling activities on certain environmentally sensitive protected areas that may affect certain species, including marine mammals;

• impose substantial liabilities for pollution resulting from our operations; and

• apply specific health and safety criteria addressing worker protection.

Costs and liabilities could arise under a wide range of federal, regional, state and local environmental laws and regulations that are amended from time to time, including, for example:

• the OPA and comparable state laws that impose a variety of requirements and liabilities related to the prevention of and response to oil spills into waters of the United States, including the Outer Continental Shelf, on lessees and operators of offshore leases and owners and operators of oil handling facilities, including requiring owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill;

• the DOI, Bureau of Ocean Energy Management (“BOEM”) or BSEE NTLs and other standards issued thereunder, that relate to offshore oil and natural gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages;

• the Clean Air Act and comparable state laws and regulations that restricts the emission of air pollutants from many sources and impose various pre-construction, monitoring and reporting requirements;

• the Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

• the RCRA and comparable state laws that impose requirements for the generation, storage, treatment and disposal of solid waste, including hazardous waste, from our facilities;

• the CERCLA and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent wastes for disposal;

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• the Federal Safe Drinking Water Act (“SWDA”), which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below ground formations that may adversely affect drinking water sources;

• the EPA community right to know regulations under Title III of CERCLA and similar state statutes that require us to organize and/or disclose information about hazardous materials used or produced in our operations;

• the OSHA and comparable state laws, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances and appropriate control measures; and

• the Marine Mammal Protection Act, which ensures the protection of marine mammals through the prohibition, with certain exceptions, of the taking of marine mammals in U.S. waters and by U.S. citizens on the high seas and that may require the implementation of operating restrictions or a temporary, seasonal or permanent ban in the affected areas.

We may be required to make significant capital and operating expenditures at our wells and platforms to comply with the requirements of these environmental laws and regulations. Failure to comply with these laws and regulations or the terms or conditions of required environmental permits may result in the assessment of administrative, civil and/or criminal penalties; the imposition of investigatory or remedial obligations as well as corrective actions; and the issuance of injunctions limiting or prohibiting some or all of our operations.

Changes in environmental or occupational health or safety laws, regulations or enforcement policies occur frequently, and any changes that result in more stringent or costly well construction, drilling or completion activities, or waste handling, storage, transport, disposal or cleanup requirements or other unforeseen liabilities could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. The costs of complying with applicable environmental laws and regulations are likely to increase over time and we cannot provide any assurance that we will be able to remain in compliance with respect to existing or new laws and regulations or that such compliance will not have a material adverse effect on our business, financial condition and results of operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbon and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical operations and waste disposal practices. Under certain environmental laws and regulations that impose strict, joint and several liability, we may be required to remediate spill incidents or contamination regardless of whether such spills or contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws and regulations at the time those actions were taken. In addition, claims for damages to persons, property or natural resources may result from spill incidents or other environmental impacts of our operations. Future spills or releases of regulated substances or accidents or the discovery of currently unknown contamination could expose us to material losses, expenditures and environmental or occupational health and safety liabilities, including liabilities resulting from lawsuits brought by private litigants for personal injury or property damage related to our operations or the area upon which our operations are conducted. We may not be able to recover some or any of these costs from insurance. See “Business—Environmental Matters and Regulation.”

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act requires the Commodities Futures Trading Commission ("CFTC") and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter-derivatives market and entities, that participate in that market, including swap clearing and trade execution requirements. Our derivative transactions are not currently subject to such swap clearing and trade execution requirements; however, in the event our derivative transactions potentially become subject to such requirements, we believe that our derivative transactions would qualify for the "end-user" exception. New or modified rules, regulations or requirements may increase the cost and availability to our counterparties of their hedging and swap positions that they can make available to us, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, that may not be as creditworthy as the current counterparties. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation or post margin collateral. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.

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While many rules and regulations have been promulgated and are already in effect, other rules and regulations, including the proposed margin rules, remain to be finalized or effectuated; therefore, the impact of those rules and regulations on us is uncertain at this time. The Dodd-Frank Act, and the rules promulgated thereunder, could (1) significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting,or decrease the liquidity, of energy-related derivatives we use to hedge against commodity price fluctuations (including through requirements to post collateral, which could adversely affect our available liquidity), (2) materially alter the terms of derivative contracts, (3) reduce the availability of derivatives to protect against risks we encounter, and (4) increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and applicable rules and regulations, our cash flow may become more volatile and less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas liquids and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas liquids and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted rules under the Clean Air Act requiring a reduction in emissions of GHGs from motor vehicles and requiring certain construction and operating permit reviews for GHGs from certain stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG emission sources in the United States including, among others, certain onshore and offshore oil and natural gas production facilities on an annual basis.

In addition, from time to time, Congress has considered legislation and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Risks Related to Our Relationship with Platinum

Platinum owns approximately 85% of our outstanding voting membership interests, giving it influence and control in corporate transactions and other matters, which may conflict with noteholders’ interests.

As of December 31,2013, Platinum beneficially owned approximately 85% of our outstanding voting membership interests and approximately 66% of our total outstanding membership interests. As a result, and for as long as Platinum holds a membership interest in us, Platinum has the ability to remove and appoint key personnel, including all of our managers, and to determine and control our company and management policies, our financing arrangements, the payment of dividends or other distributions, and the outcome of certain company transactions or other matters submitted to our members for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. As a controlling member, Platinum could make decisions that may conflict with noteholders’ interests.

Pursuant to our Second Amended and Restated Limited Liability Company Operating Agreement (as amended and in effect as of the date hereof), if we propose to obtain additional financing through the issuance of equity or certain debt securities, Platinum is entitled to a right of first offer to provide such financing. Platinum and the other members also have, pursuant to that agreement, the right of first refusal with respect to any proposed transfer of our equity interests.

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Item 1B.    Unresolved Staff Comments

None.

Item 2.        Properties

The information required by this Item 2. is contained in “Item 1. Business” and is incorporated herein by reference.

Item 3.        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 mentioned 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 stipulates that contractor Wood Group Production Service Network and Black Elk Energy be issued the additional following types of Incidents of Non-Compliance (INCs): 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. Although the report states that BSEE will issue INCs 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 has and continues to carefully review the BSEE Panel Report 2013-002.

The United States Chemical Safety and Hazard investigation board has also made an inquiry of upon Black Elk Energy 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. Further, on March 25, 2014, a second subpoena was issued by the U.S. Attorney’s Office requesting records and documents for specific time periods still part of their investigation of the WD-32 incident. We are fully cooperating with all government agencies.

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

• Independent Third-Party SEMS Audit

• Enhanced oversight of work on our operated platforms

• Hazard Recognition

• Compliance

• Reduction of Incidents of Non-Conformance (INCs)

• Stop Work Authority

In a meeting held at the BSEE Regional Office on October 30, 2013, BEEOO shared with BSEE representatives that implementation of corrective actions (18 elements and 58 tasks) associated with the Performance Improvement Plan ("PIP") has been 100% completed. Other essential work control processes such as our Project Execution Plans and Contractor Bridging Agreements have been improved to provide better guidelines and procedures for hazard assessment and work controls. Training in Hazard Recognition, National Pollutant Discharge Elimination System ("NPDES"), Job Safety Analysis ("JSA") and Stop Work Authority ("SWA") will be ongoing and has been incorporated into our training matrix.

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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.

Civil Litigation. As of December 31, 2013, several civil lawsuits have been filed as a result of the West Delta 32 Incident- involving personal injury and three fatalities. 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. The plaintiffs are seeking an unspecified amount of actual and punitive damages. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.

On January 31, 2013, the family of decedent Jerome Malagapo sued BEEOO in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Malagapo’s wife individually and on behalf of his estate and Mr. Malagapo’s children. The plaintiffs allege that Mr. Malagapo was employed by Grand Isle Shipyard, Inc. and was working on the West Delta 32 Block Platform and as a result of the incident died. The plaintiffs are seeking an unspecified amount of actual and punitive damages.

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

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

As previously reported, on March 22, 2013, six investors in Black Elk Energy, LLC (“BEE”) filed a purported derivative complaint on behalf of BEE in the Supreme Court of the State of New York, County of New York, against the Company, John Hoffman, Iron Island Technologies Inc., and various entities and individuals associated with the Company’s majority unit owner (the “Platinum Defendants”). The lawsuit seeks unspecified damages allegedly arising from (1) the dilution of BEE’s ownership interest in the Company through various financing transactions with the Platinum Defendants and the issuance of membership units under management and employee incentive programs; and (2) the alleged mismanagement of the Company in connection with certain alleged safety violations and the West Delta 32 Incident. We believe there are strong defenses to the claims asserted in the lawsuit, and the Company intends to defend the case vigorously. On or about September 24, 2013, Plaintiffs filed a motion for a preliminary injunction to restrain a portion of the proceeds of the Company’s proposed sale of certain oil fields in the Gulf of Mexico. The Court denied the motion on November 15, 2013. On or about November 20, 2013, we filed a motion to dismiss the complaint in its entirety, inter alia, on the grounds that (i) the claims fail to state a cause of action; (ii) the claims are refuted by documentary evidence; (iii) plaintiffs, who are not members of the Company, lack standing to assert a claim for mismanagement of the Company; and (iv) certain claims are barred by the statute of limitations. The motion is now fully briefed. Discovery is at an early stage, with the parties beginning to make rolling document productions.

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 which took place on November 12, 2013. Since the mediation was unsuccessful, the Parties have now agreed to enter into binding Arbitration pursuant to and in accordance with the MSA. Black Elk Energy has named Compass Consultants LLC as party to the AAA Arbitration in addition to GIS. Compass filed a lawsuit against Black Elk Energy (W.Dist. Of La.) seeking to enjoin the proceedings in the referred Arbitration case. The Arbitration proceedings are underway.

For each proceeding, we are currently evaluating the plaintiff’s petitions and determining appropriate courses of response with the aid of legal counsel. These proceedings are at a preliminary stage; accordingly, we currently cannot assess the probability of

35

losses, or reasonably estimate a range of any potential losses related to the proceedings. We intend to vigorously defend the Company in these proceedings.

Other Regulatory Items. As of December 31, 2013, we received a Notice of Proposed Civil Penalty Assessment from BSEE that administrative civil penalty proceedings had been initiated for two civil violations. As part of the civil penalty(s), we requested an informal meeting to present factual information to the reviewing officer that should serve to mitigate the proposed civil penalty of $71,250 and $100,000 respectively.

We are also subject to certain other environmental matters and regulations. For a discussion of these items, see Item 1.“Business—Environmental Matters and Regulation.”

Item 4.        Mine Safety Disclosures

Not applicable.

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PART II

Item 5.        Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

We are a privately held company and there is no established public trading market for our membership interests.

Item 6.        Selected Financial Data

Set forth below is our summary historical consolidated financial data for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, and balance sheet data at December 31, 2013, 2012, 2011, 2010 and 2009. This information may not be indicative of our future results of operations, financial position and cash flows and should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere in this Form 10-K. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable.

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	Year Ended December 31,
	2013			2012			2011			2010			2009
STATEMENTS OF OPERATIONS DATA (in thousands):
Crude oil, natural gas and plant product sales	$	265,336		$	285,897		$	314,289		$	112,566		$	20,788
Realized (loss) gain on derivative financial instruments	(1,522		)	23,364			8,099			9,271			801
Unrealized (loss) gain on derivative financial instruments	(5,806		)	(4,783		)	17,556			(12,700		)	(1,955		)
Total revenue	258,008			304,478			339,944			109,137			18,833
Operating Expenses:
Lease operating costs, workovers and production taxes	186,062			199,422			182,789			59,555			10,043
Exploration	200			1,682			1,004			14			47
Depreciation, depletion and amortization	43,606			47,314			47,214			29,795			15,419
Impairment	79,090			31,033			12,967			6,407			446
General and administrative	36,601			26,486			22,029			14,588			7,164
Gain due to involuntary conversion of asset	(17,827		)	(3,100		)	—			—			(18,718		)
Accretion	23,454			36,421			27,410			9,175			388
Gain on sale of asset	(105,771		)	38			(142		)	—			—
Other Operating Expense	8,061			—			—			—			—
Total operating expenses	253,476			339,296			293,271			119,534			14,789
Income (loss) from operations	$	4,532		$	(34,818	)	$	46,673		$	(10,397	)	$	4,044
Operating Data:
Oil (MBbl) (1)	1,730			1,977			1,991			857			140
Natural gas (MMcf) (1)	13,294			17,884			18,188			7,997			2,444
Plant products (MGal) (1)	8,854			13,588			12,257			5,403			320
Oil:
Average price before effects of hedges ($/Bbl)	$	105.60		$	106.60		$	108.09		$	80.09		$	70.43
Average price after effects of hedges ($/Bbl)	102.17			110.18			105.17			80.97			71.59
Average price differentials	7.59			12.50			13.04			0.59			8.44
Natural Gas:
Average price before effects of hedges ($/Mcf)	$	3.88		$	2.82		$	4.18		$	4.38		$	4.29
Average price after effects of hedges ($/Mcf)	4.21			3.73			4.94			5.44			4.55
Average price differentials	0.15			0.07			0.18			—			0.34

___________________________________

(1) Total production for each of the periods presented.

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	As of December 31,
	2013		2012			2011				2010		2009
BALANCE SHEET DATA (in thousands):
Cash and cash equivalents	6,227		1,383			17,260				18,879		6,236
Oil and natural gas properties, net	196,136		260,012			238,702				123,783		88,600
Total assets	565,614		590,464			546,006				306,504		114,009
Total debt, including current portion	184,186		204,670			177,041				150,753		40,133
Asset retirement obligations (net of escrow)	(1,065	)	109,894		(1)	96,185		(1	)	8,074		45,431
Members’ equity (deficit)	(172,675	)	(118,467	)		(29,708	)			(20,610	)	5,723

	Year Ended December 31,
	2013			2012			2011			2010			2009
OTHER FINANCIAL DATA (in thousands):
Net cash provided by (used in) operating activities	$	(21,688	)	$	66,054		$	73,647		$	28,345		$	(528	)
Net cash used in investing activities	(133		)	(89,723		)	(108,641		)	(114,815		)	(27,415		)
Net cash provided by (used in) financing activities	26,665			7,792			33,375			99,113			32,532
Adjusted EBITDA (2)	45,068			78,995			110,686			47,052			4,617

___________________________________

(1) Amount also net of asset retirement obligation escrow receivable as it relates to P&A obligations.

(2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss), see “—Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” below.

Item 7. 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-K. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed, particularly in “Item 1A. Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

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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 December 31, 2013, we held an aggregate net interest in approximately 457,065 gross (223,852net) acres under lease and had an interest in 113 gross wells, 93 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 years ended as of December 31, 2013, 2012 and 2011 are shown in the table below.

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	Year Ended December 31,
	2013		2012		2011
Oil:
Average price before effects of hedges ($/Bbl) (1)	$	105.60	$	106.60	$	108.09
Average price after effects of hedges ($/Bbl)	102.17		110.18		105.17
Average price differentials (2)	7.59		12.50		13.04
Gas:
Average price before effects of hedges ($/Mcf) (1)	$	3.88	$	2.82	$	4.18
Average price after effects of hedges ($/Mcf)	4.21		3.73		4.94
Average price differentials (2)	0.15		0.07		0.18

___________________________________

(1) Realized oil and natural gas prices do not include the effect of cash received or paid upon derivative contract settlements.

(2) Price differential compares realized oil and natural gas prices, without giving effect to cash received or paid upon 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. See “Item 1A. Risk Factors—If oil and natural gas prices decline, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of our outstanding debt obligations and negatively impacting the trading value of our securities.”

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

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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. The claim has been finalized. We received a total of approximately $24.1 million, net of the deductible, in cash for the claim.

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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 has increased to 36% on March 25, 2014 to 36% per annum (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement). For the year ended December 31, 2013, we issued an additional amount of Class E Units of approximately 16.7 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 Waivers And Amendment

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

On November 14, 2013, we entered into the Waiver and Tenth Amendment to 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.

Revolving Credit Facility Waivers and Amendments

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.

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 $34.5 million outstanding. Subsequently, the borrowing base was increased to $47 million on October 15, 2013. As of December 31, 2013, we had $34.5 million drawn on the Credit Facility.

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Drilling Update

We successfully completed eight wells and had one drilling rig on a non-operated property as of December 31, 2013. All of the completed wells encountered pay equal to or above our expectations.

Liquidity Risks and Uncertainties

While cash flows were lower than previously projected primarily due to lower production and sales of assets in the 3rd and 4th quarters, we continued our development operations by supplementing our cash flows from operating activities with funds raised through borrowings in 2013 and capital contributions from our members. We retained financial and technical advisors to provide recommendations on achieving improvements in production, operating expense, cash flows from operations, work over, capital expenditures and business planning. We have significantly reduced our workforce and associated general and administrative expenses to match out lower production.

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $(109.5) million at December 31, 2013 and we incurred net losses of $32.9 million during the year ended December 31, 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 our surety bonds that secure our P&A obligations led to significant cash reductions in the year 2013. To increase liquidity, we stretched accounts payable, aggressively pursued accounts receivable and sold non-core assets. We have worked closely with our vendors during this time and are working to normalize the age of accounts payables.

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

Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our plugging and abandonment (“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 our surety bonds for P&A obligations. We are currently in discussions with surety agencies to replace the 100% cash-backed letters of credit. There can be no assurance as to the availability or terms upon which such equity or debt funding might be available.

Our capital budget may be adjusted in the future as business conditions warrant and the ultimate amount of capital we expend may fluctuate materially based on market conditions.

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

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

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

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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.

Health, Safety, and Environmental Program Update

Our Health, Safety and Environmental (“HS&E”) Program is managed by a team of experienced professionals with specialized skills in the areas of health, safety, environmental, compliance and facility security. In certain circumstances, we employ third party consultants to supplement our resource needs.

For our U.S. Gulf of Mexico operations, we have developed and implemented a Regional Oil Spill Response Plan. Our response team implementing this Regional Oil Spill Response Plan is a trained work force that receives training updates annually and performs annual spill drills as required by the BSEE. In addition, we have Environmental Safety & Health Consulting Services, Inc. (“ES&H”), our designated Oil Pollution Act spill response contractor on contractual retainer. ES&H maintains 24 hour, seven day a week manned incident command centers located in Houston, Texas and Houma, Louisiana. ES&H commences spill response activities on our behalf upon our notification of an emergency. While we focus on source control of the spill, ES&H handles all communication with state and federal agencies as well as U.S. Coast Guard and BSEE notifications. ES&H maintains a staff and equipment inventory that is available upon notice to respond to an emergency.

We are also a member of Clean Gulf Associates (“CGA”). CGA was formed in 1972 and currently has 140 member companies, making the association the largest oil spill response cooperative in terms of membership in North America. CGA specializes in onsite control and cleanup and is on 24 hour, seven days a week alert with equipment currently stored at six bases situated along the U.S. Gulf of Mexico coast (Ingleside, Texas, Galveston, Texas, Lake Charles, Louisiana, Houma, Louisiana, Venice, Louisiana and Pascagoula, Mississippi), and is opening new sites in Leeville, Louisiana, Morgan City, Louisiana and Harvey, Louisiana. The CGA equipment inventory is available to serve member oil spill response needs including blowouts; open seas, near shore and shallow water skimming; open seas and shoreline booming; communications; dispersants; boat spray systems to apply dispersants; wildlife rehabilitation; and a forward command center. CGA has contractual retainers with an aerial dispersant company and a company that provides mechanical recovery equipment for spill responses. CGA equipment includes:

• HOSS Barge—the largest purpose-built skimming barge in the United States with 4,000 barrels of storage capacity;

• Fast Response System—a self-contained skimming system for use on vessels of opportunity. CGA has nine of these units; and

• Fast Response Vessels (“FRV”)—four 46-foot FRVs with cruise speeds of 20-25 knots that have built-in skimming troughs and cargo tanks, outrigger skimming arms, navigation and communication equipment.

In addition, source control support is provided, as necessary, by Boots & Coots, Inc., a provider of firefighting, well control, engineering, and training services.

On September 30, 2010, the BOEMRE announced a final SEMS rule that became effective November 15, 2010. The final SEMS rule required implementation of the following 13 elements of the American Petroleum Institute’s Recommended Practice 75 by no later than November 2011:

• Management commitment program principles,

• Safety and environmental information,

• Hazards analyses,

• Management of change,

• Operating procedures,

• Safe work practices and contractor selection,

• Training,

• Mechanical integrity,

• Pre-Startup review,

• Emergency response and control,

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• Investigation of accidents,

• Audits, and

• Records and documentation.

On November 3, 2011, we participated in an audit exercise with BOEMRE in their Herndon, VA office. There were no significant issues or deficiencies noted during this exercise. We believe we are currently in material compliance with the SEMS requirements.

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 years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
	2013			2012			2011
Average daily sales:
Oil (Boepd)	4,741			5,401			5,455
Natural gas (Mcfpd)	36,421			48,865			49,829
Plant products (Galpd)	24,256			37,125			33,580
Oil equivalents (Boepd)	11,388			14,429			14,559
Average realized prices (1):
Oil ($/Bbl)	$	102.17		$	110.18		$	105.17
Natural gas ($/Mcf)	4.21			3.73			4.94
Plant products ($/Gallon)	0.90			1.02			1.29
Oil equivalents ($/Boe)	57.90			56.50			59.30
Costs and Expenses:
Lease operating expense ($/Boe)	42.63			34.22			29.83
Production tax expense ($/Boe)	0.15			0.14			0.16
General and administrative expense ($/Boe)	8.81			5.02			4.15
Net (loss) income (in thousands)	(32,917		)	(63,968		)	15,041
Adjusted EBITDA (2) (in thousands)	45,068			78,995			110,686

___________________________________

(1) Average realized prices presented give effect to the cash paid or received upon commodity derivative settlements.

(2) Adjusted EBITDA is defined as net (loss) income before interest expense, net; surety and letter of credit fees; West Delta 32 costs; net gain (loss) on derivative instruments; cash paid or received upon commodity derivative settlements; accretion of asset retirement obligations; depreciation, depletion, and amortization; impairment of oil and gas properties; gain on involuntary conversion of assets; provision for doubtful accounts and loss/gain on sale of assets. Adjusted EBITDA is not a measure of net (loss) income or cash flows as determined by GAAP, and should not be considered as an alternative to net (loss) income, operating (loss) income or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as a measure of our liquidity. We present Adjusted EBITDA because it is frequently used by securities analysts, investors and other interested parties in the evaluation of high-yield issuers, many of whom present Adjusted EBITDA when reporting their results. Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results or cash flows as reported under GAAP. Because of these limitations, Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. Our presentation of Adjusted EBITDA should not be construed as an inference that our future results will be unaffected by unusual or nonrecurring items. A reconciliation table is provided below to illustrate how we derive Adjusted EBITDA.

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	Year Ended December 31,
	2013			2012			2011
Net (loss) income	$	(32,917	)	$	(63,968	)	$	15,041
Adjusted EBITDA	$	45,068		$	78,995		$	110,686
Reconciliation of Net income (loss) to Adjusted EBITDA:
Net (loss) income	$	(32,917	)	$	(63,968	)	$	15,041
Interest expense	26,478			25,965			25,752
Surety and letter of credit fees	8,828			—			—
West Delta 32 costs	13,147			—			—
Unrealized loss (gain) on derivative instruments	5,806			4,783			(17,556		)
Accretion of asset retirement obligations	23,454			36,421			27,410
Depreciation, depletion, amortization and impairment	122,696			78,347			60,181
Gain on involuntary conversion of assets	(17,827		)	(3,100		)	—
Provision for doubtful accounts	1,174			509			—
Loss (gain) on sale of asset	(105,771		)	38			(142		)
Adjusted EBITDA	$	45,068		$	78,995		$	110,686

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

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

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

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

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

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

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

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

Accretion expense. Accretion expense is associated with our asset retirement obligation liability and is recognized each period using the interest method of allocation. The capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon our interim review, a new

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calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate.

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

Income tax provision. As of December 31, 2013, we were a limited liability company not subject to entity level income tax. Our taxable income or loss is therefore passed through to our members and reported on their respective tax returns. Accordingly, no provision for federal income taxes has been recorded in our historical financial statements. We are subject to the Texas Gross Margin Tax. The Texas Gross Margin Tax generally is calculated as 1% of gross margin.

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Results of Operations

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

The following table sets forth certain information with respect to oil and gas operations for the years ended December 31, 2013 and 2012.

	Year Ended December 31,
	2013			2012			Change			% Change
PRODUCTION:
Oil (MBbl)	1,730			1,977			(247		)	(12	)%
Natural gas (MMcf)	13,294			17,884			(4,590		)	(26	)%
Plant products (MGal)	8,854			13,588			(4,734		)	(35	)%
Total (MBoe)	4,157			5,281			(1,124		)	(21	)%
REVENUES
Oil sales	$	182,731		$	210,720		$	(27,989	)	(13	)%
Natural gas sales	51,520			50,470			1,050			2	%
Plant product sales and other income	31,085			24,707			6,378			26	%
Net gain (loss) on derivative financial instruments	(7,328		)	18,581			(25,909		)	(139	)%
	258,008			304,478			46,430			15	%
OPERATING EXPENSES
Lease operating	177,210			180,691			(3,481		)	(2	)%
Production taxes	627			745			(118		)	(16	)%
Workover	8,224			17,986			(9,762		)	(54	)%
Exploration	200			1,682			(1,482		)	(88	)%
Depreciation, depletion and amortization	43,606			47,314			(3,708		)	(8	)%
Impairment	79,090			31,033			48,057			155	%
General and administrative	36,601			26,486			10,115			38	%
Gain due to involuntary conversion of asset	(17,827		)	(3,100		)	(14,727		)	475	%
Accretion	23,454			36,421			(12,967		)	(36	)%
Gain on sale of asset	(105,771		)	38			(105,809		)	(278,445	)%
Other operating expenses	8,061			—			8,061			100%
TOTAL OPERATING EXPENSES	253,475			339,296			(85,821		)	(25	)%
(LOSS) INCOME FROM OPERATIONS	4,533			(34,818		)	39,351			(113	)%
OTHER INCOME (EXPENSE)
Interest income	110			319			(209		)	(66	)%
Miscellaneous (expense) income	(10,771		)	(3,504		)	(7,267		)	207	%
Interest expense	(26,789		)	(25,965		)	(824		)	3	%
TOTAL OTHER INCOME (EXPENSE)	(37,450		)	(29,150		)	(8,300		)	28	%
NET (LOSS) INCOME	$	(32,917	)	$	(63,968	)	$	31,051		(49	)%

Production

Oil and natural gas production. Total oil, natural gas and plant product production of 4,157 MBoe decreased1,124 MBoe, or 21%, during the year ended December 31, 2013, compared to the same period in 2012. The decrease in production during 2013 was 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.

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Revenues

Total revenues. Total revenues for the year ended December 31, 2013 of $258.0 million decreased $46.4 million, or 15%, over the comparable period in 2012. The decrease in revenues during 2013 was a result of lower oil, gas and plant production due to the sale of assets and lower oil and plant product prices, partially offset by higher gas prices and the consolidation of Freedom Well Services, LLC. Total revenues were also lower due to a $7.3 million net (loss) on derivative financial instruments for the year ended December 31, 2013 compared to a $18.6 million net gain on derivative financial instruments for the prior year.

We entered into certain oil and natural gas commodity derivative contracts in 2013 and 2012. We received/(paid) cash upon the settlement of these derivative contracts in the amounts of $(1.5) million and $23.4 million for the years ended December 31, 2013 and 2012, respectively, which is included in the Net gain (loss) on derivative financial instruments in our statements of operations.

Excluding hedges, we realized average oil prices of $105.60 per barrel and gas prices of $3.88 per Mcf for the year ended December 31, 2013. Excluding hedges, for the year ended December 31, 2012, we realized average oil prices of $106.60 per barrel and gas prices of $2.82 per Mcf. Although average prices realized from the sale of oil reflected the economic turnaround that began during 2011, economic conditions continue to remain uncertain. Oil and natural gas prices will remain unstable and we expect them to be volatile in the future.

Operating Expenses

Lease operating costs. Our lease operating costs for the year ended December 31, 2013decreased to $177.2 million million, or $42.63 per Boe, compared to $180.7 million, or $34.22 per Boe, for the same period of 2012. The decrease in lease operating costs during 2013 was primarily due to the asset sales during 2013 partially offset by expenses incurred related to the West Delta 32 Incident. The increase in cost per Boe during 2013 was primarily due to an increase in non recurring lease operating cost related to West Delta 32 Incident.

Workover costs. Our workover costs decreased$9.8 million to $8.2 million for the year ended December 31, 2013 compared to $18.0 million for the same period in 2012. For the year ended December 31, 2013, Ship Shoal 198, South Timbalier 203, South Marsh 23 and Vermilion 119 were the primary workover expense projects.

Exploration. Exploration expense was $0.2 million and $1.7 million for the years ended December 31, 2013 and 2012, respectively. We elected to participate in the drilling of the South Pelto Block 13 No. STK BP2 with a 10.33% working interest. The well was designed to test the CP 12B sand. The operator encountered mechanical problems and commenced bypass operations which were unsuccessful. The operator opted to abandon the drilling and the well was deemed non-commercial.

Depreciation, depletion, amortization and impairment. DD&A expense was $43.6 million, or $10.49 per Boe, and $47.3 million, or $8.96 per Boe, for the years ended December 31, 2013 and 2012, respectively. The decrease in DD&A 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 $79.1 million impairment during 2013 and a $31.0 million impairment during 2012. The 2013 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 $36.6 million, or $8.81 per Boe, and $26.5 million, or $5.02 per Boe, for the years ended December 31, 2013 and 2012, respectively. The increase in G&A expense 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 $0.7 million, severance costs, consultant expenses and costs related to our consolidation of Freedom Well Services, LLC. Additionally, the increases in G&A expense were partially offset by a decrease in bonus expense and by reclassifying the 2013 surety fees to miscellaneous expense.

Gain due to 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

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platform. The costs associated with the High Island 443 A-5 drill were also insurance recoverable. We recorded a gain of $17.8 million and $3.1 million for the years ended December 31, 2013 and 2012, 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 $23.5 million and $36.4 million for the years ended December 31, 2013 and 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. We recognized a gain on the sale of assets of $105.8 million during the year ended December 31, 2013. This compares to a loss of $38.0 thousand for the prior year. The gain in 2013 was primarily related to the sale of four fields to Renaissance for approximately $52.5 million prior to normal purchase price adjustments on March 26, 2013, the sale of an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million, and the sale of two additional fields to Renaissance on November 15, 2013 for approximately $60M, and one property to Energy XXI in December 2013 for $10 million.

Other operating expenses. Other operating expenses of $8.1 million for the year ended December 31, 2013 were related to our consolidation of Freedom Well Services, LLC. There were no other operating expenses for the same period in 2012.

Miscellaneous expense. Miscellaneous expense increased $7.3 million to $10.8 million for the year ended December 31, 2013 compared to $3.5 million for the same period in 2012. The higher expense in 2013 was a result of the consent solicitation fee paid under the First Supplemental Indenture.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

The following table sets forth certain information with respect to oil and gas operations for the years ended December 31, 2012 and 2011.

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	Year Ended December 31,
	2012			2011			Change			% Change
PRODUCTION:
Oil (MBbl)	1,977			1,991			(14		)	(1	)%
Natural gas (MMcf)	17,884			18,188			(304		)	(2	)%
Plant products (MGal)	13,588			12,257			1,331			11	%
Total (MBoe)	5,281			5,314			(33		)	(1	)%
REVENUES
Oil sales	$	210,720		$	215,204		$	(4,484	)	(2	)%
Natural gas sales	50,470			75,994			(25,524		)	(34	)%
Plant product sales and other income	24,707			23,091			1,616			7	%
Net gain (loss) on derivative financial instruments	18,581			25,655			15,265			60	%
	304,478			339,944			(35,466		)	(10	)%
OPERATING EXPENSES
Lease operating	180,691			158,545			22,146			14	%
Production taxes	745			859			(114		)	(13	)%
Workover	17,986			23,385			(5,399		)	(23	)%
Exploration	1,682			1,004			678			68	%
Depreciation, depletion and amortization	47,314			47,214			100			—	%
Impairment	31,033			12,967			18,066			139	%
General and administrative	26,486			22,029			4,457			20	%
Gain due to involuntary conversion of asset	(3,100		)	—			(3,100		)	100	%
Accretion	36,421			27,410			9,011			33	%
Gain on sale of asset	38			(142		)	180			(127	)%
TOTAL OPERATING EXPENSES	339,296			293,271			46,025			16	%
(LOSS) INCOME FROM OPERATIONS	(34,818		)	46,673			(81,491		)	(175	)%
OTHER INCOME (EXPENSE)
Interest income	319			373			(54		)	(14	)%
Miscellaneous (expense) income	(3,504		)	(6,253		)	2,749			(44	)%
Interest expense	(25,965		)	(25,752		)	(213		)	1	%
TOTAL OTHER INCOME (EXPENSE)	(29,150		)	(31,632		)	2,482			(8	)%
NET (LOSS) INCOME	$	(63,968	)	$	15,041		$	(79,009	)	(525	)%

Production

Oil and natural gas production. Total oil, natural gas and plant product production of 5,281 MBoe decreased 33 MBoe, or 1%, during the year ended December 31, 2012, compared to the same period in 2011. The decrease in production during 2012 was due to lower production in the third quarter of 2012 (196 MBoe), primarily as a result of downtime for Hurricane Isaac, and lower production in the fourth quarter of 2012 (414 MBoe) as a result of downtime in fields requiring hot work, which was delayed due to the BSEE requirement for approval after the West Delta 32 Incident, partially offset by a full year of production of the properties acquired in the Merit Acquisition (872 MBoe).

Revenues

Total revenues. Total revenues for the year ended December 31, 2012 of $304.5 million decreased $35.5 million, or 10%, over the comparable period in 2011. The decrease in revenues during 2012 was a result of lower oil, natural gas and plant product prices. Total revenues were also lower due to a $18.6 million net gain (loss) on derivative financial instruments for the year ended December 31, 2012 compared to a $25.7 million for the prior year.

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We entered into certain oil and natural gas commodity derivative contracts in 2012 and 2011. We realized gains on these derivative contracts in the amounts of $23.4 million and $8.1 million for the years ended December 31, 2012 and 2011,

Excluding hedges, we realized average oil prices of $106.60 per barrel and gas prices of $2.82 per Mcf for the year ended December 31, 2012. Excluding hedges, for the year ended December 31, 2011, we realized average oil prices of $108.09 per barrel and gas prices of $4.18 per Mcf. Although average prices realized from the sale of oil reflected the economic turnaround that began during 2011, economic conditions continue to remain uncertain. Oil and natural gas prices will remain unstable and we expect them to be volatile in the future.

Operating Expenses

Lease operating costs. Our lease operating costs for the year ended December 31, 2012 increased on a nominal basis $22.1 million ($158.6 million in 2011 and $180.7 million in 2012) compared to the same period ending December 31, 2011. The increase in lease operation costs during 2012 was directly related to the additional properties acquired in the Maritech Acquisition, including non-recurring safety and regulatory costs on these acquired properties, as well as expenses incurred related to the West Delta 32 Incident. This increase in costs per Boe during 2012 was also primarily attributable to a mix of increased properties and lower production due to Hurricane Isaac and downtime in the fields requiring hot work which was delayed due to the BSEE requirement for approval after the West Delta 32 Incident.

Workover costs. Our workover costs decreased $5.4 million to $18.0 million for the year ended December 31, 2012 compared to $23.4 million for the same period in 2011. For the year ended December 31, 2012, West Cameron 20/45, Eugene Island 156/South Marsh 22, South Pass 86/87/89, West Delta 31/32, Vermilion 119/120/124 and Eugene Island 331 were the primary workover expense projects.

Exploration. Exploration expense was $1.7 million and $1.0 million for the years ended December 31, 2012 and 2011, respectively. We elected to participate in the drilling of the South Pelto Block 13 No. STK BP2 with a 10.33% working interest. The well was designed to test the CP 12B sand. The operator encountered mechanical problems and commenced bypass operations which were unsuccessful. The operator opted to abandon the drilling and the well was deemed non-commercial.

Depreciation, depletion, amortization and impairment. DD&A expense was $47.3 million, or $8.96 per Boe, and $47.2 million, or $8.88 per Boe, for the years ended December 31, 2012 and 2011, respectively. In 2012, the DD&A expense was relatively flat compared to 2011 as a result of an increase in the DD&A rate partially offset by lower production due to uneconomic leases and several fields being shut-in. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded $31.0 million and $13.0 million in impairments for the years ended December 31, 2012 and 2011, respectively, as the estimated undiscounted cash flows of oil and gas properties were less than its carrying value on certain properties.

General and administrative expenses. G&A expense was $26.5 million, or $5.02 per Boe, and $22.0 million, or $4.15 per Boe, for the years ended December 31, 2012 and 2011, respectively. The increase in G&A expense was primarily due to higher costs for additional staff and bonding insurance attributable to our 2011 acquisitions. Additional increase in G&A expense was partially due to an offset by reclassifying the 2013 surety fees in the amounts of $4.1 million and $5.7 million to "Miscellaneous Expense" for the three and six months ended June 30, 2013, respectively. Legal fees were also higher in 2012 as a result of the West Delta 32 Incident, recapitalization efforts and litigation expense.

Gain due to 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 filed an insurance claim and costs were reimbursed by our insurance company. We recorded a gain of $3.1 million, after a deductible of $0.5 million.

Accretion expense. We recognized accretion expense of $36.4 million and $27.4million for the years ended December 31, 2012 and 2011, respectively. The increase in accretion expense in 2012 was attributable to assumed asset retirement obligations related to our acquisitions in 2011.

Miscellaneous expense. Miscellaneous expense decreased $2.7 million to $3.5 million for the year ended December 31, 2012 compared to $6.3 million for the same period in 2011. The higher expense in 2011 was a result of the consent solicitation fee paid under the First Supplemental Indenture.

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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, borrowings under our lines of credit, cash flows from operations and asset sales. In 2013 we also received $24.1 million insurance proceeds related to the HI 443 A-5 well and $131.8 million (subject to customary closing adjustments) in proceeds from asset sales which funded our net working capital deficit of $(109.6) million and our incurred net loss of $(32.9) million.

The combination of restricted credit availability, declining production since the fourth quarter of 2012, settlement of our plugging and abandonment (P&A) liabilities and additional collateral requirements related to our surety bonds that secure our P&A obligations led to significant reductions in cash beginning in the fourth quarter of 2012 and continuing throughout the year 2013. To increase liquidity we continue to stretch accounts payable, aggressively pursued accounts receivable and sold non-core assets. In 2014 we expect to continue to sell non-core assets in an effort to improve our liquidity position.

Our primary use of capital has been for acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our P&A obligations. As we abandon certain fields and meet the various criteria related to the corresponding escrow accounts, we expect to release funds from the escrow accounts. We use letters of credit to back our surety bonds for P&A obligations. Certain of our surety bonds are secured entirely by 100% cash backed letters of credit. We are currently in discussions with our surety providers to replace the 100% cash backed surety bonds with collateral percentages far less than 100%

The amount, timing and allocation of capital expenditures are largely discretionary and within our control. In 2014 we have decided to defer a significant portion of our identified capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We will monitor and adjust our future capital expenditures to respond to changes in prices, availability of financing, industry conditions, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Senior Secured Revolving Credit Facility

On December 24, 2010, we entered into a Credit Facility comprised of a senior secured revolving credit facility of up to $35 million and a $75 million secured letter of credit facility to be used exclusively for the issuance of letters of credit in support of our future P&A liabilities relating to our oil and natural gas properties (the “Letter of Credit Facility”). The Credit Facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 4.75% to 5.5%, or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 3.25% to 4.00%. The applicable margin is computed based on the borrowing based utilization percentage in effect from time to time. The borrowing base under our Credit Facility is subject to redetermination on a semi-annual basis, effective April 1 and October 1, and up to one additional time during any six month period, as may be requested by either us or the administrative agent, acting at the direction of the majority of the lenders. The borrowing base will be determined by the administrative agent in its sole discretion and consistent with its normal oil and gas lending criteria in existence at that particular time. Our obligations under the Credit Facility 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.

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

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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 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 October 15, 2013 and as of December 31, 2013 we had $35 million outstanding. As of March 17, 2014, the outstanding balance of the Credit Facility was zero.

As of December 31, 2013, letters of credit in the aggregate amount of $66.6 million were outstanding under the Letter of Credit Facility. We had $34.5 million in 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 the twelve months ended December 31, 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 of investments, sell or otherwise transfer assets, enter into transactions with affiliates or change our line of business. As of December 31, 2013, we were not in compliance with the total leverage ratio covenant, the hedging requirement and the interest coverage ratio covenant. Our total leverage ratio was calculated to be 5.1 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 1.4 to 1.0, which was lower than the minimum 3.0 to 1.0. Our payables restriction covenant was calculated at $46.9 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. The Letter of Credit Facility covenants were removed due to the Tenth Amendment.

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-K.

13.75 % Senior Secured Notes

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On November 23, 2010, we issued $150 million in aggregate principal amount of the Notes discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under our lines of credit, to fund BOEMRE collateral requirements and to prefund our P&A escrow accounts. We pay interest on the Notes semi-annually, on June 1st and December 1st of each year, in arrears, commencing June 1, 2011. The Notes mature on December 1, 2015.

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

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

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

As of December 31, 2013, we were in compliance with our covenants under the Indenture. As of December 31, 2013, the recorded value of the Notes was $149.1 million, which includes the unamortized discount of $0.9 million.

Member Contributions

In the first quarter of 2013, we entered into contribution agreements with PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”) or entities designated by PPBE (together, the “Platinum Group”) pursuant to which we have issued 50 million additional Class E Units and 3.8 million additional Class B Units to the Platinum Group for an aggregate offering price of $50.0 million. In addition, we also agreed to issue an additional 43 million Class E Units in exchange for $30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class E Units will receive a preferred return of 20% per annum, which has increased to 36% per annum as of March 25, 2014 (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement). For the year ended December 31, 2013, we issued an additional amount of Class E Units of approximately $16.7 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.

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

Operating Agreement Amendment. In April 2013, we entered into the Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC (the “Fifth Amendment”) to (1) revise and confirm the order and manner of distributions to our members and (2) permit the issuance of Class E Units in an aggregate

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amount not to exceed $95.0 million and the issuance of Class B Units in connection with such Class E Units in an aggregate amount not to exceed 3,800,000 units before giving effect to any capitalized Class E preferred return, for cash or property capital contributions.

We expect that our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “—Oil and Natural Gas Hedging” and “—Quantitative and Qualitative Disclosures About Market Risk.”

We actively review acquisition opportunities on an ongoing basis. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Cash Flows

The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the years ended December 31, 2013, 2012 and 2011 (in thousands):

	Year Ended December 31,
	2013			2012			2011
Net cash provided by (used in) operating activities	$	(21,688	)	$	66,054		$	73,647
Net cash used in investing activities	(133		)	(89,723		)	(108,641		)
Net cash provided by financing activities	26,665			7,792			33,375
Net (decrease) increase in cash and equivalents	$	4,844		$	(15,877	)	$	(1,619	)

Cash flows provided by operating activities. Cash provided by operating activities totaling $21.7 million in 2013 compared to $66.1 million in 2012. Significant components of net cash provided by operating activities during the year ended December 31, 2013 included $8.2 million of non-cash items, primarily DD&A expense, impairment of oil and gas properties and accretion of asset retirement obligations as well as $24.5 million of changes in operating assets and liabilities, partially offset by a net loss of $32.9 million as a result of lower oil and gas production and prices and higher lease operating costs. The cash provided by operating activities in 2012 of $66.0 million, an decrease of $7.6 million from the same period in 2011, was primarily attributed to higher net income as a result of the 2011 and 2012 acquisitions.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and natural gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” below.

Cash flows used in investing activities. Cash used in investing activities totaling $0.1 million in 2013 was primarily attributable to additions to the oil and gas properties and the funding of the future P&A obligations through escrow. The cash used in investing activities in 2012 is primarily attributable to the assets purchased in the Maritech Acquisition and Merit Acquisition and the funding of the future P&A obligations through escrow. Cash used in investing activities in 2011 is attributable to the assets purchased in the Nippon Acquisition and the funding of the collateral requirements securing our P&A obligations with respect to the acquired properties and the W&T Escrow Accounts. The Nippon assets were purchased on September 30, 2011.

Cash flows provided by financing activities. Cash flows provided by financing activities of $26.6 million in 2013 were attributable to borrowings under the Credit Facility and short-term notes partially offset by payments on the Credit Facility and short-term notes, tax distributions to members, and debt issue costs. Cash flows provided by financing activities of $7.8 million in 2012 were attributable to borrowing on the Credit Facility and short term notes as well as a $30 million contribution from Platinum, which were partially offset by payments on the Credit Facility, debt issuance costs of the Notes, and tax distributions to members.

W&T Escrow Accounts

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On September 14, 2009, we completed the W&T Acquisition, pursuant to which we acquired certain oil, natural gas and mineral interests and leases, along with related wells, infrastructure, equipment, information and other rights and assets. In connection with the W&T Acquisition, the parties identified certain of the acquired properties as “Operated Properties” and the remaining properties as “Non-Operated Properties.”

As a condition to W&T’s willingness to sell the W&T Properties to us, we were required to provide adequate financial assurance of our ability to pay for the costs of plugging and abandoning and/or removing wells, platforms, facilities, pipelines and other equipment related to the W&T Properties. Accordingly, we were required to, among other things, (i) establish separate escrow accounts with respect to the Operated Properties and the Non-Operated Properties, (ii) make monthly contributions to each escrow account according to stipulated payments schedules until such accounts are fully funded to a maximum aggregate principal amount of $63.8 million, (iii) grant a second priority security interest to W&T on the W&T Properties and (iv) deliver, or cause to be delivered, a performance and payment guarantee from Platinum to W&T with respect to future P&A obligations associated with the Operated Properties and our obligation to fund the Operated Properties Escrow Account.

We used $20 million of the net proceeds of the Senior Notes Offering to prefund the W&T Escrow Accounts. As a result of this prefunding payment, the Operated Properties Escrow Account is now fully funded and we therefore have no further obligation to fund the Operated Properties Escrow Account. Platinum’s guarantee of our funding obligations under the Operated Properties Escrow Account terminated upon the full funding of the Operated Properties Escrow Account. The Non-Operated Properties Escrow Account has not been fully funded but in exchange for our prefunding, our obligation to make further payments to this account has been suspended for one year. Our funding obligations re-commenced on December 1, 2011, on which date we were required to make an initial payment of $0.2 million to the Non-Operated Properties Escrow Account, to be followed by payments of $0.3 million per month. Pursuant to this stipulated payment schedule, the Non-Operated Properties Escrow Account will be fully funded by the end of 2017.

In exchange for our agreement to prefund the W&T Escrow Accounts, W&T agreed to amend the documents relating to the acquisition of the W&T Properties to fully release, with respect to the Operated Properties, or subordinate, with respect to the Non-Operated Properties, its existing security interests and mortgages on such properties and allow us to grant new, second liens on those assets to the benefit of the holders of the notes (the “W&T Amendments”). Accordingly, the collateral for the notes includes all of the Operated Properties and Non-Operated Properties acquired in the W&T Acquisition, except for certain properties that were previously released or relinquished. W&T retained a third lien on the Non-Operated Properties.

Until the Non-Operated Properties Escrow Account has been fully funded (and therefore both W&T Escrow Accounts are fully funded), we are not permitted to withdraw cash to fund, or as reimbursement for, our P&A obligations with respect to the W&T Properties (i) from the Operated Properties Escrow Account without the consent of W&T or (ii) from the Non-Operated Properties Escrow Account.

W&T has a first priority lien on the Escrow Accounts, with the administrative agent under our credit facility holding a second lien for the benefit of the lenders under such facility and our derivatives counterparty. Our agreement with W&T prohibits the creation of any additional liens on the W&T Escrow Accounts, other than the liens described above.

On December 19, 2012, we entered into a Third Amendment with W&T. Pursuant to the Third Amendment, we caused 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.

Nippon Surety Bonds

On September 30, 2010, we completed the Nippon Acquisition in which we assumed $57.4 million in asset retirement obligations related to P&A obligations associated with the Nippon Properties. We fully funded the P&A obligations through surety bonds. The cancelation of the bonds will only be allowed once all P&A obligations relating to the properties have been fully performed and Nippon has given its consent.

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As of 2012 we were required by the Nippon PSA to revisit the amount of the asset retirement obligations. As of the date of this filing, we are still in negotiations with Nippon over the changes, if any, that will require additional surety bonds.

Maritech Escrow Account

Pursuant to the purchase agreement for the Maritech Acquisition, we are required to fund an escrow account (the “Maritech Escrow Account”), relating to the Maritech Properties, the principal amount of $13.1 million for future P&A costs that may be incurred on such properties. As of December 31, 2013, we have funded $12.4 million, leaving $0.7 million to be funded through February 2014. The account was fully funded at the time of this annual report. Maritech will allow us to withdraw funds from the escrow account if all P&A obligations have been satisfied for any particular well or related asset on a lease.

Merit Escrow Account

In regards to the Merit Acquisition, we are required to establish an escrow account to secure the performance of our P&A obligations and other indemnity obligations with respect to P&A and/or decommissioning of the acquired wells and facilities. We paid $33 million in surety bonds at closing and are required to, over time, deposit in the escrow account an aggregate principal amount equal to $60 million, which is to be paid in 30 equal monthly installments payable on the first day of each month commencing on the first day of the first month following closing. As of December 31, 2013, we have fully funded the escrow account. We will be allowed to withdraw amounts from the escrow account for reimbursement of our P&A obligations relating to any particular well or asset on a lease once we obtain a consent from Merit.

Asset Retirement Obligations

Periodically, we review and revise our asset retirement obligation estimates. In 2013, our asset retirement obligation decreased by $68.8 million due to a sale of properties and P&A activity incurred. In 2013, we also recognized $23.5 million in accretion expense.

At December 31, 2013 and 2012, we recorded total asset retirement obligations of $276.7 million and $345.5 million, respectively, and have funded approximately $235.4 million and $215.3 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds. As of December 31, 2013 and 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 December 31, 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	$	184,803	$	34,757	$	150,046	$	—	$	—
Interest on debt and notes payable	39,977		21,070		18,907		—		—
Operating leases (1)	17,722		7,274		4,124		3,231		3,093
Total contractual obligations	242,502		63,101		173,077		3,231		3,093
Other Obligations
Asset retirement obligations (2)	276,732		43,109		75,903		79,890		77,830
Total obligations (3)	$	519,234	$	106,210	$	248,980	$	83,121	$	80,923

___________________________________

(1) Consists of office space leases for our Houston, Texas offices and services provided in the office.

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

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(3) Does not include Class D Cumulative Convertible Participating Preferred Units as they are 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 December 31, 2013, commodity derivative instruments were in place covering approximately 75% of our projected oil sales volumes and 22% of our projected natural gas volumes through 2014.

Please see “Notes to Consolidated Financial Statements—Note 8—Derivative Instruments” for additional discussion regarding the accounting applicable to our hedging program.

Critical Accounting Policies

“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” is based upon our consolidated financial statements, which have been prepared in conformity with U.S. generally accepted accounting principles (“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. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience, current market factors and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements.

Oil and Natural Gas Properties

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

Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated at least bi-annually by our independent petroleum engineer, and are subject to future revisions based on availability of additional information. Depletion is calculated each quarter

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based upon the latest estimated reserves data available. Asset retirement obligations are recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement obligations are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well, the proceeds are credited to accumulated depletion and depreciation.

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

Oil and Natural Gas Reserve Quantities: Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our independent engineering firm prepares a reserve and economic evaluation of all our properties on a well-by-well basis utilizing information provided to it by us and information available from state agencies that collect information reported to it by the operators of our properties. The estimate of our proved reserves as of December 31, 2013, 2012 and 2011 has been prepared and presented in accordance with SEC rules and accounting standards which use pricing based on 12-month unweighted first-day-of-the-month average pricing.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve report. The accuracy of our reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.

Derivative Financial Instruments: We utilize certain derivative contracts to reduce our exposure to fluctuating oil and natural gas prices. The oil and natural gas reference prices of these derivative contracts are based upon futures which have a high degree of correlation with actual prices received by us. We did not designate any of our derivative contracts as qualifying cash flow hedges. Accordingly, all gains and losses from our price risk management activities are currently included in earnings. Open positions are marked-to-market and recorded as net gain (loss) on derivative financial instruments. When settled, the resulting cash flows are reported as cash flows from operating activities.

Asset Retirement Obligations: Authoritative guidance for asset retirement obligations uses a cumulative effect approach to recognize transition amounts for asset retirement obligations and accumulated depreciation. The accounting guidance requires companies to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and to capitalize an equal amount as part of the cost of the related oil and natural gas properties. We recognize the legal obligation of the dismantlement, restoration and abandonment costs associated with our oil and natural gas properties with our asset retirement obligation. These costs are impacted by our estimated remaining life as well as current market conditions associated with these costs.

Liabilities for expenditures of a noncapital nature are recorded when environmental assessment or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component is fixed or reliably determinable.

Recent Accounting Pronouncements: Management does not believe that any recently issued accounting pronouncements would have a material effect on the accompanying consolidated financial statements.

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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. For the years ended December 31, 2013, 2012 and 2011, we received an average of $105.60, $106.60 and $108.09 per barrel of oil, respectively, and $3.88, $2.82 and $4.18 per Mcf of natural gas, respectively, before consideration of commodity derivative contracts. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through the first six months of 2008, commodity prices for oil and natural gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs but also on capital costs.

Item 7A. 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 total annual production for the year ended December 31, 2013, our annual revenue would increase or decrease by approximately $17.3 million for each $10.00 per barrel change in oil prices and $13.3 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 December 31, 2013, the fair value of our commodity derivatives were included in our consolidated balance sheets for approximately $8.5 million as current assets and $0.3 thousand as long-term liabilities. At December 31, 2012, the fair value of our commodity derivatives in our consolidated balance sheet for approximately $2.4 million as current asset and $5.1 million as long-term liabilities. For the years ended December 31, 2013, 2012 and 2011, we received (paid) cash upon the settlement of commodity derivatives approximately $(1.5) million, $23.4 million and $8.1 million, respectively.

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 $17.0 million at December 31, 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.

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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 $35.2 million at December 31, 2013 and $27.2 million at December 31, 2012.

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.

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Item 8.    Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm	65
Consolidated Balance Sheets	66
As of December 31, 2013 and 2012
Consolidated Statements of Operations	67
Years Ended December 31, 2013, 2012 and 2011
Consolidated Statements of Members’ Deficit	68
Years Ended December 31, 2013, 2012 and 2011
Consolidated Statements of Cash Flows	69
Years Ended December 31, 2013, 2012 and 2011
Notes to Consolidated Financial Statements	70

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Report of Independent Registered Public Accounting Firm

To the Members of

Black Elk Energy Offshore Operations, LLC:

We have audited the accompanying consolidated balance sheets of Black Elk Energy Offshore Operations, LLC and Subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, members’ deficit and cash flows for each of the three years in the period ended December 31, 2013. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board of the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Black Elk Energy Offshore Operations, LLC and Subsidiaries as of December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

March 31, 2014

65

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,227		$	1,383
Restricted cash	775			—
Accounts receivable, net of allowance for doubtful accounts of $811 and $509 at December 31, 2013 and 2012, respectively	61,747			46,553
Accounts receivable - insurance recovery	—			3,100
Due from affiliates	273			347
Prepaid expenses and other	7,109			27,972
Current portion of escrow for abandonment costs	21,976			—
Derivative assets	1,370			2,408
TOTAL CURRENT ASSETS	99,477			81,763
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $293,973 and $191,326 at December 31, 2013 and 2012, respectively	196,136			260,012
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $5,350 and $1,717 at December 31, 2013 and 2012, respectively	4,862			1,968
OTHER ASSETS
Debt issue costs, net	1,488			3,230
Asset retirement obligation escrow receivable	20,348			20,348
Escrow for abandonment costs	235,473			215,263
Other assets	7,830			7,880
TOTAL OTHER ASSETS	265,139			246,721
TOTAL ASSETS	$	565,614		$	590,464
LIABILITIES AND MEMBERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued expenses	155,880			108,736
Derivative liabilities	9,828			—
Asset retirement obligations	43,109			41,572
Current portion of debt and notes payable	257			3,552
TOTAL CURRENT LIABILITIES	209,074			153,860
LONG-TERM LIABILITIES
Gas imbalance payable	1,888			2,521
Dividends payable	—			12,408
Derivative liabilities	31			5,091
Asset retirement obligations, net of current portion	233,623			303,933
Debt, net of current portion, net of unamortized discount of $617 and $882 at December 31, 2013 and 2012, respectively	183,929			201,118
TOTAL LONG-TERM LIABILITIES	419,471			525,071
TOTAL LIABILITIES	628,545			678,931
CLASS E and CLASS D PREFERRED UNITS	109,744			30,000
COMMITMENTS AND CONTINGENCIES
MEMBERS’ DEFICIT	(172,675		)	(118,467		)
TOTAL LIABILITIES AND MEMBERS’ DEFICIT	$	565,614		$	590,464

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

66

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2013			2012			2011
REVENUES:
Oil sales	$	182,731		$	210,720		$	215,204
Natural gas sales	51,520			50,470			75,994
Plant product sales and other revenue	31,085			24,707			23,091
Realized (loss) gain on derivative financial instruments	(1,522		)	23,364			8,099
Unrealized (loss) gain on derivative financial instruments	(5,806		)	(4,783		)	17,556
TOTAL REVENUES	258,008			304,478			339,944
OPERATING EXPENSES:
Lease operating	177,210			180,691			158,545
Production taxes	627			745			859
Workover	8,224			17,986			23,385
Exploration	200			1,682			1,004
Depreciation, depletion and amortization	43,606			47,314			47,214
Impairment	79,090			31,033			12,967
General and administrative	36,601			26,486			22,029
Gain due to involuntary conversion of asset	(17,827		)	(3,100		)	—
Accretion	23,454			36,421			27,410
Loss (gain) on sale of asset	(105,771		)	38			(142		)
Other operating expenses	8,061			—			—
TOTAL OPERATING EXPENSES	253,475			339,296			293,271
INCOME (LOSS) FROM OPERATIONS	4,533			(34,818		)	46,673
OTHER INCOME (EXPENSE):
Interest income	110			319			373
Miscellaneous expense	(10,771		)	(3,504		)	(6,253		)
Interest expense	(26,789		)	(25,965		)	(25,752		)
TOTAL OTHER EXPENSE	(37,450		)	(29,150		)	(31,632		)
NET (LOSS) INCOME	(32,917		)	(63,968		)	15,041
PREFERRED UNIT DIVIDENDS	17,336			8,208			4,200
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	(50,253	)	$	(72,176	)	$	10,841

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

67

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ DEFICIT

(in thousands)

	Members’ Capital			Accumulated Deficit			Total Members’ Deficit
Balance at December 31, 2010	$	(1,609	)	$	(19,001	)	$	(20,610	)
Distribution	(19,939		)	—			(19,939		)
Dividends	—			(4,200		)	(4,200		)
Net income	—			15,041			15,041
Balance at December 31, 2011	(21,548		)	(8,160		)	(29,708		)
Contribution	110			—			110
Distribution	(16,693		)	—			(16,693		)
Dividends	—			(8,208		)	(8,208		)
Net loss	—			(63,968		)	(63,968		)
Balance at December 31, 2012	(38,131		)	(80,336		)	(118,467		)
Cumulative adjustment- FWS 2012 Con. Retained Deficit	—			(3,955		)	(3,955		)
Dividends	—			(17,336		)	(17,336		)
Net loss	—			(32,917		)	(32,917		)
Balance at December 31, 2013	$	(38,131	)	$	(134,544	)	$	(172,675	)

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

68

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(32,917	)	$	(63,968	)	$	15,041
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	43,606			47,314			47,214
Impairment of oil and gas properties	79,090			31,033			12,967
Accretion of asset retirement obligations	23,454			36,421			27,410
Amortization of debt issue cost	4,611			4,777			2,915
Accretion of debt discount	265			232			203
Unrealized loss (gain) on derivative financial instruments	5,806			4,783			(17,556		)
(Gain) loss on sale of assets	(105,771		)	38			(142		)
Provision on doubtful accounts	1,174			509			—
Gain on involuntary conversion of assets	(17,827		)	(3,100		)	—
Changes in operating assets and liabilities:
Accounts receivable	(12,233		)	5,238			(26,348		)
Escrow Receivable, short term	(21,976		)	—			—
Due to/from affiliates, net	74			(185		)	413
Prepaid expenses and other assets	20,921			(1,744		)	(13,513		)
Other assets	253			—			—
Accounts payable and accrued expenses	36,732			36,427			38,199
Gas imbalance	(835		)	999			(4,748		)
Settlement of asset retirement obligations	(46,114		)	(32,720		)	(8,408		)
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES	(21,688		)	66,054			73,647
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	(128,696		)	(42,238		)	(21,169		)
Acquisitions of oil and gas properties	(3,250		)	(3,455		)	(27,398		)
Sale of oil and gas properties	128,712			(38		)	150
Additions to property and equipment	(477		)	(570		)	(1,699		)
Cash assumed in consolidation of Freedom Well Services, LLC	473			—			—
Proceeds received from insurance recovery	24,090			—			—
Deposits	—			(312		)	(540		)
Restricted cash	(775		)	—			—
Escrow payments, net	(20,210		)	(43,110		)	(57,985		)
NET CASH USED IN INVESTING ACTIVITIES	(133		)	(89,723		)	(108,641		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on short term notes	1,081			17,644			18,979
Payments on short term notes	(4,554		)	(18,247		)	(16,895		)
Borrowings on bank debt	54,000			171,500			158,457
Payments on bank debt	(71,500		)	(143,500		)	(134,457		)
Debt issuance costs	(2,362		)	(3,022		)	(2,770		)
Contributions from preferred members	50,000			110			30,000
Distributions to members	—			(16,693		)	(19,939		)
NET CASH PROVIDED BY FINANCING ACTIVITIES	26,665			7,792			33,375
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	4,844			(15,877		)	(1,619		)
CASH AND CASH EQUIVALENTS—BEGINING OF PERIOD	1,383			17,260			18,879
CASH AND CASH EQUIVALENTS—END OF PERIOD	$	6,227		$	1,383		$	17,260
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	23,603		$	23,603		$	22,050
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Increase in asset retirement obligations	$	2,341		$	53,118		$	147,442
Asset retirement obligations relieved due to sale of properties	$	(48,454	)
Assumption of gas imbalances	$	—		$	—		$	(1,159	)
Increase in asset retirement obligation escrow receivable	$	—		$	—		$	20,348
Paid-in-kind dividends on preferred equity and accrued distributions to members	$	17,336		$	8,208		$	4,200
Class D preferred units transferred to Class E preferred units	$	12,408		$	—		$	—

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

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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

NOTE 1—ORGANIZATION AND BUSINESS

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

Effective January 1, 2013, our consolidated financial statements include the accounts of BEEOO, our wholly-owned subsidiaries Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corporation, and our variable interest entity Freedom Well Services, LLC ("FWS"), as we determined that we are the primary beneficiary of FWS and we have the power to direct the activities of FWS.

NOTE 2— LIQUIDITY, RISKS, AND UNCERTAINTIES

While cash flows were lower than previously projected primarily due to lower production and sales of assets in the 3rd and 4th quarters, we continued our development operations by supplementing our cash flows from operating activities with funds raised through borrowings in 2013 and capital contributions from our members. We retained financial and technical advisors to provide recommendations on achieving improvements in production, operating expense, cash flows from operations, work over, capital expenditures and business planning.

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $(109.6) million at December 31, 2013 and we incurred net losses of $(32.9) million during the year ended December 31, 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 our surety bonds that secure our P&A obligations led to significant cash reductions in the fourth quarter of 2012 and the year 2013. To increase liquidity, we stretched accounts payable, aggressively pursued accounts receivable and sold non-core assets.

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

Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our plugging and abandonment (“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 our surety bonds for P&A obligations. We are currently in discussions with surety agencies to replace the 100% cash-backed letters of credit.

As of December 31, 2013 we have obtained a waiver of certain supplemental bonding requirements from Capital One. The current ratio covenant has been removed in the Seventh Amendment, Ninth Amendment and Tenth Amendment and has been replaced with a payables restriction covenant. Our liquidity projections demonstrate improvement of our financial position and we believe that we will meet our interest coverage ratio covenant, debt leverage ratio covenant and payables restriction covenant going forward.

Our capital budget may be adjusted in the future as business conditions warrant and the ultimate amount of capital we expend may fluctuate materially based on market conditions.

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

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

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

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

NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Reclassifications: Certain reclassifications have been made to conform 2011 and 2012 balances to our 2013 presentation. Such reclassifications had no effect on net income or cash flow.

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

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

We account for business combinations using the purchase method, in accordance with Accounting Standards Codification 810 from the Financial Accounting Standards Board (“FASB”). We use estimates to record the fair value of assets acquired and liabilities assumed.

Oil and natural gas reserves estimates, which are the basis for unit-of-production depletion and the impairment test, are based on assumptions that have inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

Cash and Cash Equivalents: We consider all demand deposits, money market accounts and certificates of deposit purchased with an original maturity of three months or less to be cash and cash equivalents.

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

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

We record revenues based on physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create gas imbalances that we recognize as a receivable (payable) when there are not sufficient reserves to make up the gas imbalance. A gas imbalance receivable (payable) can also be a result of imbalances acquired in conjunction with the acquisition of oil and gas properties. At December 31, 2013 and December 31, 2012, our net gas receivable imbalances were $1.2 million and $0.4 million, respectively.

Allowance for Doubtful Accounts: Trade and other receivables are recorded at their outstanding balances adjusted for an allowance for doubtful accounts. The allowance for doubtful accounts is determined by analyzing the payment history and credit worthiness of each debtor. Receivable balances are charged off when they are considered uncollectible by management. Recoveries of receivables previously charged off are recorded as income when received. At December 31, 2013 and December 31, 2012, allowance for doubtful accounts totaled $0.8 million and $0.5 million, respectively.

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

Depreciation, depletion and amortization (“DD&A”) of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. DD&A expense related to oil and natural gas properties for the years ended December 31, 2013, 2012 and 2011 was $41.4 million, $46.5 million and $46.6 million, respectively. As more fully described below, proved reserves are estimated annually by our independent petroleum engineer, and are subject to future revisions based on availability of additional information. DD&A is calculated each quarter based upon the latest estimated reserves data available. Asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Upon sale or retirement of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to operations.

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural gas properties by field to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices. For the years ended December 31, 2013, 2012 and 2011, we recorded an impairment charge of approximately $79.1 million, $31.0 million and $13.0 million, respectively.

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

Other Property and Equipment: Other property and equipment consists principally of furniture, fixtures and equipment and leasehold improvements. Other property and equipment and related accumulated depreciation and amortization are relieved upon retirement or sale and the gain or loss is included in operations. Maintenance and repairs are charged to operations.

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Renewals and betterments that extend the useful life of property and equipment are capitalized to the appropriate property and equipment accounts. Depreciation of other property and equipment is computed using the straight-line method based on estimated useful lives of the property and equipment. Depreciation expense of other property and equipment for the years ended December 31, 2013, 2012 and 2011 was $2.2 million, $0.8 million and $0.6 million, respectively.

In accordance with authoritative guidance on accounting for the impairment or disposal of long-lived assets, we assess the recoverability of the carrying value of our non-oil and natural gas long-lived assets when events occur that indicate an impairment in value may exist. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If this occurs, an impairment loss is recognized for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset.

Oil and Natural Gas Reserve Quantities: Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our independent engineering firm prepares a reserve and economic evaluation of all our properties on a well-by-well basis utilizing information provided to it by us and information available from state agencies that collect information reported to it by the operators of our properties. As discussed below, the estimate of our proved reserves as of December 31, 2013 and 2012 have been prepared and presented in accordance with SEC rules and applicable accounting standards. These rules require companies to prepare their reserve estimates using reserve definitions and pricing based on 12-month un-weighted first-day-of-the-month average pricing.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to DD&A and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the report. The accuracy of our reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the quantities of oil, natural gas, and natural gas liquids ultimately recovered.

Debt Issue Costs: Debt issue costs associated with long-term debt under revolving credit facilities and senior notes are carried at cost, net of amortization using the straight-line method over the term of the applicable long-term debt facility or the term of the notes, which approximates the effective interest method. Amortization expense for the years ended December 31, 2013, 2012 and 2011 amounted to $4.6 million, $4.8 million and $2.9 million, respectively.

Future amortization expense is as follows:

Year Ending December 31,	(in thousands)
2014	$	2,390
2015	1,463
2016	—
2017	—
2018	—
	$	3,853

Derivative Financial Instruments: We utilize certain derivative contracts to reduce our exposure to fluctuating oil and natural gas prices. The oil and natural gas reference prices of these derivative contracts are based upon futures which have a high degree of correlation with actual prices received by us. We did not designate any of our derivative contracts as qualifying cash flow hedges. Accordingly, all gains and losses from our price risk management activities are currently included in earnings. Open positions are marked-to-market and recorded as unrealized gain (loss) on derivative financial instruments. When settled, the resulting cash flows are reported as cash flows from operating activities.

Asset Retirement Obligations: Accounting guidance for asset retirement obligations requires companies to recognize a liability for the present value of all obligations associated with retirement of tangible long-lived assets and to capitalize an equal

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amount as part of the cost of the related oil and natural gas properties. We recognize the legal obligation of the dismantlement, restoration and abandonment costs associated with our oil and natural gas properties with our asset retirement obligations. These costs are impacted by our estimated remaining lives of the properties, as well as current market conditions associated with these activities.

Environmental Expenditures: We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed.

Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component is fixed or reliably determinable.

Income Taxes: We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes.

We are subject to the Texas margin tax which is generally calculated as 1% of gross margin. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. During the years ended December 31, 2013, 2012 and 2011, the margin tax was immaterial to the consolidated financial statements.

Recent Accounting Pronouncements: Management does not believe that any recently issued accounting pronouncements would have a material effect on the accompanying consolidated financial statements.

NOTE 4—DIVESTITURES

Divestitures

On March 26, 2013, we completed the sale of four fields to Renaissance for approximately $52.5 million prior to normal adjustments. Funds were used to reduce the amount borrowed under the Credit Facility by $36 million for Capex. We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million and an additional sale was made on November 15, 2013 for SP65 to Renaissance for $60.0 million prior to normal adjustments. Funds were used to repay a portion of the Credit Facility and to fund capital expenditures.

On December 20, 2013, we completed the sale of one field to Energy XXI GOM, LLC for approximately $10 million prior to normal adjustments. Funds were used to repay a portion of the Credit Facility and to fund 2013 capital expenditures.

NOTE 5—OIL AND GAS PROPERTIES

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

	At December 31,
	2013			2012
	(in thousands)
Proved properties	$	490,109		$	451,338
Accumulated depletion, depreciation, amortization and impairment	(293,973		)	(191,326		)
Oil and Natural Gas Properties, net	$	196,136		$	260,012

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NOTE 6—ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Below are the components of accounts payable and accrued expenses:

	At December 31,
	2013		2012
	(in thousands)
Accounts payable—trade	$	122,015	$	61,530
Accrued operating expenses	19,014		42,194
Interest payable	2,410		1,913
Other payables	12,441		3,099
	$	155,880	$	108,736

NOTE 7—ASSET RETIREMENT OBLIGATIONS

Accounting guidance requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon our interim review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost.

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

	At December 31,
	2013			2012
	(in thousands)
Beginning of year	$	345,505		$	288,686
Revaluation of liability	2,341			53,118
Liabilities relieved due to sale of properties	(48,454		)	—
Liabilities settled	(46,114		)	(32,720		)
Accretion expense	23,454			36,421
End of year	$	276,732		$	345,505
Less: Current portion	$	(43,109	)	$	(41,572	)
LT Asset retirement obligations	$	233,623		$	303,933

NOTE 8—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

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the derivative instruments are categorized as standalone derivatives and are being marked-to-market in unrealized gain (loss) on derivative financial instruments” in the consolidated statements of operations.

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At December 31, 2013, the notional volumes of our commodity derivative contracts were as follows:

	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)
1/14 - 2/14	19,000	$	96.90	$	(60	)	$	(60	)	82,000	$	4.60	$	45		$	45		$	(15	)	$	(15	)
1/14 - 5/14	10,083	100.80		136			136			129,960	4.94		$	464		464			600			600
6/14 - 6/14	—	—		—			—			129,960	4.94		101			101			101			101
1/14 - 12/14	15,000	65.00		(5,172		)	(5,172		)	—	—		—			—			(5,172		)	(5,172		)
1/14 - 1/14	4,723	88.80		(46		)	(46		)	43,347	4.09		(14		)	(14		)	(60		)	(60		)
2/14 - 2/14	13,313	88.80		(128		)	(128		)	32,636	4.09		(5		)	(5		)	(133		)	(133		)
3/14 - 3/14	8,413	88.80		(78		)	(78		)	46,764	4.09		(5		)	(5		)	(83		)	(83		)
4/14 - 4/14	12,473	88.80		(108		)	(108		)	41,253	4.09		(1		)	(1		)	(109		)	(109		)
5/14 - 5/14	11,793	88.80		(92		)	(92		)	40,391	4.09		—			—			(92		)	(92		)
6/14 - 6/14	15,546	88.80		(108		)	(108		)	20,112	4.09		(1		)	(1		)	(109		)	(109		)
7/14 - 7/14	11,845	88.80		(72		)	(72		)	39,283	4.09		(2		)	(2		)	(74		)	(74		)
8/14 - 8/14	13,165	88.80		(69		)	(69		)	34,246	4.09		(2		)	(2		)	(71		)	(71		)
9/14 - 9/14	16,235	88.80		(74		)	(74		)	29,753	4.09		(2		)	(2		)	(76		)	(76		)
10/14 - 10/14	15,605	88.80		(60		)	(60		)	28,635	4.09		(2		)	(2		)	(62		)	(62		)
11/14 - 11/14	18,525	88.80		(61		)	(61		)	27,081	4.09		(3		)	(3		)	(64		)	(64		)
12/14 - 12/14	22,526	88.80		(57		)	(57		)	34,114	4.09		(7		)	(7		)	(64		)	(64		)
1/14 - 1/14	46,000	87.85		(489		)	(489		)	—	—		—			—			(489		)	(489		)
2/14 - 2/14	25,000	87.85		(263		)	(263		)	—	—		—			—			(263		)	(263		)
3/14 - 3/14	56,000	87.85		(570		)	(570		)	—	—		—			—			(570		)	(570		)
4/14 - 4/14	45,000	87.85		(431		)	(431		)	—	—		—			—			(431		)	(431		)
5/14 - 5/14	46,000	87.85		(400		)	(400		)	—	—		—			—			(400		)	(400		)
6/14 - 6/14	48,000	87.85		(377		)	(377		)	40,391	4.19		3			3			(374		)	(374		)
7/14 - 7/14	36,000	87.85		(250		)	(250		)	20,112	4.19		1			1			(249		)	(249		)
8/14 - 8/14	34,000	87.85		(208		)	(208		)	39,283	4.19		1			1			(207		)	(207		)
9/14 - 9/14	26,000	87.85		(141		)	(141		)	34,246	4.19		1			1			(140		)	(140		)
10/14 - 10/14	27,000	87.85		(128		)	(128		)	29,753	4.19		1			1			(127		)	(127		)
11/14 - 11/14	20,000	87.85		(83		)	(83		)	28,635	4.19		—			—			(83		)	(83		)
12/14 - 12/14	31,000	87.85		(105		)	(105		)	27,081	4.19		(3		)	(3		)	(108		)	(108		)
1/15 - 1/15	—	—		—			—			34,114	4.19		(5		)	(5		)	(5		)	(5		)
2/15 - 2/15	—	—		—			—			27,838	4.19		(4		)	(4		)	(4		)	(4		)
3/15 - 3/15	—	—		—			—			24,461	4.19		(3		)	(3		)	(3		)	(3		)
1/15 - 1/15	—	—		—			—			27,838	4.09		(8		)	(8		)	(8		)	(8		)
2/15 - 2/15	—	—		—			—			24,461	4.09		(6		)	(6		)	(6		)	(6		)
3/15 - 3/15	—	—		—			—			26,443	4.09		(5		)	(5		)	(5		)	(5		)
1/14 - 1/14	46,006	100.72		(57		)	(57		)	—	—		—			—			(57		)	(57		)
2/14 - 2/14	39,159	100.72		(45		)	(45		)	—	—		—			—			(45		)	(45		)
3/14 - 3/14	36,822	100.72		(33		)	(33		)	—	—		—			—			(33		)	(33		)
4/14 - 4/14	34,069	100.72		(16		)	(16		)	—	—		—			—			(16		)	(16		)
5/14 - 5/14	35,200	100.72		3			3			—	—		—			—			3			3
6/14 - 6/14	31,668	100.72		18			18			—	—		—			—			18			18
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		124			124			—	—		—			—			124			124
11/14 - 11/14	40,874	100.72		131			131			—	—		—			—			131			131
12/14 - 12/14	26,424	100.72		80			80			—	—		—			—			80			80
				(9,028		)	(9,028		)				539			539			(8,489		)	(8,489		)

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At December 31, 2012, the notional volumes of our commodity derivative contracts were as follows:

	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)
1/13 - 10/13	27,750	$	96.90	$	983		$	983		104,000	$	4.60	$	1,114	$	1,114	$	2,097		$	2,097
11/13 - 11/13	26,800	96.90		88			88			104,000	4.60		$	81	$	81	169			169
12/13 - 12/13	27,750	96.90		95			95			104,000	4.60		61		61		156			156
1/14 - 2/14	19,000	96.90		136			136			82,000	4.60		80		80		216			216
1/13 - 6/13	15,542	100.80		715			715			200,669	4.94		1,806		1,806		2,521			2,521
7/13 - 7/13	7,132	100.80		47			47			148,788	4.94		194		194		241			241
8/13 - 8/13	5,980	100.80		40			40			139,212	4.94		176		176		216			216
9/13 - 9/13	3,897	100.80		26			26			116,125	4.94		145		145		171			171
10/13 - 10/13	3,259	100.80		22			22			91,166	4.94		110		110		132			132
11/13 - 11/13	—	—		—			—			64,926	4.94		71		71		71			71
12/13 - 12/13	10,042	100.80		70			70			119,462	4.94		107		107		177			177
1/14 - 5/14	10,083	100.80		361			361			129,960	4.94		547		547		908			908
6/14 - 6/14	—	—		—			—			129,960	4.94		111		111		111			111
1/13 - 12/13	19,750	85.90		(1,649		)	(1,649		)	47,000	5.00		785		785		(864		)	(864		)
1/14 - 12/14	15,000	65.00		(4,199		)	(4,199		)	—	—		—		—		(4,199		)	(4,199		)
1/13 - 1/13	9,042	88.80		(29		)	(29		)	—	—		—		—		(29		)	(29		)
2/13 - 2/13	23,522	88.80		(84		)	(84		)	—	—		—		—		(84		)	(84		)
3/13 - 3/13	16,792	88.80		(67		)	(67		)	—	—		—		—		(67		)	(67		)
4/13 - 4/13	23,812	88.80		(103		)	(103		)	—	—		—		—		(103		)	(103		)
5/13 - 5/13	24,012	88.80		(110		)	(110		)	—	—		—		—		(110		)	(110		)
6/13 - 6/13	29,752	88.80		(140		)	(140		)	—	—		—		—		(140		)	(140		)
7/13 - 7/13	23,143	88.80		(108		)	(108		)	—	—		—		—		(108		)	(108		)
8/13 - 8/13	24,915	88.80		(114		)	(114		)	—	—		—		—		(114		)	(114		)
9/13 - 9/13	28,688	88.80		(127		)	(127		)	—	—		—		—		(127		)	(127		)
10/13 - 10/13	28,006	88.80		(120		)	(120		)	—	—		—		—		(120		)	(120		)
11/13 - 11/13	31,605	88.80		(130		)	(130		)	—	—		—		—		(130		)	(130		)
12/13 - 12/13	38,743	88.80		(152		)	(152		)	—	—		—		—		(152		)	(152		)
1/14 - 1/14	4,723	88.80		(17		)	(17		)	—	—		—		—		(17		)	(17		)
2/14 - 2/14	13,313	88.80		(48		)	(48		)	—	—		—		—		(48		)	(48		)
3/14 - 3/14	8,413	88.80		(29		)	(29		)	—	—		—		—		(29		)	(29		)
4/14 - 4/14	12,473	88.80		(41		)	(41		)	—	—		—		—		(41		)	(41		)
5/14 - 5/14	11,793	88.80		(37		)	(37		)	—	—		—		—		(37		)	(37		)
6/14 - 6/14	15,546	88.80		(46		)	(46		)	—	—		—		—		(46		)	(46		)
7/14 - 7/14	11,845	88.80		(33		)	(33		)	—	—		—		—		(33		)	(33		)
8/14 - 8/14	13,165	88.80		(34		)	(34		)	—	—		—		—		(34		)	(34		)
9/14 - 9/14	16,235	88.80		(41		)	(41		)	—	—		—		—		(41		)	(41		)
10/14 - 10/14	15,605	88.80		(38		)	(38		)	—	—		—		—		(38		)	(38		)
11/14 - 11/14	18,525	88.80		(42		)	(42		)	—	—		—		—		(42		)	(42		)
12/14 - 12/14	22,526	88.80		(46		)	(46		)	—	—		—		—		(46		)	(46		)
1/13 - 1/13	66,000	87.85		(272		)	(272		)	—	—		—		—		(272		)	(272		)
2/13 - 2/13	34,000	87.85		(154		)	(154		)	—	—		—		—		(154		)	(154		)
3/13 - 3/13	50,000	87.85		(246		)	(246		)	—	—		—		—		(246		)	(246		)
4/13 - 4/13	35,000	87.85		(184		)	(184		)	—	—		—		—		(184		)	(184		)
5/13 - 5/13	36,000	87.85		(198		)	(198		)	—	—		—		—		(198		)	(198		)
6/13 - 6/13	23,000	87.85		(129		)	(129		)	—	—		—		—		(129		)	(129		)
7/13 - 7/13	15,000	87.85		(84		)	(84		)	—	—		—		—		(84		)	(84		)
8/13 - 8/13	11,000	87.85		(60		)	(60		)	—	—		—		—		(60		)	(60		)
9/13 - 9/13	20,000	87.85		(106		)	(106		)	—	—		—		—		(106		)	(106		)
10/13 - 10/13	4,000	87.85		(21		)	(21		)	—	—		—		—		(21		)	(21		)
11/13 - 11/13	250	87.85		(1		)	(1		)	—	—		—		—		(1		)	(1		)
12/13 - 12/13	2,500	87.85		(12		)	(12		)	—	—		—		—		(12		)	(12		)
1/14 - 1/14	46,000	87.85		(211		)	(211		)	—	—		—		—		(211		)	(211		)
2/14 - 2/14	25,000	87.85		(110		)	(110		)	—	—		—		—		(110		)	(110		)
3/14 - 3/14	56,000	87.85		(239		)	(239		)	—	—		—		—		(239		)	(239		)
4/14 - 4/14	45,000	87.85		(186		)	(186		)	—	—		—		—		(186		)	(186		)
5/14 - 5/14	46,000	87.85		(182		)	(182		)	—	—		—		—		(182		)	(182		)
6/14 - 6/14	48,000	87.85		(181		)	(181		)	—	—		—		—		(181		)	(181		)
7/14 - 7/14	36,000	87.85		(129		)	(129		)	—	—		—		—		(129		)	(129		)
8/14 - 8/14	34,000	87.85		(117		)	(117		)	—	—		—		—		(117		)	(117		)
9/14 - 9/14	26,000	87.85		(86		)	(86		)	—	—		—		—		(86		)	(86		)

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10/14 - 10/14	27,000		87.85		(86		)	(86		)	—	—		—		—		(86		)	(86		)
11/14 - 11/14	20,000		87.85		(61		)	(61		)	—	—		—		—		(61		)	(61		)
12/14 - 12/14	31,000		87.85		$	(87	)	$	(87	)	—	—		$	—	$	—	$	(87	)	$	(87	)
9/13 - 9/13	(17,500	)	$	89.15	$	72		$	72		—	$	—	$	—	$	—	$	72		$	72
					$	(8,071	)	$	(8,071	)				$	5,388	$	5,388	$	(2,683	)	$	(2,683	)

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

	Asset Derivatives			Liability Derivatives
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair value at December 31, 2013		Balance Sheet Location	Fair value at December 31, 2013
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	1,370	Current	$	(9,828	)
	Non-current	—		Non-current	(31		)
Total derivative instruments		$	1,370		$	(9,859	)

	Asset Derivatives			Liability Derivatives
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
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	6,808	Current	$	(4,400	)
	Non-current	1,235		Non-current	(6,326		)
Total derivative instruments		$	8,043		$	(10,726	)

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

		Twelve Months Ended December 31,
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Statements of Operations Location	2013			2012			2011
Commodity Contracts	Realized (loss) gain on derivative financial instruments	$	(1,522	)	$	23,364		$	8,099
Commodity Contracts	Unrealized gain (loss) on derivative financial instruments	(5,806		)	(4,783		)	17,556
Total derivative instruments		$	(7,328	)	$	18,581		$	25,655

NOTE 9—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

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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 December 31, 2013 and 2012, and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands):

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

	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 December 31, 2013 and 2012, management estimates that the derivative contracts had a fair value of $(8.5) million and $(2.7) million, respectively. We estimated the fair value of derivative instruments using internally-developed models that use as their basis, readily observable market parameters.

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

As of December 31, 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 December 31, 2013 was $164.1 million.

Fair Value on a Non-Recurring Basis

As of December 31, 2013, oil and gas properties with a carrying value of $275.2 million were written down to their fair value of $196.1 million, resulting in an impairment charge, which is recognized under “Impairments” in the consolidated statements of operations, of $79.1 million for the year ended December 31, 2013. As of December 31, 2012, oil and gas properties with a carrying value of $291.0 million were written down to their fair value of $260.0 million, resulting in an impairment charge of $31.0 million. 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

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prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

NOTE 10—DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:

	December 31, 2013			December 31, 2012
	(in thousands)
Senior Secured Revolving Credit Facility	$	34,500		$	52,000
13.75% Senior Secured Notes, net of discount	149,383			149,118
AFCO Credit Corporation-insurance note payable	—			3,552
Other debt	303			—
Total debt	184,186			204,670
Less: current portion	(257		)	(3,552		)
Total long-term debt	$	183,929		$	201,118

Senior Secured Revolving Credit Facility

On December 24, 2010 we entered into a credit facility (the “Credit Facility”) comprised of a senior secured revolving credit facility (the “Revolving Credit Facility”) and a secured letter of credit to be used exclusively for the issuance of letters of credit in support of our future P&A liabilities relating to our oil and natural gas properties (the “Letter of Credit Facility”).

During 2013, we have entered into various amendments to the Credit Facility. These amendments have (1) changed our amount available for borrowing under the Revolving Credit Facility, (2) increased the secured letter of credit from $35 million to $47 million, (3) amended certain provisions governing our swap agreements, (4) updated the fees on the letters of credit to 2% on a go-forward basis, (5) updated the “change in control” definition, (6) amended the definition of debt included in the calculation of the covenants, (7) changed the maturity date to January 1, 2015 on the Credit Facility and to June 22, 2014 on the Letter of Credit Facility, (8) received waivers related to our financial covenants for the third and fourth quarters of 2013, (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 (the “Platinum Group”) during the first quarter of 2013 and (11) revised the definition of “Event of Default” to include non-compliance with new affirmative covenants, (12) restricted returns of capital to our unit holders or distributions of our property to our equity interest holders and (13) waived our right and the rights of the Lenders to request or obtain a borrowing base redetermination prior to the first scheduled redetermination date in 2014.

As of December 31, 2013, we had $34.5 million of borrowings outstanding and $66.6 million of letters of credit issued resulting in zero borrowings available under the Credit Facility. On March 17, 2014, our credit facility was paid off.

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 2.5 to 1.0, or 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 December 31, 2013, we were not in compliance with the total leverage ratio covenant, and the interest coverage ratio covenant. Our total leverage ratio was calculated to be 5.0 to 1.0, which was higher than the required maximum of 2.5 to 1.0. Our interest coverage ratio covenant was calculated to be 1.4to 1.0, which was lower than the minimum 3.0 to 1.0. Our payables restriction covenant was calculated at $46.9 million which was higher than the maximum of $6.0 million. We received

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a limited waiver relating to such covenants in the 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 December 31, 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.

13.75% Senior Secured Notes

On November 23, 2010, we issued $150 million face value of 13.75% Senior Secured Notes discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under our prior revolving credit facility, to fund Bureau of Ocean Energy Management, Regulation and Enforcement collateral requirements, and to prefund our escrow accounts. We pay interest on the Notes semi-annually in arrears, on June 1 and December 1 of each year, which commenced on June 1, 2011. The Notes will mature on December 1, 2015, of which all principal then outstanding will be due. As of December 31, 2013 and 2012, the recorded value of the Notes was $149.4 million and $149.1 million, respectively, which includes the unamortized discount of $0.6 million and $0.9 million, respectively. We incurred underwriting and debt issue costs of $7.2 million which have been capitalized and will be amortized over the life of the Notes.

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

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

On May 23, 2011, we commenced a consent solicitation that was completed on May 31, 2011 and resulted in our entry into the First Supplemental Indenture. We paid a consent solicitation fee of $4.5 million. The First Supplemental Indenture amended the Indenture to, among other things: (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 (as defined in Note 18) to consolidated leverage to be less than 1.4 to 1.0 as of the last day of each fiscal year. In addition, we and our subsidiaries (excluding FWS) are subject to various covenants, including restricted payments, incurrence of indebtedness and issuance of preferred stock, liens, dividends and other payments, merger, consolidation or sale of assets, transactions with affiliates, designation of restricted and unrestricted subsidiaries, and a maximum limit for capital expenditures. Our limitation on capital expenditures was amended in conjunction with the Consent Solicitation on May 31, 2011 to a maximum limit of $60 million for the fiscal year ending December 31, 2012 and 30% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expense for any year thereafter. As of December 31, 2013, we were in compliance with our covenants under the Indenture.

AFCO Credit Corporation—Insurance Notes Payable

In 2012, we entered into a note to finance annual insurance premiums related to our oil and natural gas properties for an aggregate $17.6 million. The note bore interest at an annual rate of 1.95% compounded monthly. The note was paid off during the first quarter of 2013.

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The amounts of required principal payments based on our outstanding debt amounts as of December 31, 2013, were as follows:

Year Ending December 31,	(in thousands)
2014	$	257
2015	184,530
2016	16
2017	—
2018	—
	184,803
Unamortized discount on 13.75% Senior Secured Notes	(617		)
Total debt	$	184,186

NOTE 11—DEFINED CONTRIBUTION PLAN

We have a 401(k) Defined Contribution Plan (the “Plan”). Employees become eligible to contribute to the plan and to receive employer contributions the first of the month subsequent to completing one month of service. The Plan allows eligible employees to contribute up to 90% of their annual compensation, not to exceed the maximum amounts permitted by IRS regulations. The defined contribution plan provides that we will make a safe harbor contribution equal to 3% of compensation for the plan year. Employees are 100% vested in contributions that they make to the Plan and any safe harbor contributions. Other contributions made by us fully vest after three years of service. We provided matching contributions to the Plan for the years ended December 31, 2013, 2012 and 2011 of $0.5 million, $0.3 million and $0.5 million, respectively.

NOTE 12—MEMBERS’ DEFICIT

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

In the first quarter of 2013, we entered into contribution agreements with PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”) or entities designated by PPBE (together, the “Platinum Group”) pursuant to which we have issued 50.0 million additional Class E Preferred Units (the “Class E Units”) and 3.8 million additional Class B Units to the Platinum Group for an aggregate offering price of $50.0 million. The Class E Units are recorded under "Preferred Units" and the Class B Units are included in "Members Deficit" in the consolidated balance sheets. In addition, we also agreed to issue an additional 43 million Class E Units in exchange for $30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class D Preferred Units were recorded under "Preferred Units" in the consolidated balance sheets. The Class E Units 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 year ended December 31, 2013, we issued an additional amount of Class E Units of approximately 16.7 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.

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NOTE 13—GAIN ON INVOLUNTARY CONVERSION

High Island 443 A-2

On September 27, 2012, an incident occurred on our High Island 443 A-2 ST well which required the closing of the blind/shear rams to properly shut in and maintain control of the well due to several days of unsuccessful attempts to repair a small hydrocarbon leak on a conductor riser. Additional surface diagnostics found the inner casing strings to be most likely compromised. On October 12, 2012, the Bureau of Safety and Environmental Enforcement (“BSEE”) advised us to plug and abandon the well. We have well control insurance and pursued reimbursement for this incident. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drill are also insurance recoverable.

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 December 31, 2013, the claim was finalized and we received at total of approximately$24.1 million, net of deductibles, in cash for the claim during 2013. Of this amount, $17.8 million was recognized as a gain on involuntary asset conversion on the consolidated statement of operations.

NOTE 14—RELATED PARTY TRANSACTIONS

We pay for certain operating and general and administrative expenses on behalf of Black Elk Energy, LLC, the parent company of Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corp. At December 31, 2013 and 2012, we had receivables from Black Elk Energy, LLC in the amount of $273,430 and $23,430, respectively.

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 12.

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.

On May 28, 2013, our consolidated subsidiary 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 a month to month lease option thereafter. The agreement also includes an option to purchase the equipment for $1.5 million. The lease arrangement is treated as an operating lease and we incurred approximately $0.2 million of rental expense for the year ended December 31, 2013. As of December 31, 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 of $0.6 million, which is included in “Accounts payable and accrued expenses”.

In October 2010, Freedom Logistics LLC (“Freedom”) was formed by Platinum, our majority equity holder, and Freedom HHC Management, LLC, the members of which are Messrs. John Hoffman (our President and Chief Executive Officer) and David Cantu (a member of our management), for the purpose of holding certain aircraft equipment, including two helicopters. On October 8, 2010, we guaranteed the loan that Freedom used to purchase two helicopters in the aggregate principal amount of $3.2 million. On August 1, 2012, Freedom entered into a purchase agreement with Gulf State Aviation, whereby Gulf State Aviation purchased certain aircraft equipment from Freedom, including the two helicopters. The proceeds of the sale were applied to the balance of the guaranteed loan when the sale was finalized in December 2012 and there was no remaining balance due on the loan as of December 31, 2012. 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 15—MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

Major Customers

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The following purchasers and operators accounted for 10% or more of our oil and natural gas sales:

	Year Ended December 31,
	2013		2012		2011
Shell Trading (US) Company	62	%	18	%	51	%
JP Morgan Ventures Energy Corporation	—	%	41	%	8	%

In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of our customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. We believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.

Concentrations of Credit Risk

We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. We had cash deposits in certain banks that at times exceeded the maximum limits federally insured by the Federal Deposit Insurance Corporation. We monitor the financial condition of the banks and have experienced no losses on those accounts.

Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Based on the current demand for oil and natural gas, we do not expect that termination of sales to any of our current purchasers would have a material adverse effect on our ability to find replacement purchasers and to sell our production at favorable market prices.

Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We actively monitor our credit risks related to financial institutions and counterparties including monitoring credit agency ratings, financial position and current news to mitigate this credit risk.

A substantial portion of our oil and natural gas reserves and production are located in the Gulf of Mexico. Our company may be disproportionally exposed to the impact of delays of interruptions of production from these wells due to mechanical problems, damages to the current producing reservoirs and significant governmental regulations, including any curtailment of production or interruption of transportation of oil or natural gas produced from these wells.

NOTE 16—COMMITMENTS AND CONTINGENCIES

General

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessment of the property would be necessary to adequately determine remediation costs, if any. Management does not consider the amounts that would result from any environmental site assessments to be significant to the consolidated financial position or results of our operations. Accordingly, no provision for potential remediation costs is reflected in the accompanying consolidated financial statements.

We are subject to claims and lawsuits that arise primarily in the ordinary course of business. It is the opinion of management that the disposition or ultimate resolution of such claims and lawsuits will not have a material adverse effect on our consolidated financial position or results of operations.

West Delta 32

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. At the time of the explosion, production on the platform had been shut in while crews of independent contractors performed maintenance and construction on the platform. Three workers died as a result of the explosion and subsequent fire, and others sustained varying degrees of personal injuries. An investigation by the Bureau of Safety Enforcement and Environment Agency (“BSEE”), in coordination with the U.S. Coast Guard, has been

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finalized. As a result of the investigation, it is possible that BSEE could issue Incidents of Non-Compliance. We are currently waiting for BSEE’s conclusion of its assessment of penalties.

The United States Chemical Safety and Hazard Investigation Board has also made inquiry regarding the incident but has decided not to formally opened an investigation. Additionally, civil lawsuits relating to the explosion have been filed and are pending in federal courts.

On January 31, 2013, the family of decedent Jerome Malagapo sued BEEOO in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Malagapo’s wife individually and on behalf of his estate and Mr. Malagapo’s children. The plaintiffs allege that Mr. Malagapo was employed by Grand Isle Shipyard, Inc. and was working on the West Delta 32 Block Platform and as a result of the incident died. The plaintiffs are seeking an unspecified amount of actual and punitive damages.

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

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

For each proceeding, we are currently evaluating the plaintiff’s petitions and determining appropriate courses of response with the aid of legal counsel. These proceedings are at a preliminary stage; accordingly, we currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings. We intend to vigorously defend the Company in these proceedings.

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

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 which took place on November 12, 2013. Since the mediation was unsuccessful, the Parties have now agreed to enter into binding Arbitration, pursuant to and in accordance with the MSA. The Arbitration proceedings are underway.

Operating Leases

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

Approximate future minimum lease payments for operating leases at December 31, 2013 were as follows:

Year Ending December 31,	(in thousands)
2014	$	7,274
2015	2,151
2016	1,973
2017	1,695
2018	1,536
Thereafter	3,093
	$	17,722

Rent expense of approximately $1.7 million, $1.5 million and $1.0 million was incurred under operating leases in the years ended December 31, 2013, 2012 and 2011, respectively.

Escrow Accounts

Pursuant to the purchase agreement from W&T Offshore, Inc. (“W&T”), 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 $49.2 million ($18.0 million operated and $31.2 million non-operated) for future P&A costs that may be incurred on such properties. We were required to fully fund such obligations by the end of 2012 with respect to the operating properties and by the end of 2016 with respect to non-operating properties. The maximum obligation of $63.8 million may be adjusted downward in certain situations. We may withdraw cash from the W&T Escrow Accounts as reimbursement for performed P&A obligations. However, no cash may be withdrawn if at any point we are in default under our stipulated payment schedules. As of November 2010, we fully funded the operating escrow account in the amount of $43.1 million and the payment schedule for the Non-Operated Properties Escrow Account was amended and commenced on December 2011. As of December 31, 2013, we have funded $17.5 million into the non-operating escrow account, leaving $13.7 million to be funded through May 1, 2017.

The obligations under the W&T Escrow Accounts are fully guaranteed by an affiliate of Platinum. W&T Offshore Inc. (“W&T”) has a first lien on the entirety of the W&T Escrow Accounts, and BP Corporation North America Inc. and Platinum are pari passu second lien holders. Once P&A obligations with respect to the interest in properties acquired from the W&T Acquisition have been fully satisfied, the lien on the W&T Escrow Accounts will be automatically extinguished. W&T also has a second priority lien with respect to the interest in properties acquired from the W&T Acquisition (with Platinum and BNP Paribas sharing a first priority lien), which lien will be released once the W&T Escrow Accounts have been fully funded.

On December 19, 2012, we entered into a Third Amendment to Purchase and Sale Agreement (the “Third Amendment”) with W&T. Pursuant to the Third Amendment, we caused performance bonds (the “ARGO Bonds”) in an aggregate amount of $32.6 million to be issued by Argonaut Insurance Company to W&T to guaranty our performance of certain plugging and abandonment obligations. Upon receipt of the ARGO Bonds, W&T (i) released its rights to any money held in an escrow account established to secure our performance of certain plugging and abandonment obligations with respect to the Operated Properties Escrow Account, (ii) released the security interest and deposit account control agreement formerly securing its rights in the Operated Properties Escrow Account and (iii) authorized the escrow agent to release such funds from the Operated Properties Escrow Account to or at our direction. In addition, we and W&T agreed that until the funding of an escrow account established to our performance of certain plugging and abandonment obligations with respect to certain non-operated properties is complete, we may not obtain reductions of the ARGO Bonds under any circumstances without W&T’s consent.

Pursuant to the purchase agreement for the Maritech Acquisition, we are required to fund an escrow account (the “Maritech Escrow Account”), relating to the properties that were acquired of $13.1 million to be used for future P&A costs that may be incurred on such properties. As of December 31, 2013, we have funded $12.4 million, leaving $0.7 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.

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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 December 31, 2013, we have fully funded the escrow obligation.

NOTE 17—UNCERTAIN TAX POSITIONS

As we are considered a flow through entity for U.S. federal tax purposes, our only exposure to uncertain tax positions relates to the Texas margins tax.

We did not have unrecognized tax benefits as of December 31, 2013 and 2012, and do not expect this to change significantly over the next 12 months. In accordance with accounting guidance for income taxes, we will recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of December 31, 2013 , 2012 and 2011, we have not accrued interest or penalties related to uncertain tax positions.

Our tax years for fiscal years ended December 31, 2013, 2012, and 2011 are subject to examination in the United States and relevant state jurisdictions.

NOTE 18—SUPPLEMENTAL OIL AND NATURAL GAS RESERVE INFORMATION (UNAUDITED)

The supplementary data presented herein reflects information for all of our oil and natural gas producing activities.

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to our oil and natural gas activities for the years ended December 31, 2013, 2012 and 2011:

	Year Ending December 31,
	2013		2012		2011
	(in thousands)
Oil and Gas Activities:
Exploration costs	$	200	$	1,682	$	1,004
Development costs	130,953		42,238		21,169
Acquisition costs	3,250		3,455		27,398
Costs incurred	$	134,403	$	47,375	$	49,571

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and natural gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

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Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed reserves in barrels (“MBbls”) and cubic feet (“MMcf”) for each of the periods indicated were as follows:

	Crude Oil and  NGLs (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved reserves at December 31, 2011	20,123		150,393		45,189
Purchases of minerals in place	—		—		—
Extensions and discoveries	3,761		11,343		5,652
Revisions of previous estimates	(94	)	(30,759	)	(5,221	)
Production	(2,301	)	(17,884	)	(5,281	)
Proved reserves at December 31, 2012	21,489		113,093		40,339
Extensions and discoveries	1,950		9,431		3,522
Revisions of previous estimates	(1,633	)	(16,017	)	(4,302	)
Production	(1,941	)	(13,294	)	(4,157	)
Purchases of minerals in place	11		—		11
Sales of minerals in place	(6,829	)	(15,423	)	(9,400	)
Proved reserves at December 31, 2013	13,047		77,790		26,012
Proved developed reserves at December 31, 2013	9,973		53,907		18,957

Our proved undeveloped reserves at December 31, 2013 were 7.1 MMBoe, consisting of 3.1 MMBbls of oil and NGLs and 23.9 Bcf of natural gas. Decreases in proved undeveloped reserves in 2013 were primarily due to the reclassification of several PUDs that had reached the five year period and a lower pricing environment. All proved undeveloped reserves are scheduled to be drilled by 2017 excluding the twelve drills waiting on wellbore availability. Our proved undeveloped reserves at December 31, 2012 were 15.9 MMBoe, consisting of 9.2 MBbls of oil and NGLs and 40.1 Bcf of natural gas. Increases in proved undeveloped reserves were primarily due to continued evaluation of our existing asset base and the Merit Acquisition.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a standardized measure of the discounted net future cash flows and changes applicable to proved oil and natural gas reserves required by accounting guidance for disclosures about oil and natural gas producing activities. The future cash flows are based on estimated oil and natural gas reserves utilizing prices and costs in effect as of year-end, discounted at 10% per year and assuming continuation of existing economic conditions.

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of our proved oil and natural gas properties.

The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.

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	December 31,
	2013		2012		2011
	(in thousands)
Future cash inflows	$	1,611,000	$	2,552,252	$	2,641,791
Future cost:
Production	573,233		695,079		714,076
Development	212,376		496,834		544,523
Future income taxes	—		—		—
Future net cash flows	825,391		1,360,339		1,383,192
10% annual discount for estimated timing of cash flows	189,441		302,546		321,784
Standardized measure of discounted future net cash flows	$	635,950	$	1,057,793	$	1,061,408

Changes in Standardized Measure of Discounted Future Net Cash Flows from Oil and Gas Proved Reserves

	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Beginning of year:	$	1,057,793		$	1,061,408		$	392,189
Purchase of minerals in place	348			—			612,048
Extensions and discoveries and improved recovery, net of future production and development cost	108,261			202,334			314,920
Accretion of discount	87,339			83,566			34,238
Net change in sales prices net of production costs	(314,721		)	(61,407		)	112,923
Changes in estimated future development costs	162,099			6,420			(359,942		)
Previously estimated future development costs incurred	74,073			39,433			17,198
Revisions of quantity estimates	(132,242		)	(186,902		)	60,822
Sales, net of production costs	(86,673		)	(88,837		)	(131,500		)
Timing differences and other	(31,392		)	1,778			8,512
Sales of minerals in place	(288,935		)	—			—
Net increase (decrease)	(421,843		)	(3,615		)	669,219
End of year	$	635,950		$	1,057,793		$	1,061,408

The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.

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NOTE 19—QUARTERLY FINANCIAL DATA (Unaudited)

The table below sets forth unaudited financial information for each quarter of the last two years (in thousands):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2013
Total revenues	$	59,988		$	66,374		$	63,757		$	67,889
Loss (income) from operations	(8,972		)	(30,683		)	(8,881		)	44,004
Net (loss) income	(16,212		)	(39,518		)	(18,415		)	(41,228		)
Net (loss) income attributable to common unit holders	(19,355		)	(44,201		)	(23,170		)	(36,418		)
Year ended December 31, 2012
Total revenues	$	76,181		$	106,594		$	57,125		$	64,578
Income (loss) from operations	1,245			28,721			(25,153		)	(39,631		)
Net (loss) income	(5,654		)	21,517			(32,575		)	(47,256		)
Net (loss) income attributable to common unit holders	(7,454		)	19,573			(34,807		)	(49,488		)

NOTE 20—SUBSEQUENT EVENTS

Actions taken after the 2013 Fiscal Year

Resignation of Bruce Koch

On January 9, 2014, Black Elk Energy Offshore Operations, LLC (the “Company”) announced the resignation of Bruce Koch, Vice President and Chief Financial Officer, effective January 7, 2014. The terms of Mr. Koch’s offer letter included a lump sum severance compensation in an amount equal to one year's annual base salary, plus the benefits for one year the he was entitled to under his employment agreement. In exchange for these benefits, the offer letter contains a general release of claims by Mr. Koch and covenants by Mr. Koch with respect to confidentiality and non-disparagement.

Appointment of Chief Financial Officer

On January 8, 2014, we appointed Jeffrey Shulse as our Chief Financial Officer. 

Senior Secured Revolving Credit Facility

On March 17, 2014 our credit facility was paid off.. 

Sale of Assets

On March 13, 2014 , Black Elk Energy Offshore Operations, LLC (the “Company” or “we”) entered into a Purchase and Sale Agreement (the “PSA”) with a wholly owned subsidiary of Fieldwood Energy LLC (“Fieldwood”). Pursuant to the PSA, Fieldwood acquired all of the Company’s interest in 1 operated and 15 non-operated fields in the offshore Gulf of Mexico, and further described in detail as Exhibit 10.1 and incorporated herein, for $50 million, subject to normal purchase price adjustments (the “Sale”). The Sale closed on March 17, 2014.

Pursuant to the PSA, and subject to specified limitations described therein, we agreed to indemnify Fieldwood its Affiliates (as defined in the PSA) and their respective directors, officers, employees, stockholders, members, agents, consultants, advisors and other representatives against certain retained liabilities (as defined in the PSA) as well as losses resulting from any breach of any representations, warranties and covenants of the Company, regardless of fault, contained in the PSA, and for certain other matters. Fieldwood has also agreed to indemnify us, our Affiliates (as defined in the PSA) and our respective directors, managers, general partners, officers, agents, employees, consultants, equity owners, stockholders and other representatives against certain losses (excluding certain retained liabilities of Seller) resulting from any breach of any

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representations, covenants or obligations of Fieldwood contained in the PSA and, subject to certain limitations, the operation and ownership of the assets acquired pursuant to the PSA, regardless of fault, and damages, including environmental damages, relating thereto.

New Swap Transactions. On January 24, 2014, we entered into the following swap transactions:

Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month	NYMEX Strike Price
February 2014 - February 2014	Swap	271,672	4.47
March 2014 - March 2014	Swap	342,217	4.47
April 2014 - April 2014	Swap	287,089	4.47
May 2014 - May 2014	Swap	282,346	4.47
June 2014 - June 2014	Swap	231,998	4.47
July 2014 - July 2014	Swap	245,330	4.47
August 2014 - August 2014	Swap	223,294	4.47
September 2014 - September 2014	Swap	207,094	4.47
October 2014 - October 2014	Swap	202,612	4.47
November 2014 - November 2014	Swap	186,296	4.47
December 2014 - December 2014	Swap	219,770	4.47
January 2015 - January 2015	Swap	203,909	4.47
February 2015 - February 2015	Swap	178,341	4.47
March 2015 - March 2015	Swap	177,093	4.47

New Swap Transactions. On March 20, 2014, we entered into the following swap transactions:

Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month	NYMEX Strike Price
February 2014 - February 2014	Swap	271,672	4.47
March 2014 - March 2014	Swap	342,217	4.47
April 2014 - April 2014	Swap	287,089	4.47
May 2014 - May 2014	Swap	282,346	4.47
June 2014 - June 2014	Swap	231,998	4.47
July 2014 - July 2014	Swap	245,330	4.47
August 2014 - August 2014	Swap	223,294	4.47
September 2014 - September 2014	Swap	207,094	4.47
October 2014 - October 2014	Swap	202,612	4.47
November 2014 - November 2014	Swap	186,296	4.47
December 2014 - December 2014	Swap	219,770	4.47
January 2015 - January 2015	Swap	203,909	4.47
February 2015 - February 2015	Swap	178,341	4.47
March 2015 - March 2015	Swap	177,093	4.47

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedure

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

As required by Rule 15d-15(b) under the Exchange Act, management annually reviews our accounting policies and practices, and as a result of such review, identified it had an ineffective financial reporting process and inconsistent review of certain routine accrual calculations and journal entries. As a result of these material weaknesses (as further discussed below), our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures as of December 31, 2013 were not effective at a reasonable level of assurance, based on the evaluation of these controls and procedures required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act. Notwithstanding the material weaknesses further discussed below, our Chief Executive Officer and Chief Financial Officer believe that the financial statements included in this report fairly present in all material respects (and in accordance with U.S. generally accepted accounting principles) our financial condition, results of operations and cash flows for the periods presented.

Management’s Report on Internal Control over Financial Reporting

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

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

Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this evaluation, management used the criteria established in 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In connection with such evaluation, our management identified material weaknesses in our control environment based on the criteria established in the 1992 Internal Control-Integrated Framework issued by the COSO. A material weakness is a control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements will not be prevented or detected.

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

Remediation of a Material Weakness

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

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

Changes in Internal Controls over Financial Reporting

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

• Appointment of our Chief Financial Officer in January 2014;

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

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

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

This Annual Report on Form 10-K does not include an attestation report from UHY LLP, the Company's independent registered public accounting firm, regarding internal control over financial reporting. Management's report was not subject to attestation by UHY LLP, pursuant to SEC rules that permit the Company to provide only management's report in this Annual Report on Form 10-K.

Item 9B. Other Information.

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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.

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.

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 Credit Facility as of December 31, 2013 had no borrowing capacity and as of that date we had $34.5 million outstanding.

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.

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.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table sets forth the names, ages and offices of our directors, executive officers and other key employees. There were no family relationships among any of our managers or executive officers. Pursuant to the terms of our Second Amended and Restated Operating Agreement, the members of our Board of Managers are appointed by the holders of our Class B Units and our executive officers are appointed by, and serve at the pleasure of, our Board of Managers.

Name	Age	Title
John Hoffman	55	President, Chief Executive Officer and Manager
Jeff Shulse	43	Chief Financial Officer
Daniel Small	44	Manager

Set forth below is the description of the backgrounds of our managers, executive officers and other key employees.

John Hoffman. As one of our founders, John Hoffman has served as our President and Chief Executive Officer since our inception in January 2008. He has also served as a member of our Board of Managers since that time pursuant to the terms of our Second Amended and Restated Operating Agreement. Mr. Hoffman is a Registered Professional Engineer with 30 years of industry experience. Mr. Hoffman has extensive experience in field development and operations, onshore and offshore. Prior to starting and building our Company, Mr. Hoffman held various leadership positions at Amoco Corporation, a global chemical and oil company (“Amoco”), from 1981 to 1996, including from 1991 to 1996 at Gulf of Suez Petroleum, a joint venture owned in equal shares by BP and The Egyptian General Petroleum Company, BP America Inc., a leading producer of oil and natural gas in the United States, from 1996 to 2006 and Stone Energy Corporation, an independent oil and gas company, from 2006-2007. His new field development experience spans internationally in the Egyptian Western Desert and Gulf of Suez. In the United States, his developments include major projects in deepwater Gulf of Mexico as well as on the OCS margins. Mr. Hoffman has extensive exploitation experience and knowledge with a unique demonstrated track record of increasing reserves and production while lowering costs. Mr. Hoffman has numerous publications in journals for his work on sand control, subsea wells and innovative coiled tubing pipelines. During his time with Gulf Suez Petroleum, Mr. Hoffman was awarded the Chairman’s Award for Operational Excellence. Mr. Hoffman received this prestigious Chairman’s Award once more during his tenure with Amoco while working the Amoco Deepwater Strategy. Further distinguishing his superior business skills, Mr. Hoffman was honored as a winner of Ernst & Young Entrepreneur of the Year Gulf Coast Area Award in 2011.

Jeff Shulse. Jeff Shulse serves as our Chief Financial Officer, a position he has held since January 2014. Mr. Shulse has over 20 years of finance, M&A and oilfield operations experience. Most recently, Mr. Shulse was founder and President of Freedom Well Services, a consolidated subsidiary of the Company. Prior to launching Freedom Well Services, Mr. Shulse was VP of Finance with Norse Cutting & Abandonment, CFO and General Counsel for American InfoSource and has public accounting experience with both Arthur Andersen LLP and Deloitte Touche Tohmatsu Limited in the areas of M&A, structured finance and taxation. Mr. Shulse is a Certified Public Accountant and a member of the State Bar of Texas and holds a Bachelor of Business Administration in Accounting from the University of Houston and a JD from the University of Houston Law Center.

Daniel Small. Daniel Small has served as a member of our Board of Managers since July 2009. Mr. Small was appointed to our Board of Managers pursuant to the terms of our Second Amended and Restated Operating Agreement, which allows PPVA Black Elk (US) Corp. or its affiliates to appoint one manager as long as PPVA Black Elk (US) Corp. or its successor holds units in our company. He is also a Managing Director at Platinum Management (NY) LLC, the investment advisor to Platinum Partners Value Arbitrage Fund LP, a New York based multi-strategy investment fund, a position he has held since January 2007. Mr. Small leads the firm’s private placement group and is responsible for overseeing the day to day activities of the group including investment management, sourcing, marketing and administration. Before joining Platinum, from January 2004 to December 2006, Mr. Small was a Senior Analyst and served on the investment committee at Glenview Capital Management, a $7.0 billion hedge fund. Mr. Small is a graduate of the Wharton School, magna cum laude, with majors in finance, accounting and political science and earned a J.D. from the University of Pennsylvania Law School.

Corporate Governance

Because the registration statement filed in June 2011 registers only debt securities and because we do not have and are not seeking to list any securities on a national securities exchange or on an inter-dealer quotation system, we are not subject to a

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number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, we are not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, our Board of Managers has not established a separately designated standing audit committee or made any determination as to whether any of the members of our Board of Managers, or any committees thereof, would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition.

Code of Ethics

We have adopted a Code of Business Ethics and Conduct, which sets forth ethical standards for our officers and employees. This document will be provided free of charge to any unitholder requesting a copy by writing to Investor Relations, Black Elk Energy Offshore Operations, LLC, 11451 Katy Freeway, Suite 500, Houston, Texas 77079.

Item 11. Executive Compensation

Compensation Discussion and Analysis

Introduction

Our executive compensation program is overseen by our Chief Executive Officer, Chief Financial Officer, and Human Resource Manager (the “Committee”). The Committee has the ultimate responsibility for making decisions relating to the compensation of our named executive officers. Our Chief Executive Officer reviews compensation for all of our named executive officers and makes compensation recommendations to the other members of the Committee. The Committee then evaluates the initial recommendations and conducts a separate review and evaluation of the named executive officers’ compensation. Finally, the Committee makes a final determination with respect to compensation for all named executive officers based on several factors, including individual performance, performance of the business and, to the extent available, general information related to compensation of executive officers at other private companies. As a general matter, members of the Committee do not set their own compensation. Rather, the compensation for each named executive officer on the Committee is reviewed and set by the other two members of the Committee. The Committee generally approves any changes to base salary levels, bonus opportunities and other annual compensation components on May 1, 2013. The Company did not utilize a compensation consultant in 2013.

The named executive officers for our fiscal year ending December 31, 2013, and who are described in this Compensation Discussion and Analysis section, are:

• John Hoffman—President and Chief Executive Officer

• Gary Barton—Former Interim Chief Financial Officer

• Bruce Koch—Former Chief Financial Officer

Objective of Our Executive Compensation Program

The objective of our executive compensation program is to attract and retain experienced leaders in their respective fields of expertise to work as members of our executive team, while aligning their interests with those of our investors.

We attract and retain highly talented and experienced executives in part by setting base salaries that the Committee believes, based on the Committee members’ extensive experience in the industry, are competitive with the base salaries paid to executives at other companies like ours in the energy industry. While we do not benchmark any of our compensation against compensation paid by any other company, the Committee considers the total compensation paid to each named executive officer over the course of each year to ensure that the total amounts paid by us are commensurate with the Committee members’ sense of the total compensation paid by other companies with which we compete for executive talent, based on their experience in the industry.

We provide our named executive officers with the opportunity to earn cash bonus awards to reward the executives’ contribution to our success, growth, and the achievement of strategic goals. We provide our named executive officers with a portion of the distributions paid to our investors through our profit sharing arrangements. We believe that by rewarding our named executive officers for the achievement of shorter-term goals through our cash bonus awards and by allowing them to receive a portion of the distributions paid to our investors, we are attracting talented executives to join us and stay with us, while also aligning their interests with those of our investors.

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Components of our Compensation

Our compensation and benefits programs have historically consisted of the following components, which are described in greater detail below:

• Base salary;

• Cash bonus awards based on both individual performance and our company’s performance;

• Profit sharing arrangements;

• Severance and change in control benefits; and

• Participation in broad-based retirement, health and welfare benefits.

Base Salary

Each named executive officer’s base salary is a fixed component of compensation and does not vary depending on the level of performance achieved. Base salaries for our named executive officers have historically been the product of negotiations with each individual as to what level of salary is necessary to retain the executive’s services. During these negotiations, the Committee typically considers the individual’s position, experience, past performance, and responsibilities. The Committee reviews the base salaries for each named executive annually as well as at the time of any promotion or significant change in job responsibilities, and in connection with each review, the Committee considers general individual and company performance over the course of that year.

We believe each named executive officer’s base salary component of compensation is set at a level that furthers the objectives of our compensation program by providing base pay that is competitive with amounts paid by companies with which we compete for executive talent. The determination as to the ultimate amount, competitiveness, and reasonableness of a named executive officer’s salary is made by the Committee based on the members’ extensive experience in the energy industry, and the Committee’s determination is subject to approval by our Board of Managers with respect to any increase in base salary. The base salary paid to each named executive officer for the 2013 fiscal year is reported in the succeeding Summary Compensation Table. In 2013 and 2012, John Hoffman did not receive a salary increase. All officers received a salary as reported in the table below:

		Annual	Annual
		Salary	Salary May -
		January -	December	2013 Salary
Name and Principal Position	Year	April 2013	2013	Adjustment
John Hoffman, CEO	2013	300,000	300,000	—
Gary Barton Former Interim CFO (1)	2013	300,000	—	(300,000	)
Bruce Koch, Former CFO	2013	287,500	287,500	—

(1) Mr. Barton served as (Interim) CFO from January 25, 2013 through April 15, 2013 under a Jan 25, 2013 engagement letter (the "January 2013 Engagement Letter") with Alvarez & Marsal North American, LLC ("A&M"), a global professional services firm specializing in turnaround and interim management, performance improvement and buisness advisory services. During Mr. Barton's service with the Company in accordance with the January 2013 Engagement Letter, the Company paid A&M $100,000 per month as compensation for Mr. Barton's services.

Bonuses

All bonuses provided by us to our named executive officers are paid in cash in amounts and at times determined at the discretion of the Committee. We do not set or communicate predetermined goals or metrics for the payment of our bonuses to our employees. Bonuses can be paid based on any considerations the Committee deems appropriate, including our growth and success, which may be measured at any point during the year through a number of metrics, including but not limited to, production levels, reserve growth, the achievement of strategic business goals, and financial metrics such as EBITDA. After considering these and other factors, the Committee determines when our performance and the performance of our employees warrants the payment of a cash bonus. Once the Committee determines that a bonus should be paid, it sets a “bonus pool amount,” the total amount of all bonuses that will be paid to employees. The bonus pool amount is determined in the discretion of the Committee after considering the magnitude of the accomplishment for which the bonus is to be paid as well as our budget. The Committee members determine the amount of each individual award after considering the level of contribution made by each employee to the accomplishment of the particular achievement and the reasonableness of each employee’s total

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compensation for the year, as determined in the Committee’s discretion based on the Committee members’ experience in the industry. Although all bonuses are discretionary and we have no obligation to pay any amount of bonus to any named executive officer, the Committee does take into consideration each named executive officer’s target bonus, to the extent such a target was included in the executive’s offer letter.

We believe our bonus program, and in particular its flexibility, helps us to achieve the objectives of our compensation program by rewarding our named executive officers for their level of contribution to our most important achievements, thus aligning their interests with those of our investors. Further, when determining the amounts of the bonus awards to each named executive officer, the Committee considers the competitiveness of the individual bonus payments as well as the competitiveness of the overall annual pay for each named executive officer, as compared to the amounts paid to executives at the companies with which we compete for executive talent. These considerations ensure that our named executive officers’ bonus compensation is both reasonable and competitive, based on the Committee members’ experience in the industry.

Profit Sharing

We have always believed that it is important to tie the interests of our named executive officers to those of our investors. We have historically accomplished this goal by granting profits interests in Black Elk Energy, LLC (which in turn holds a portion of our Class B Units) to a select group of our executive officers. During our reorganization in 2010, we established the Black Elk Energy Offshore Operations, LLC 2010 Employee Incentive Plan (the “Incentive Plan”), a mechanism through which we can grant profits interests in Black Elk Employee Incentive, LLC (“Incentive LLC”), which in turn holds all of our Class C Units. While our named executive officers still hold previously granted profits interests in Black Elk Energy, LLC, beginning with fiscal year 2010, we have granted only, and plan in the future to only grant profits interest to our executives solely through the Incentive Plan.

The Incentive Plan provides our executives with an opportunity to share in the distributions made to our investors. The degree to which our named executive officers share in distributions is determined by the Committee based on experience, responsibility, and tenure. Generally, upon a named executive officer’s termination from employment with us for any reason, the interests held by the individual (including any capital account) will be forfeited. The named executive officers may not sell or transfer their interests in either Black Elk Energy, LLC or Incentive LLC. To date, the only distributions that have been made to our named executive officers have been distributions equivalent to the tax liability incurred by each named executive officer by holding profits interests in Black Elk Energy, LLC or Incentive LLC.

We believe this program furthers the objectives of our compensation program by providing an opportunity for each named executive officer to earn additional compensation, thus increasing the competitiveness of our compensation packages, while aligning the named executive officers’ financial interests with those of our investors.

No awards were made under the Incentive Plan in 2013 or 2012.

Severance and Change in Control Benefits

Mr. Hoffman has (and Mr. Koch had) employment agreements with us that contain severance provisions. Upon termination of Mr. Hoffman's employment (i) by the executive due to a material breach of the employment agreement by us, uncorrected for 30 days following written notice, or (ii) by us without cause, then the executive will be entitled to receive a lump-sum severance payment in an amount equal to one year’s annual base salary of the executive, plus continuation of certain employee benefits for one year. In addition, Mr. Hoffman's employment agreement includes a severance due to termination by the executive upon a change in control.

We believe that severance protection provisions create important retention tools, as post-termination payments would allow Mr. Hoffman to leave our employment with value primarily in the event of certain terminations of employment that were beyond their control. Post-termination payments allow our senior executive management to focus their attention and energy on making objective business decisions that are in our best interest without allowing personal considerations to cloud the decision-making process. Executive officers at other companies in our industry, and the general market against which we compete for executive talent, commonly have post-termination payments and we have consistently provided this benefit to certain of our executive officers in order to remain competitive in attracting and retaining skilled professionals in our industry. For more information please see the section entitled “Potential Payments Upon a Termination or Change in Control” below.

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Other Benefits

We pay 100% of the insurance premiums for all of our employees, including their spouses and dependents, for health, dental, vision, life, and accidental death and dismemberment insurance. We also pay 100% of health club memberships for employees. We provide Mr. Hoffman with enhanced life and disability insurance and kidnap and ransom insurance; otherwise, the insurance benefits provided to our named executive officers are the same as those provided to our employees generally. In addition, in 2013 and 2012 we paid for the provision of tax preparation services for Mr. Hoffman.

Our 401(k) plan is designed to encourage all employees, including the participating named executive officers, to save for the future. We make a non-elective contribution equal to 3% of each employee’s total compensation for the plan year. Additionally, we match 50% of all employee contributions to the plan, up to a maximum of 3% of each employee’s total compensation for the plan year. Thus, each of our employees receives 401(k) contributions from us of at least 3% and up to 6% (depending on the level of their own contributions) of their total compensation each year. The plan increases the competitiveness of our total compensation package and aids in retaining our named executive officers. We do not have a supplemental executive retirement plan.

Risk Assessment

The Committee has reviewed our compensation policies as generally applicable to our employees and believes that our policies do not encourage excessive and unnecessary risk-taking, and that the level of risk that they do encourage is not reasonably likely to have a material adverse effect on us. The components of our compensation program are base salary, cash bonuses, profit sharing opportunities (for some employees), health and welfare benefits, and participation in a 401(k) retirement plan. These compensation components are generally uniform in design and operation throughout our organization and with all levels of employees. These compensation policies and practices are centrally designed and administered. In addition, the following factors, in particular, reduce the likelihood of excessive risk-taking:

• Our overall compensation levels are competitive with the market, both industry-wide and geographically.

• Our compensation mix is balanced among (i) fixed components like salary and benefits, (ii) discretionary cash incentives that reward our overall financial performance, operational measures and individual performance, and (iii) our profit sharing arrangements.

• The Committee has discretion to reduce or eliminate cash bonuses when it determines that such adjustments would be appropriate based on our interests.

In summary, although a significant portion of the compensation provided to named executive officers is performance-based, we believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees), in particular because our cash bonuses are entirely discretionary. As such, they are not based on specific pre-determined metrics that could be manipulated by particular behavior by our employees.

Summary Compensation Table

The table below sets forth the annual compensation earned during the 2013 Fiscal Year by our “named executive officers,” as of December 31, 2013:

Name and Principal Position	Year	Salary ($)  (1)	Bonus ($)  (2)	Non-Equity Incentive Plan Compensation ($) (3)	All Other Compensation ($) (4)	Total ($)
John Hoffman, CEO	2013	300,000			68,389	368,389
	2012	300,000	—	1,555,510	66,705	1,922,215
	2011	300,000	270,000	1,722,232	82,327	2,374,559
Gary Barton, Former Interim CFO (5)	2013	300,000	—	—	—	300,000
Bruce Koch, Former CFO	2013	287,500	—	—	—	287,500

___________________________________

(1) The amounts in this column reflect the base salary actually paid to each named executive officer during the fiscal year.

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(2) The amounts in this column reflect the total amount of bonus compensation received by each named executive officer during the applicable fiscal year. No bonuses were paid to the named executive officers in 2013.

(3) The amounts in this column represent tax distributions received by each of the named executive officers with regard to forfeitable interests in Incentive LLC and Black Elk Energy, LLC, described in detail in the narrative description to the Summary Compensation Table, below. The named executive officers receive tax distributions because the LLCs in which they hold interests are categorized as partnerships for federal income tax purposes and, as such, our profits flow through and become taxable to our owners, even if no distributions are made. These tax distributions are intended to cover any tax liability the named executive officers have so incurred. The named executive officers’ interests are held indirectly through 197 units in Incentive LLC that Mr. Hoffman was granted during 2010 and 170 units in Black Elk Energy, LLC that Mr. Hoffman was granted prior to 2010. Mr. Hoffman also holds interests in us through 45 units in Management Incentive Units 09 and 827 units in Black Elk Management, LLC. These interests were granted in 2009.

(4) With respect to Mr. Hoffman the amount in this column represents the aggregate incremental cost to us of providing the following benefits: (a) our contribution to his individual account under our 401(k) plan, (b) supplemental life and disability insurance ($36,266), and (c) tax preparation ($8,800). With respect to Mr. Koch the amount in this column represents the aggregate incremental cost to us of providing the following benefits: (a) our contribution to his individual account under our 401(k) plan, (b) tax preparation ($8,800) and (c) severance payment ($275,814).

(5) Mr. Barton served as CFO from January 25, 2013 through April 15, 2013 under a Jan 25, 2013 engagement letter (the "January 2013 Engagement Letter") with Alvarez & Marsal North American, LLC ("A&M"), a global professional services firm specializing in turnaround and interim management, performance improvement and buisness advisory services. During Mr. Barton's service with the Company in accordance with the January 2013 Engagement Letter, the Company paid A&M $100,000 per month as compensation for Mr. Barton's services.

Grants of Plan-Based Awards for the 2013 Fiscal Year

We did not grant any plan-based awards to our executive officers during the 2013 fiscal year.

Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year

Employment Agreements

We entered into an employment agreement with Mr. Hoffman in 2009 (the "Prior Employment Agreement") for a three-year term, with no automatic renewal, and a minimum base salary for Mr. Hoffman of $300,000. The Prior Employment Agreement generally provided that Mr. Hoffman could participate in any welfare, benefit, or incentive plan generally available to our other executive officers. Mr. Hoffman was entitled to four weeks of vacation per year. The Prior Employment Agreement also provided for severance payments under certain circumstances, discussed in detail below in the section entitled “Potential Payments Upon Termination or a Change in Control.” The Prior Employment Agreement also contained provisions assigning our business opportunities and any intellectual property developed by the executives while working for us to us. The Prior Employment Agreement contained a non-compete obligation that applied throughout Mr. Hoffman’s employment with us and—in the event of a termination of employment by us for cause or an automatic termination of employment upon death, disability, voluntary resignation, or retirement—following employment until the earlier of (i) the repayment in full of the obligations under a credit agreement, or (ii) July 13, 2012. Mr. Hoffman agreed not to solicit our clients or employees during their employment with us and until the later of one year from their termination date or July 13, 2012. The Prior Employment Agreements also contained non-disparagement and confidentiality obligations. The Prior Employment Agreements expired on July 13, 2012.

On July 13, 2013, we entered into employment agreements with Mr. Hoffman (collectively the “2012 Employment Agreement”). The 2012 Employment Agreement provides for a three-year term, with no automatic renewal, and a minimum base salary for Mr. Hoffman of $300,000. The 2012 Employment Agreement generally provides that Mr. Hoffman can participate in any welfare, benefit, or incentive plan generally available to our other executive officers. Mr. Hoffman, is entitled to four weeks of vacation per year. The 2012 Employment Agreement also provides severance payment to Mr. Hoffman under certain circumstances, discussed in detail below in the section entitled “Potential Payments Upon Termination or a Change in Control.” The 2012 Employment Agreement also contains provisions assigning our business opportunities and any intellectual property developed by Mr. Hoffman while working for us to us. The 2012 Employment Agreement contains a non-compete obligation that applies throughout Mr. Hoffman's employment with us and—in the event of a termination of employment by us for cause or an automatic termination of employment upon death, disability, voluntary resignation, or retirement—following employment until the earlier of (i) the repayment in full of the obligations under a credit agreement, or (ii) July 13, 2015 . Mr. Hoffman also agrees not to solicit our clients or employees during their employment with us and until the later of (A) one year

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from their termination date or (B) July 13, 2015. The 2012 Employment Agreement also contains non-disparagement and confidentiality obligations.

Profit Sharing

The distributions enumerated in the Non-Equity Incentive Plan Compensation column to the Summary Compensation Table reflect each named executive officer’s tax distributions as described in footnote 3 in this table. These tax distributions relate to interests held indirectly through interests in Incentive LLC (which in turn owns all of our Class C Units) and/or through Black Elk Energy, LLC (which in turn holds some of our Class B Units). All interests held by our named executive officers in Incentive LLC were granted during 2010 under our Incentive Plan, and interests in Black Elk Energy, LLC were granted prior to 2010. Both interests in Black Elk Energy, LLC and Incentive LLC are intended to be “profits interests.”

Awards may be granted under our Incentive Plan to our employees, directors and consultants. Awards under the Incentive Plan represent a percentage interest of the total membership interest of Incentive LLC. If an award under the Incentive Plan terminates or is canceled then new awards can be granted. Unless we determine otherwise, and except with regard to Mr. Hoffman, the termination of a named executive officer’s employment with us for any reason will terminate the executive’s ownership of any interest in Incentive LLC and that executive will not be entitled to any outstanding balance in his or her capital account. The named executive officers may not sell or transfer their interests in Incentive LLC.

Pension Benefits

We have not maintained, and do not currently maintain, a defined benefit pension plan.

Nonqualified Deferred Compensation

We have not maintained, and do not currently maintain, a nonqualified deferred compensation plan.

Potential Payments Upon Termination or a Change in Control

Mr. Hoffman

Mr. Hoffman has an employment agreement with us that contains severance provisions. Upon termination of Mr. Hoffman (i) by the executive due to a material breach of the employment agreement by us, uncorrected for 30 days following written notice, (ii) by the executive upon a change in control, or (iii) by us without cause, then the executive will be entitled to receive a lump-sum severance payment in an amount equal to one year’s annual base salary of the executive, plus continuation of benefits generally provided to our executives, currently including company 401(k) contribution, plus continued medical, dental, vision, life and disability insurance coverage for one year.

The 2012 Employment Agreement provides that “cause” means generally (i) the executive’s conviction of, or plea of nolo contendere to, any felony or to any crime or offense causing substantial harm to us or involving acts of theft, fraud, or embezzlement, (ii) willful and intentional misuse or diversion of any of our funds, (iii) embezzlement, (iv) fraudulent or willful and material misrepresentations, or (v) material breach by executive of any material provision of the 2012 Employment Agreement which is not corrected within 30 days following written notice.

The 2012 Employment Agreement provides that “change of control” means generally (i) the sale or lease of substantially all of our assets, or (ii) a transaction in which the holders of our voting stock immediately prior to such transaction own, immediately after such transaction, securities representing less than 50% of the voting power of the surviving entity. A transaction solely for the purpose of effecting a change in our domicile will not constitute a “change of control.”

The following table enumerates the payment that would have been due to Mr. Hoffman if his employment had been terminated on December 31, 2013, (i) due to a material breach of the employment agreement by us, uncorrected for 30 days following written notice, (ii) by the executive upon a change in control, or (iii) by us without cause.

Name and Principal Position	One Year of Base Salary Paid in Lump-Sum(1)		Value of One Year of Benefits (2)		Total Value of Severance Obligation
John Hoffman, CEO	$	300,000	$	68,389	$	368,389

___________________________________

(1) The numbers in this column represent Mr. Hoffman’s base salary in effect as of December 31, 2013.

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(2) The numbers in this column represent a lump sum payment in an amount equal to our 401(k) contribution for a year ($13,750 ) as well as the value of medical, dental, vision, life and disability insurance coverage for one year ($68,389). The lump sum amount with respect to 401(k) contribution is calculated based on our contribution to each executive’s individual 401(k) account for fiscal year 2013.

Mr. Barton

Mr. Barton served as CFO from January 25, 2013 through April 15, 2013 under a Jan 25, 2013 engagement letter (the "January 2013 Engagement Letter") with Alvarez & Marsal North American, LLC ("A&M"), a global professional services firm specializing in turnaround and interim management, performance improvement and business advisory services. During Mr. Barton's service with the Company in accordance with the January 2013 Engagement Letter, the Company paid A&M $100,000 per month as compensation for Mr. Barton's services.

Mr. Koch

On January 9, 2014, Black Elk Energy Offshore Operations, LLC (the “Company”) announced the resignation of Bruce Koch, Vice President and Chief Financial Officer, effective January 7, 2014. The terms of Mr. Koch’s employment agreement included a lump sum severance compensation in an amount equal to one year's annual base salary, plus the benefits for one year the he was entitled to under his employment agreement.

The following table enumerates the amount of severance paid to Mr. Koch:

2014 Severance Payments:	Severance	Benefits	Total
Bruce Koch Former CFO			—

Director Compensation

We do not compensate any of our managers for their service on our Board. We do, however, reimburse our managers for expenses associated with travel to and from any required board meetings.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Our membership interests are represented by Class A Units, Class B Units, Class C Units and Class E Units. 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 our 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.

As of March 31, 2014, there were 1,361,300 Class A Units, 114,277,308.5 Class B Units, 12,031,250 Class C Units and 109,743,693 Class E Units issued and outstanding. The Class A and Class B Units have voting rights; the Class C Units and Class E Units do not have voting rights.

None of our managers or executive officers directly owns any Class A Units, Class B Units, Class C Units, or Class E Units. All of our issued and outstanding Class A Units are owned by PPVA Black Elk (Equity) LLC (“PPVA (Equity)”), a wholly owned subsidiary of Platinum Partners Value Arbitrage Fund, L.P. PPVA (Equity), PPVA Black Elk (Investor) LLC, additional wholly owned subsidiaries of Platinum Partners Value Arbitrage Fund, L.P., and Platinum Partners Black Elk Opportunities Fund, LLC (“PPBE”) also own Class B Units. PPVA (Equity), PPBE, and Platinum Partners Black Elk Opportunities Fund International, LLC also own our issued and outstanding Class E Units. Additional information regarding Platinum’s significant ownership interest in us is set forth below, as well as under “Item 13. Certain Relationships and Related Transactions and Director Independence” in this Form 10-K.

Our executive officers and other key employees indirectly own Class B Units through their ownership of Black Elk Energy, LLC. See “Item 11. Executive Compensation—Components of our Compensation—Profit Sharing” for additional information. Our Chief Executive Officer also indirectly owns Class B Units through his ownership of Black Elk Management, LLC.

All of our issued and outstanding Class C Units are held by Black Elk Employee Incentive, LLC. Class C Units are profits interests that are awarded from time to time to our executive officers and other key employees. See “Item 11. Executive Compensation—Components of our Compensation—Profit Sharing” for additional information regarding the Class C Units.

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The following table sets forth information regarding the beneficial ownership of our total voting membership interests, consisting of our Class A and Class B Units, as of March 31, 2014 for:

• each of our members;

• each of our executive officers;

• all our members and executive officers as a group; and

• each other person known by us to beneficially own more than 5% of our total voting membership interests.

Footnote 1 to the following table provides a brief explanation of what is meant by the term “beneficial ownership.” The voting membership interests and related percentages of beneficial ownership are based on our total outstanding voting membership interests as of March 31, 2014. The amounts presented may not add due to rounding.

To our knowledge and except as indicated in the footnotes to this table and subject to applicable community property laws, the persons named in this table have the sole voting power with respect to the membership interests listed as beneficially owned by them.

Name and Address of Beneficial Owner (1)	Number of Class A Units Beneficially Owned	Number of Class B Units Beneficially Owned	Percentage of Voting Membership Interests Beneficially Owned (2)
Manager and Named Executive Officers (3):
John Hoffman (4)	—	9,030,757	7.81	%
Jeff Shulse (5)		—	*
Dan Small	—	—	*
All Managers and Executive Officers as a Group (Three persons)	—	9,030,757	7.81	%
5% Beneficial Owners:
Black Elk Management, LLC (4) (6)	—	8,267,187	7.15	%
PPVA Black Elk (Equity) LLC (7)	1,361,300	72,808,822	64.14	%
PPVA Black Elk (Investor) LLC (8)	—	21,919,100	18.95	%
Platinum Partners Black Elk Opportunities Fund, LLC (9)	—	1,284,400	1.11	%
Platinum Partners Credit Opportunities Fund International, LLC (10)		360,000	*

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 * Less than 1%

(1) “Beneficial ownership” is a term broadly defined by the SEC in Rule 13d-3 under the Exchange Act and includes more than the typical forms of stock ownership, that is, stock held in the person’s name. The term also includes what is referred to as “indirect ownership,” meaning ownership of shares as to which a person has or shares investment or voting power, or a person who, though a trust or proxy, prevents the person from having beneficial ownership. For the purpose of this table, a person or group of persons is deemed to have “beneficial ownership” of any units as of April 9, 2013, if that person or group has the right to acquire such units within 60 days after such date.

(2) The percentage of voting members interests in based on voting Class A Units and Class B Units.

(3) The address for each manager and executive officer is: c/o Black Elk Energy LLC, 11451 Katy Freeway, Houston, Texas 77079 Suite 500, Houston, Texas 77079.

(4) Includes (i) 8,267,187 Class B Units held indirectly through Mr. Hoffman’s 100% ownership of Black Elk Management, LLC and (ii) 763,569.94 Class B Units held indirectly through Mr. Hoffman’s 13.9% ownership of Black Elk Energy, LLC (Black Elk Energy, LLC owns less than 5% of our voting membership interests).

(5) Black Elk Management, LLC is owned 100% by Mr. Hoffman. Mr. Hoffman has voting and dispositive power with respect to 826.72 of the Class B Units held by Black Elk Management, LLC. Mr. Hoffman disclaims any beneficial ownership of these Class B Units, except to the to the extent of his pecuniary interest therein. Black Elk Management, LLC has the following address: c/o Black Elk Energy, 11451 Katy Freeway, Suite 500, Houston, Texas 77079.

(6) PPVA Black Elk (Equity) LLC is wholly owned by Platinum Partners Value Arbitrage Fund, L.P. which has sole voting and dispositive power with respect to such Class A and Class B Units. PPVA Black Elk (Equity) LLC has the following address: c/o Platinum Partners Value Arbitrage Fund, L.P., 152 West 57th Street, 4th Floor, New York, New York 10019.

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(7) PPVA Black Elk (Investor) LLC is wholly owned by Platinum Partners Value Arbitrage Fund, L.P. which has sole voting and dispositive power with respect to such Class B Units. PPVA Black Elk (Investor) LLC has the following address: c/o Platinum Partners Value Arbitrage Fund, L.P., 152 West 57th Street, 4th Floor, New York, New York 10019.

(8) Platinum Partners Black Elk Opportunities Fund, LLC has the sole voting and dispositive power with respect to such Class B Units. Platinum Partners Black Elk Opportunities Fund, LLC has the following address: 152 West 57th Street, 54th Floor, New York, New York 10019.

(9) Platinum Partners Credit Opportunities Fund International, LLC has the sole voting and dispositive power with respect to such Class B Units. Platinum Partners Platinum Partners Credit Opportunities Fund International, LLC has the following address: 152 West 57th Street, 54th Floor, New York, New York 10019.

Through its ownership, and pursuant to the terms of our Second Amended and Restated Operating Agreement, (as amended and in effect as of the date of this Form 10-K), Platinum is able to exercise significant control over us, including the determination of company and management policies, our financing arrangements, the payment of dividends or other distributions, and the outcome of certain company transactions or other matters submitted to our members for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. Platinum also has the ability to appoint all of the members of our Board of Managers and the Board of Managers, in turn, has the power to appoint and remove our officers. Platinum also has the ability to determine the outcome of most actions requiring approval by our members, including veto power. Specifically, without Platinum’s consent, we may not:

• amend our Second Amended and Restated Operating Agreement or our Certification of Incorporation;

• approve or materially modify executive compensation;

• repurchase any of our units or other equity securities;

• enter into any merger, consolidation, reorganization or other business combination or transaction;

• sell, transfer, lease, license, pledge or dispose of any of our assets for a purchase price of more than $0.5 million other than capital expenditures and acquisitions contemplated by our annual budget;

• initiate any public offering;

• enter into a transaction with any of our managers or members or affiliate or member of family thereof;

• enter into a transaction that would have a materially disproportionate impact on Platinum over our other members; or

• make any distribution other than that contemplated by our Second Amended and Restated Operating Agreement.

Additionally, if we propose to obtain additional financing through the issuance of equity or certain debt securities, Platinum is entitled to a right of first offer to provide such financing. Platinum, along with the other members, also has a right of first refusal with respect to other equity holders’ proposed transfers of our equity interests.

Platinum may transfer all or a portion of its ownership interests to a third party without the consent of the other members. The new owner of the Platinum ownership interest may then be in a position to replace our Board of Managers and officers with its own designees and thereby exert significant control over the decisions made by our Board of Managers and officers.

For additional information regarding the risk associated with Platinum’s significant ownership interest in us, see “Item 1A. Risk Factors—Platinum owns approximately 85% of our outstanding voting membership interests, giving it influence and control in corporate transactions and other matters, which may conflict with noteholders’ interests.”

Item 13. Certain Relationships and Related Transactions and Director Independence

Director Independence

For a description of director independence, see “Item 10. Directors, Executive Officers and Corporate Governance.”

Certain Relationships and Related Transactions

Platinum

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

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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).

In the first quarter of 2013, we entered into contribution agreements with PPBE or the Platinum Group pursuant to which we have issued, or expect to issue 40 million additional Class E Units and 3 million additional Class B Units to the Platinum Group for an aggregate offering price of $40.0 million. As of April 10, 2013, we have issued an aggregate $50.0 million of Class E Units and 3.8 million Class B Units. On March 31, 2013, we issued an additional 2,522,693.340 Class E Units as paid-in-kind dividends to the holders of Class E Units on such date.

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

Platinum also guarantees our obligations under the W&T Escrow Accounts and the surety bonds in favor of Nippon and the BOEMRE with respect to our future P&A obligations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Description of Other Indebtedness—W&T Escrow Accounts”.

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 which is included in the receivable discussed above.

On May 28, 2013, our consolidated subsidiary 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. The lease arrangement is treated as an operating lease and we incurred approximately $0.2 million of rental expense for the year ended December 31, 2013. As of December 31, 2012, 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 of $0.6 million, which is included in “Accounts payable and accrued expenses”.

Black Elk Energy Expenses

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 which is included in the receivable discussed above.

We pay expenses for certain general and administrative and operating costs on behalf of Black Elk Energy, LLC, the parent company of Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corp. At December 31, 2013 and February 28, 2014, we had receivables from Black Elk Energy, LLC in the amount of $23,430.

For the year ended December 31, 2013 and the two months ended February 28, 2014, we paid $0.2 million and $1.0 million, respectively, to Up and Running Solutions, LLC, for IT consulting services. Up and Running Solutions, LLC is owned by the wife of a former employee, David Cantu (a member of our management). There were no amounts due to the related party at December 31, 2013 or at February 28, 2014.

Policies and Procedures

In the ordinary course of business, we may enter into a related person transaction (as such is defined by the SEC). The policies and procedures relating to the approval of related person transactions are not in writing. Given the relatively small size of our organization, any material related person transactions entered into would be discussed with management and require approval by our Board prior to entering into the transaction.

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Item 14. Principal Accounting Fees and Services

UHY LLP has been retained since 2010 and has performed audit services for the years ended December 31, 2013 and 2012. The following table sets forth the aggregate fees and costs paid to UHY LLP during the last two fiscal years for professional services rendered to us:

	Years Ended December 31,
	2013		2012
Audit Fees (1)	$	574,391	$	540,784
Audit-Related Fees (2)	—		—
Tax Fees (3)	—		—
All Other Fees (4)	—		—
	$	574,391	$	540,784

___________________________________

(1) Reflects fees for services rendered for the audit of our annual financial statements, review of our quarterly financial statements, fees for the review and issuance of consents and comfort letters related to our registration statements, and other SEC filings.

(2) No fees were paid to UHY LLP for audit-related services.

(3) No fees were paid to UHY LLP for tax services.

(4) No other fees were paid to UHY LLP.

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PART IV

Item 15. Exhibits, and Financial Statement Schedules

(a) The following documents are filed as a part of this Form 10-K:

i. Financial Statements—See “Item 8. Financial Statements and Supplementary Data” of this Form 10-K.

ii. Financial Statement Schedules—All schedules have been omitted since the required information is not present or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the Consolidated Financial Statements and notes thereto.

iii. Exhibits—The following is a list of exhibits filed as part of this Form 10-K including those incorporated by reference.

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	Certificate of Formation of Black Elk Energy Finance Corporation, dated as of October 26, 2010 (incorporated by reference to Exhibit 3.3 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	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).
3.5	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)).
3.6	Bylaws of Black Elk Energy Finance Corp., dated as of October 26, 2010 (incorporated by reference to Exhibit 3.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.7	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).
3.8	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).
3.9	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).
3.10	Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of April 9, 2013 (incorporated by reference to Exhibit 3.10 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
3.11	Sixth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of May 3, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on May 9, 2013).
3.12	Third Amendment to the Third Amended and Restated Limited Liability Company Operating Agreement of Blaclk Elk Energy Offshore Operations, LLC, effective as of January 25, 2013.

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Exhibit Number	Description
4.1	Indenture, dated as of November 23, 2010, among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp., as Issuers, the Guarantor party named therein, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
4.2	First Supplemental Indenture, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. as issuers, Black Elk Energy Land Operations, LLC as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).
4.3	Registration Rights Agreement, dated as of November 23, 2010, among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp., the Guarantor party named therein and the Purchasers named therein (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
4.4	Security Agreement, dated as of November 23, 2010, by Black Elk Energy Offshore Operations, LLC, Black Elk Energy Finance Corp., Black Elk Energy Land Operations, LLC in favor of The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent (incorporated by reference to Exhibit 4.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
4.5	Amended and Restated Second Lien Intercreditor Agreement, dated as of December 24, 2010, by and among Capital One, N.A., in its capacity as First Lien Agent for the First Lien Creditors, The Bank of New York Mellow Trust Company, N.A., in its capacity as Indenture Trustee and in its capacity as Collateral Agent for, on behalf of and in the stead of, the Second Lien Creditors, Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. and each other Loan Parties from time to time party thereto (incorporated by reference to Exhibit 4.12 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333174226)).
10.1	Purchase and Sale Agreement, dated September 14, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.2	First Amendment to Purchase and Sale Agreement, dated as of October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.3	Second Amendment to Purchase and Sale Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc. and Black Elk Offshore Operations, LLC (incorporated by reference to Exhibit 10.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.4	Third Amendment to Purchase and Sale Agreement, dated December 19, 2012, by and between W&T Offshore, Inc. and the Company (incorporated by reference to Exhibit 10.6 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
†10.5	Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and John G. Hoffman (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2013).
†10.6	Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and Arthur Garza III (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2013).
†10.7	Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and James F. Hagemeier (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 3, 2012).
†10.8	Engagement Letter, dated January 25, 2013, by and between Black Elk Energy Offshore Operations, LLC and Alvarez & Marsal North America, LLC (incorporated by reference to Exhibit 10.13 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).

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Exhibit Number	Description
†10.9	Amended and Restated Company Agreement of Black Elk Employee Incentive, LLC, dated as of August 20, 2010 (incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 26, 2012).
†10.10	Employment Agreement, dated as of April 16, 2013, by and between Black Elk Energy Offshore Operations, LLC and Bruce Koch (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on April 23, 2013).
†10.11	Employment Agreement, dated January 8, 2014, by and between Black Elk Energy Offshore Operations, LLC and Jeffrey Shulse (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on January 14, 2014).
10.12	Credit Agreement, dated as of December 24, 2010, among Black Elk Energy Offshore Operations, LLC, each of the Lenders from time to time party thereto, and Capital One, N.A. as administrative agent for the Lenders (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.13	First Amendment to Credit Agreement, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).
10.14	Waiver and Second Amendment to Credit Agreement, dated as of June 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.6 to the Form 10-Q for the period ended June 30, 2011 as filed with the Securities and Exchange Commission on August 10, 2011 (SEC File No. 333-174226)).
10.15	Limited Waiver and Third Amendment to Credit Agreement, dated as of November 8, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.1 to the Form 10-Q filed with the Securities and Exchange Commission on November 13, 2012
10.16	Fourth Amendment to Credit Agreement and Other Loan Documents, effective as of December 21, 2012, 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 10.1 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
10.17	Sixth Amendment to Credit Agreement, effective as of January 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 March 11, 2013).
10.18	Limited Waiver and Seventh Amendment to Credit Agreement, effective as of February 22, 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 10.3 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
10.19	Eighth Amendment to Credit Agreement, effective as of March 26, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
10.20	Limited Waiver and Ninth Amendment to Credit Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporate by reference to Exhibit 4.39 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
10.21	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).

110

Exhibit Number	Description
10.22	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).
10.23	Letter of Credit Facility Agreement, dated as of December 24, 2010, among Black Elk Energy Offshore Operations, LLC, as Borrower, Capital One, N.A., as Administrative Agent and the Lenders Party Thereto (incorporated by reference to Exhibit 4.8 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.24	First Amendment to Letter of Credit Facility Agreement, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011
10.25	Second Amendment to Letter of Credit Facility Agreement, dated as of December 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.1 to the Form 10-Q filed with the Securities and Exchange Commission on August 10, 2012).
10.26	Third Amendment to Letter of Credit Facility Agreement, dated as of May 24, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.2 to the Form 10-Q filed with the Securities and Exchange Commission on August 10, 2012).
10.27	Fourth Amendment to Letter of Credit Facility Agreement and Waiver, dated as of November 8, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.2 to the Form 10-Q filed with the Securities and Exchange Commission on November 13, 2012).
10.28	Fifth Amendment to Letter of Credit Facility Agreement and Amendment to Other Loan Documents, effective as of December 21, 2012, 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 10.4 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
10.29	Sixth Amendment to Letter of Credit Facility Agreement and Amendment to Other Loan Documents, effective as of February 22, 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 10.5 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
10.30	Limited Waiver and Seventh Amendment to Letter of Credit Facility Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders, and the Lenders signatory thereto (incorporated by reference to Exhibit 4.40 to the form 10-K with the Securities and Exchange Commission on April 15, 2013).
10.31	Limited Waiver, 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).
10.32	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 (incorporated by reference to Exhibit 10.11 to the Form 10-Q filed with the Securities and Exchange Commission on November 14, 2013).
10.33	Security Agreement, dated as of December 24, 2010, made by Black Elk Energy Offshore Operations, LLC, Black Elk Energy Finance Corp., Black Elk Energy Land Operations, LLC, and The Other Grantors Party Thereto, in favor of Capital One, N.A, not in its individual capacity, but solely as Administrative Agent (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226).
10.34	Pledge and Security Agreement, dated as of December 24, 2010, by Black Elk Offshore Operations, LLC as Pledgor in favor of Capital One, N.A. as Collateral Agent (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).

111

Exhibit Number	Description
10.35	Guaranty Agreement, dated as of December 24, 2010, by each of the Subsidiaries of the Borrower in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders to the certain Credit Agreement dated as of even date therewith by and among the Borrower, the Agent and the Lenders (incorporated by reference to Exhibit 4.7 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.36	Security and Pledge Agreement, dated as of December 24, 2010, between Black Elk Energy Offshore Operations, LLC and Capital One N.A., not in its individual capacity, but solely as Administrative Agent (incorporated by reference to Exhibit 4.9 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.37	Guaranty Agreement, dated as of December 24, 2010, by each of the Subsidiaries of the Borrower, in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders pursuant to that certain Letter of Credit Facility Agreement dated as of even date herewith, by and among the Borrower, the Agent and the Lenders (incorporated by reference to Exhibit 4.10 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.38	Intercreditor Agreement, entered into as of December 24, 2010, by and among BP Corporation North America Inc., Black Elk Offshore Operations, LLC, and Capital One, National Association, as Administrative Agent for itself and the Lenders party to the Credit Agreement referred to therein (incorporated by reference to Exhibit 4.11 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.39	Amended and Restated Intercreditor Agreement (Escrow Agreements), dated as of December 24, 2010, by and among W&T Offshore, Inc., Capital One, N.A., in its capacity as agent for the Second Lien Creditors, and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.13 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.40	Amended and Restated Intercreditor Agreement (Non-Operated Properties), dated as of December 24, 2010, by and among Capital One, N.A., in its capacity as Facility/Swap Agent for the Facility/ Swap Creditors, The Bank of New York Mellon Trust Company, N.A., in its capacity as Indenture Trustee and in its capacity as Collateral Agent for, on behalf of and in the stead of, the Notes Creditors, W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. and each of the other Loan Parties from time to time party thereto (incorporated by reference to Exhibit 4.14 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.41	Mortgage, Deed of Trust, Collateral Assignment, Security Agreement and Financing Statement, dated October 29, 2009, by and between Black Elk Energy Offshore Operations, LLC and W&T Offshore, Inc. and W. Reid Lea, as Trustee for the benefit of W&T Offshore, Inc (incorporated by reference to Exhibit 4.15 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.42	First Amendment to Mortgage, Deed of Trust, Collateral Assignment, Security Agreement and Financing Statement, dated November 23, 2010, by and between Black Elk Energy Offshore Operations, LLC and W&T Offshore, Inc. and W. Reid Lea, as Trustee for the benefit of W&T Offshore, Inc. (incorporated by reference to Exhibit 4.16 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.43	Partial Release by Obligee of Record, effective November 23, 2010, of that certain Mortgage, Deed of Trust, Collateral Assignment and Security Agreement, dated as of October 29, 2009, by Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.17 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.44	Operated Escrow Agreement, dated as of October 29, 2009, but effective as of August 1, 2009, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.18 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.45	First Amendment to Operated Escrow Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.19 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).

112

Exhibit Number	Description
10.46	Operated Deposit Account Security Agreement, dated October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.20 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.47	Operated Deposit Account Control Agreement, executed and delivered October 29, 2009, among W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association (incorporated by reference to Exhibit 4.21 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.48	Non-Operated Escrow Agreement, dated as of October 29, 2009, but effective as of August 1, 2009, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.22 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.49	First Amendment to Non-Operated Escrow Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.23 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011(SEC File No. 333-174226)).
10.50	Non-Operated Deposit Account Security Agreement, dated October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.24 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.51	Non-Operated Deposit Account Control Agreement, executed and delivered as of October 29, 2009, among W&T Offshore, Inc., Black Elk Energy Offshore Operations, and Amegy Bank National Association (incorporated by reference to Exhibit 4.25 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.52	Waiver, dated as of September 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, 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 10-Q for the period ended September 30, 2011 as filed with the Securities and Exchange Commission on November 10, 2011 (SEC File No. 333-174226)).
*10.53	Contribution Agreement, dated as of January 25, 2013, by and between Black Elk Energy Offshore Operations, LLC and PPVA Black Elk Energy (Equity) LLC.
*10.54	Letter Agreement, dated February 12, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Value Arbitrage Fund LP.
*10.55	Contribution Agreement, dated as of February 12, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC.
*10.56	Contribution Agreement, dated as of February 13, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC.
*10.57	Contribution Agreement, dated as of February 14, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC.
*10.58	Contribution Agreement, dated as of February 22, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC.
10.59	Purchase and Sale Agreement by and between Black Elk Energy Offshore Operations, LLC as Seller and Renaissance Offshore, LLC as Purchaser, dated as of March 1, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
10.60	First Amendment to Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and Renaissance Offshore, LLC, effective as of March 22, 2013 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
10.61	Offer and Separation Agreement and General Release Offer, dated as of April 1, 2013, by and between Black Elk Energy Offshore Operations, LLC and Douglas W. Fehr (incorporated by reference to Exhibit 10.26 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).

113

Exhibit Number	Description
10.62	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).
10.63	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).
10.64	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 Adminstrative 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).
10.65	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, with 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).
10.66	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).
10.67	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).
10.68	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 03, 2013).
10.69	Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC, as Seller, and Renaissance Offshore, LLC, as Purchaser, South Pass Field 65 dated as of November 15, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on November 20, 2013).
*10.70	Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and SandRidge Offshore, LLC, effective as of March 1, 2014.
*12.1	Computation of Ratio of Earnings to Fixed Charges.
*21.1	Subsidiary List of Black Elk Energy Offshore Operations, LLC.
*23.1	Consent of Netherland, Sewell & Associates, Inc.
*31.1	Certification of Principal Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of Principal Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Section 1350 Certifications of Principal Executive Officer and Principal Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*99.1	Summary Report of Netherland, Sewell & Associates, Inc.
101.INS§	XBRL Instance Document
101.SCH§	XBRL Taxonomy Extension Schema Document
101.CAL§	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF§	XBRL Taxonomy Extension Definition Presentation Linkbase Document

114

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

__________________________________

*    Filed herewith.

†    Management contract or compensatory plan or arrangement.

§    Furnished with this Form 10-K. 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.

115

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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
By:	/s/ Jeff Shulse
	Jeff Shulse
	Chief Financial Officer

March 31, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ John Hoffman	President, Chief Executive Officer and Manager (Principal Executive Officer)	March 31, 2014
John Hoffman
/s/ Jeff Shulse	Chief Financial Officer (Principal Financial Officer)	March 31, 2014
Jeff Shulse
/s/ Daniel Small	Manager	March 31, 2014
Daniel Small

116

EXHIBIT INDEX

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	Certificate of Formation of Black Elk Energy Finance Corporation, dated as of October 26, 2010 (incorporated by reference to Exhibit 3.3 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	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).
3.5	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)).
3.6	Bylaws of Black Elk Energy Finance Corp., dated as of October 26, 2010 (incorporated by reference to Exhibit 3.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
3.7	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).
3.8	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).
3.9	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).
3.10	Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of April 9, 2013 (incorporated by reference to Exhibit 3.10 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
3.11	Sixth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of May 3, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on May 9, 2013).
3.12	Third Amendment to the Third Amended and Restated Limited Liability Company Operating Agreement of Blaclk Elk Energy Offshore Operations, LLC, effective as of January 25, 2013.
4.1	Indenture, dated as of November 23, 2010, among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp., as Issuers, the Guarantor party named therein, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
4.2	First Supplemental Indenture, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. as issuers, Black Elk Energy Land Operations, LLC as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).

4.3	Registration Rights Agreement, dated as of November 23, 2010, among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp., the Guarantor party named therein and the Purchasers named therein (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
4.4	Security Agreement, dated as of November 23, 2010, by Black Elk Energy Offshore Operations, LLC, Black Elk Energy Finance Corp., Black Elk Energy Land Operations, LLC in favor of The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent (incorporated by reference to Exhibit 4.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
4.5	Amended and Restated Second Lien Intercreditor Agreement, dated as of December 24, 2010, by and among Capital One, N.A., in its capacity as First Lien Agent for the First Lien Creditors, The Bank of New York Mellow Trust Company, N.A., in its capacity as Indenture Trustee and in its capacity as Collateral Agent for, on behalf of and in the stead of, the Second Lien Creditors, Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. and each other Loan Parties from time to time party thereto (incorporated by reference to Exhibit 4.12 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333174226)).
10.1	Purchase and Sale Agreement, dated September 14, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.2	First Amendment to Purchase and Sale Agreement, dated as of October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.3	Second Amendment to Purchase and Sale Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc. and Black Elk Offshore Operations, LLC (incorporated by reference to Exhibit 10.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.4	Third Amendment to Purchase and Sale Agreement, dated December 19, 2012, by and between W&T Offshore, Inc. and the Company (incorporated by reference to Exhibit 10.6 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
†10.5	Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and John G. Hoffman (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2013).
†10.6	Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and Arthur Garza III (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2013).
†10.7	Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and James F. Hagemeier (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 3, 2012).
†10.8	Engagement Letter, dated January 25, 2013, by and between Black Elk Energy Offshore Operations, LLC and Alvarez & Marsal North America, LLC (incorporated by reference to Exhibit 10.13 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
†10.9	Amended and Restated Company Agreement of Black Elk Employee Incentive, LLC, dated as of August 20, 2010 (incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 26, 2012).
†10.10	Employment Agreement, dated as of April 16, 2013, by and between Black Elk Energy Offshore Operations, LLC and Bruce Koch (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on April 23, 2013).
†10.11	Employment Agreement, dated January 8, 2014, by and between Black Elk Energy Offshore Operations, LLC and Jeffrey Shulse (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on January 14, 2014).

10.12	Credit Agreement, dated as of December 24, 2010, among Black Elk Energy Offshore Operations, LLC, each of the Lenders from time to time party thereto, and Capital One, N.A. as administrative agent for the Lenders (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.13	First Amendment to Credit Agreement, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).
10.14	Waiver and Second Amendment to Credit Agreement, dated as of June 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.6 to the Form 10-Q for the period ended June 30, 2011 as filed with the Securities and Exchange Commission on August 10, 2011 (SEC File No. 333-174226)).
10.15	Limited Waiver and Third Amendment to Credit Agreement, dated as of November 8, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.1 to the Form 10-Q filed with the Securities and Exchange Commission on November 13, 2012
10.16	Fourth Amendment to Credit Agreement and Other Loan Documents, effective as of December 21, 2012, 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 10.1 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
10.17	Sixth Amendment to Credit Agreement, effective as of January 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 March 11, 2013).
10.18	Limited Waiver and Seventh Amendment to Credit Agreement, effective as of February 22, 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 10.3 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
10.19	Eighth Amendment to Credit Agreement, effective as of March 26, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
10.20	Limited Waiver and Ninth Amendment to Credit Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporate by reference to Exhibit 4.39 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
10.21	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).
10.22	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).
10.23	Letter of Credit Facility Agreement, dated as of December 24, 2010, among Black Elk Energy Offshore Operations, LLC, as Borrower, Capital One, N.A., as Administrative Agent and the Lenders Party Thereto (incorporated by reference to Exhibit 4.8 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.24	First Amendment to Letter of Credit Facility Agreement, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011

10.25	Second Amendment to Letter of Credit Facility Agreement, dated as of December 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.1 to the Form 10-Q filed with the Securities and Exchange Commission on August 10, 2012).
10.26	Third Amendment to Letter of Credit Facility Agreement, dated as of May 24, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.2 to the Form 10-Q filed with the Securities and Exchange Commission on August 10, 2012).
10.27	Fourth Amendment to Letter of Credit Facility Agreement and Waiver, dated as of November 8, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.2 to the Form 10-Q filed with the Securities and Exchange Commission on November 13, 2012).
10.28	Fifth Amendment to Letter of Credit Facility Agreement and Amendment to Other Loan Documents, effective as of December 21, 2012, 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 10.4 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
10.29	Sixth Amendment to Letter of Credit Facility Agreement and Amendment to Other Loan Documents, effective as of February 22, 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 10.5 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013).
10.30	Limited Waiver and Seventh Amendment to Letter of Credit Facility Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders, and the Lenders signatory thereto (incorporated by reference to Exhibit 4.40 to the form 10-K with the Securities and Exchange Commission on April 15, 2013).
10.31	Limited Waiver, 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).
10.32	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 (incorporated by reference to Exhibit 10.11 to the Form 10-Q filed with the Securities and Exchange Commission on November 14, 2013).
10.33	Security Agreement, dated as of December 24, 2010, made by Black Elk Energy Offshore Operations, LLC, Black Elk Energy Finance Corp., Black Elk Energy Land Operations, LLC, and The Other Grantors Party Thereto, in favor of Capital One, N.A, not in its individual capacity, but solely as Administrative Agent (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226).
10.34	Pledge and Security Agreement, dated as of December 24, 2010, by Black Elk Offshore Operations, LLC as Pledgor in favor of Capital One, N.A. as Collateral Agent (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.35	Guaranty Agreement, dated as of December 24, 2010, by each of the Subsidiaries of the Borrower in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders to the certain Credit Agreement dated as of even date therewith by and among the Borrower, the Agent and the Lenders (incorporated by reference to Exhibit 4.7 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.36	Security and Pledge Agreement, dated as of December 24, 2010, between Black Elk Energy Offshore Operations, LLC and Capital One N.A., not in its individual capacity, but solely as Administrative Agent (incorporated by reference to Exhibit 4.9 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.37	Guaranty Agreement, dated as of December 24, 2010, by each of the Subsidiaries of the Borrower, in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders pursuant to that certain Letter of Credit Facility Agreement dated as of even date herewith, by and among the Borrower, the Agent and the Lenders (incorporated by reference to Exhibit 4.10 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).

10.38	Intercreditor Agreement, entered into as of December 24, 2010, by and among BP Corporation North America Inc., Black Elk Offshore Operations, LLC, and Capital One, National Association, as Administrative Agent for itself and the Lenders party to the Credit Agreement referred to therein (incorporated by reference to Exhibit 4.11 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.39	Amended and Restated Intercreditor Agreement (Escrow Agreements), dated as of December 24, 2010, by and among W&T Offshore, Inc., Capital One, N.A., in its capacity as agent for the Second Lien Creditors, and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.13 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.40	Amended and Restated Intercreditor Agreement (Non-Operated Properties), dated as of December 24, 2010, by and among Capital One, N.A., in its capacity as Facility/Swap Agent for the Facility/ Swap Creditors, The Bank of New York Mellon Trust Company, N.A., in its capacity as Indenture Trustee and in its capacity as Collateral Agent for, on behalf of and in the stead of, the Notes Creditors, W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. and each of the other Loan Parties from time to time party thereto (incorporated by reference to Exhibit 4.14 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.41	Mortgage, Deed of Trust, Collateral Assignment, Security Agreement and Financing Statement, dated October 29, 2009, by and between Black Elk Energy Offshore Operations, LLC and W&T Offshore, Inc. and W. Reid Lea, as Trustee for the benefit of W&T Offshore, Inc (incorporated by reference to Exhibit 4.15 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.42	First Amendment to Mortgage, Deed of Trust, Collateral Assignment, Security Agreement and Financing Statement, dated November 23, 2010, by and between Black Elk Energy Offshore Operations, LLC and W&T Offshore, Inc. and W. Reid Lea, as Trustee for the benefit of W&T Offshore, Inc. (incorporated by reference to Exhibit 4.16 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.43	Partial Release by Obligee of Record, effective November 23, 2010, of that certain Mortgage, Deed of Trust, Collateral Assignment and Security Agreement, dated as of October 29, 2009, by Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.17 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.44	Operated Escrow Agreement, dated as of October 29, 2009, but effective as of August 1, 2009, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.18 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.45	First Amendment to Operated Escrow Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.19 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.46	Operated Deposit Account Security Agreement, dated October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.20 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.47	Operated Deposit Account Control Agreement, executed and delivered October 29, 2009, among W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association (incorporated by reference to Exhibit 4.21 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.48	Non-Operated Escrow Agreement, dated as of October 29, 2009, but effective as of August 1, 2009, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.22 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.49	First Amendment to Non-Operated Escrow Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.23 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011(SEC File No. 333-174226)).

10.50	Non-Operated Deposit Account Security Agreement, dated October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.24 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.51	Non-Operated Deposit Account Control Agreement, executed and delivered as of October 29, 2009, among W&T Offshore, Inc., Black Elk Energy Offshore Operations, and Amegy Bank National Association (incorporated by reference to Exhibit 4.25 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.52	Waiver, dated as of September 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, 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 10-Q for the period ended September 30, 2011 as filed with the Securities and Exchange Commission on November 10, 2011 (SEC File No. 333-174226)).
*10.53	Contribution Agreement, dated as of January 25, 2013, by and between Black Elk Energy Offshore Operations, LLC and PPVA Black Elk Energy (Equity) LLC.
*10.54	Letter Agreement, dated February 12, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Value Arbitrage Fund LP.
*10.55	Contribution Agreement, dated as of February 12, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC.
*10.56	Contribution Agreement, dated as of February 13, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC.
*10.57	Contribution Agreement, dated as of February 14, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC.
*10.58	Contribution Agreement, dated as of February 22, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC.
10.59	Purchase and Sale Agreement by and between Black Elk Energy Offshore Operations, LLC as Seller and Renaissance Offshore, LLC as Purchaser, dated as of March 1, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
10.60	First Amendment to Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and Renaissance Offshore, LLC, effective as of March 22, 2013 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013).
10.61	Offer and Separation Agreement and General Release Offer, dated as of April 1, 2013, by and between Black Elk Energy Offshore Operations, LLC and Douglas W. Fehr (incorporated by reference to Exhibit 10.26 to the Form 10-K filed with the Securities and Exchange Commission on April 15, 2013).
10.62	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).
10.63	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).
10.64	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 Adminstrative 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).
10.65	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, with 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).

10.66	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).
10.67	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).
10.68	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 03, 2013).
10.69	Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC, as Seller, and Renaissance Offshore, LLC, as Purchaser, South Pass Field 65 dated as of November 15, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on November 20, 2013).
*10.70	Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and SandRidge Offshore, LLC, effective as of March 1, 2014.
*12.1	Computation of Ratio of Earnings to Fixed Charges.
*21.1	Subsidiary List of Black Elk Energy Offshore Operations, LLC.
*23.1	Consent of Netherland, Sewell & Associates, Inc.
*31.1	Certification of Principal Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of Principal Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Section 1350 Certifications of Principal Executive Officer and Principal Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*99.1	Summary Report of Netherland, Sewell & Associates, Inc.
101.INS§	XBRL Instance Document
101.SCH§	XBRL Taxonomy Extension Schema Document
101.CAL§	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF§	XBRL Taxonomy Extension Definition Presentation Linkbase Document
101.LAB§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE§	XBRL Taxonomy Extension Presentation Linkbase Document

__________________________________

*    Filed herewith.

†    Management contract or compensatory plan or arrangement.

§    Furnished with this Form 10-K. 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.

EX-12.1

Exhibit 12.1

Computation of Ratio of Earnings to Fixed Charges

(Dollars in Thousand, Except Ratios)

The following table sets forth our ratio of earnings to fixed charges for the periods indicated on a consolidated historical basis. For purposes of computing the ratio of earnings (loss) to fixed charges, earnings (loss) is defined as pre-tax income (loss) plus fixed charges. Fixed charges consist of interest expense and amortization of deferred financing fees.

RATIO OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
	2013			2012			2011		2010			2009
	(in thousands)
	(Unaudited)
Earnings (Loss):
Pre-Tax Income (Loss)	$	(32,917	)	$	(63,968	)	$	15,041	$	(23,898	)	$	663
Fixed Charges	26,769			25,965			25,752		12,872			3,662
Total Earnings (Loss)	(6,148		)	(38,003		)	40,793		(11,026		)	4,325
Fixed Charges:
Interest Expense	20,898			21,385			21,334		12,671			2,917
Deferred Financing Fees	5,870			4,580			4,418		201			745
Total Fixed Charges	26,769			25,965			25,752		12,872			3,662
Ratio of Earnings (Loss) to Fixed Charges	__(1)			__(1)			1.58		__(1)			1.18

(1) For the year ended December 31, 2013, 2012 and 2010 earnings were inadequate to cover fixed charges. The coverage deficiency necessary for the ratio of earnings to fixed charges to equal 1.00x (one-to-one coverage) was $32.9 million, $64.0 and $23.9 million for the year ended December 31, 2013, 2012 and 2010.

EX-21.1

Exhibit 21.1

Black Elk Energy

List of Subsidiaries

Direct Ownership and Percentage

Name of Subsidiary	Ownership	Jurisdiction of Organization
Black Elk Energy Land of Operations, LLC	100% owned by Parent	Texas
Black Elk Energy Finance Corp.	100% owned by Parent	Texas
Freedom Well Services	100% owned by Parent	Texas

EX-23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, Netherland, Sewell & Associates, Inc. hereby consents to the inclusion or incorporation by reference of information contained in our report as of December 31, 2013, and all references to our firm included in or made part of the Annual Report on Form 10-K for the year ended December 31, 2013, of Black Elk Energy Offshore Operations, LLC.

NETHERLAND, SEWELL & ASSOCIATES, INC.

\s\ Danny D. Simmons

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

By:        

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

March 31, 2014

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

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

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, John Hoffman, certify that:

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

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

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

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules13a-15(f) and 15d-15(f)) for the registrant and have:

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

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

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

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

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

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

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

Date: March 31, 2014	By:	/s/ John Hoffman
	Name:	John Hoffman
	Title:	President and Chief Executive Officer (Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

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

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Jeff Shulse, certify that:

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

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

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

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules13a-15(f) and 15d-15(f)) for the registrant and have:

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

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

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

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

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

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

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

Date: March 31, 2014	By:	/s/ Jeff Shulse
	Name:	Jeff Shulse
	Title:	Chief Financial Officer (Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION

In connection with the Annual Report on Form 10-K for the year ended December 31, 2012 of Black Elk Energy Offshore Operations, LLC (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), John Hoffman, Chief Executive Officer of the Company, and Jeff Shulse, Chief Financial Officer of the Company, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

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

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

Date: March 31, 2014	By:	/s/ John Hoffman
	Name:	John Hoffman
	Title:	President and Chief Executive Officer (Principal Executive Officer)
Date: March 31, 2014	By:	/s/ Jeff Shulse
	Name:	Jeff Shulse
	Title:	Chief Financial Officer (Principal Financial Officer)

EX-99.1

March 31, 2014

Mr. Art Garza

Black Elk Energy Offshore Operations, LLC

11451 Katy Freeway, Suite 500

Houston, Texas 77079

Dear Mr. Garza:

In accordance with your request, we have estimated the proved, probable, and possible reserves and future revenue, as of December 31, 2013, to the Black Elk Energy Offshore Operations, LLC (Black Elk) interest in certain oil and gas properties located in Louisiana, Oklahoma, Texas, and the Gulf of Mexico. We completed our evaluation on February 25, 2014. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Black Elk. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Black Elk's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Black Elk interest in these properties, as of December 31, 2013, to be:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	4,780.8	263.9	14,237.1	356,024.1	300,285.1
Proved Developed Non-Producing	4,152.6	775.6	39,669.9	336,562.7	203,384.8
Proved Undeveloped	2,740.6	333.9	23,883.4	158,153.0	65,696.7
Proved Abandonment Costs	0.0	0.0	0.0	(25,348.30)	66,583.8(1)
Total Proved	11,674.0	1,373.4	77,790.3	825,391.5	635,950.4
Probable Developed	3,619.5	223.1	16,229.5	334,764.4	194,515.3
Probable Undeveloped	4,014.2	507.4	37,496.9	345,102.7	214,747.8
Total Probable	7,633.7	730.5	53,726.4	679,867.0	409,263.1
Possible Developed	2,010.0	104.8	8,087.6	171,953.7	94,793.6
Possible Undeveloped	2,765.5	305.6	26,892.6	292,511.2	178,104.9
Total Possible	4,775.5	410.4	34,980.2	464,464.8	272,898.4

Totals may not add because of rounding.

⁽¹⁾  Black Elk's estimate of the cash value of its escrow accounts for abandonment liability is included as a credit in 2014.

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved, probable, and possible reserves. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Black Elk's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Black Elk's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2013. For oil and NGL volumes, the average West Texas Intermediate posted price of $93.42 per barrel is adjusted by field for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $3.670 per MMBTU is adjusted by field for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. For the proved reserves, the average adjusted product prices weighted by production over the remaining lives of the properties are $107.00 per barrel of oil, $40.69 per barrel of NGL, and $3.933 per MCF of gas.

Operating costs used in this report are based on operating expense records of Black Elk. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Black Elk are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Black Elk and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Black Elk's estimates of the costs to abandon the wells, platforms, and production facilities; these estimates do not include any salvage value for the lease and well equipment. It is our understanding that Black Elk has established escrow accounts for abandonment liability. As requested, Black Elk's estimate of the cash value of these accounts has been included in 2014 as a capital credit. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Black Elk interest. Therefore, our estimates of reserves and future revenue do not include adjustments for

the settlement of any such imbalances; our projections are based on Black Elk receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones and undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Black Elk, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

/s/ C.H. (Scott) Rees III

By:        

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

/s/ Lily W. Cheung        /s/ Patrick L. Higgs

By:            By:        

Lily W. Cheung, P.E. 107207        Patrick L. Higgs, P.G. 985

Vice President        Vice President

Date Signed: March 31, 2014    Date Signed: March 31, 2014

LWC:RGH

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Definitions - Page 1 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

Supplemental definitions from the 2007 Petroleum Resources Management System:
Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

Definitions - Page 2 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources

Definitions - Page 3 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used,

Definitions - Page 4 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

Definitions - Page 5 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Definitions - Page 6 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

    a.    Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
    b.    Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
    c.    Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
    d.    Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
    e.    Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
    f.    Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Definitions - Page 7 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:    Ÿ The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);    Ÿ    The company's historical record at completing development of comparable long-term projects;    Ÿ    The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;    Ÿ    The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and    Ÿ    The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 8 of 7

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Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Swap transactions

New Swap Transactions. On March 20, 2014, we entered into the following swap transactions:

Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month	NYMEX Strike Price
February 2014 - February 2014	Swap	271,672	4.47
March 2014 - March 2014	Swap	342,217	4.47
April 2014 - April 2014	Swap	287,089	4.47
May 2014 - May 2014	Swap	282,346	4.47
June 2014 - June 2014	Swap	231,998	4.47
July 2014 - July 2014	Swap	245,330	4.47
August 2014 - August 2014	Swap	223,294	4.47
September 2014 - September 2014	Swap	207,094	4.47
October 2014 - October 2014	Swap	202,612	4.47
November 2014 - November 2014	Swap	186,296	4.47
December 2014 - December 2014	Swap	219,770	4.47
January 2015 - January 2015	Swap	203,909	4.47
February 2015 - February 2015	Swap	178,341	4.47
March 2015 - March 2015	Swap	177,093	4.47

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Debt and Notes Payable (Details Textual) (USD $)	12 Months Ended						1 Months Ended		1 Months Ended	12 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Senior Secured Revolving Credit Facility	Dec. 31, 2013 Secured Letter of Credit Facility [Member] Letter of Credit [Member]	Dec. 24, 2010 Secured Letter of Credit Facility [Member] Letter of Credit [Member]	Jan. 31, 2013 Senior Secured Revolving Credit Facility Letter of Credit [Member]	Dec. 31, 2013 Senior Secured Revolving Credit Facility Letter of Credit [Member]	May 31, 2011 13.75% Senior Secured Notes, net of discount	Dec. 31, 2013 13.75% Senior Secured Notes, net of discount	Dec. 31, 2012 13.75% Senior Secured Notes, net of discount	Nov. 23, 2010 13.75% Senior Secured Notes, net of discount	Dec. 31, 2013 13.75% Senior Secured Notes, net of discount Maximum [Member]	Dec. 31, 2013 13.75% Senior Secured Notes, net of discount Minimum [Member]	Dec. 31, 2013 AFCO Credit Corporation-Insurance Note Payable [Member] AFCO Credit Corporation-insurance note payable	Dec. 31, 2012 AFCO Credit Corporation-Insurance Note Payable [Member] AFCO Credit Corporation-insurance note payable
Debt and Notes Payable (Textual) [Abstract]
Current borrowing capacity, secured letter of credit					$ 47,000,000	$ 35,000,000
Current amount available on Revolving Credit Facility								0
Proceeds from Lines of Credit	54,000,000	171,500,000	158,457,000
Leverage ratio				5.0									1.4	1.0
Interest coverage ratio				1.4
Interest rate on notes/Fee percentage on letter of credit												13.75%				1.95%
Total long-term debt	183,929,000	201,118,000
Total debt	184,186,000	204,670,000								149,383,000	149,118,000				0	3,552,000
Unamortized discount included in recorded notes value	617,000	882,000								600,000	900,000
Underwriting and debt issue costs capitalized	3,853,000									7,200,000
Maximum percent limit on capital expenditure covenant										30.00%
Debt instrument face value												150,000,000				17,600,000
13.75% Senior secured notes discounted												99.109%
Maturity date of debt instrument										Dec. 01, 2015
Repurchase percentage for 13.75% Senior Secured Notes for a Change of Control										101.00%
Redeemable amount as a percentage of principal amount										110.00%
Percentage of the 13.75% Senior Secured Notes redeemable until December 1, 2013										35.00%
Optional redemption repurchase percentage for the 13.75% Senior Secured Notes from December 1, 2013 until December 1, 2014										106.875%
Consent solicitation fee									4,500,000
Repurchase percentage for 13.75% Senior Secured Notes											103.00%
Outstanding balance					66,600,000			34,500,000
Amended Capital Expenditure Maximum Limit Value											60,000,000
Contribution from our majority equity holder									30,000,000
Credit facility maturity date after amendment							Jan. 01, 2015
Amended covenant interest coverage ratio				3.0
Debt Instrument, Payables Restriction Per Restrictive Covenants, Amount				46,900,000
Maximum Amount Of Payables Restriction Covenant	$ 6,000,000			$ 6,000,000
Amended leverage ratio	2.5			2.5

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Derivative Instruments (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]
Realized gain on derivative financial instruments	$ (5,806)	$ (4,783)	$ 17,556
Unrealized (loss) gain on derivative financial instruments	(5,806)	(4,783)	17,556
Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet
Asset Derivatives	1,370	8,043
Liability Derivatives	(9,859)	(10,726)
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member]
Derivatives, Fair Value [Line Items]
Realized gain on derivative financial instruments	0	23,364	8,099
Unrealized (loss) gain on derivative financial instruments	0	(4,783)	17,556
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Current Assets Derivatives [Member]
Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet
Asset Derivatives	1,370	6,808
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Non-current Assets Derivatives [Member]
Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet
Asset Derivatives	0	1,235
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Current Liability Derivatives [Member]
Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet
Liability Derivatives	(9,828)	(4,400)
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Non-current Liability Derivatives [Member]
Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet
Liability Derivatives	(31)	(6,326)
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Asset Derivatives [Member]
Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet
Asset Derivatives	1,370	8,043
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments under Accounting Guidance [Member] | Liability Derivatives [Member]
Fair Values, on a Gross Basis, of Derivatives Not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet
Liability Derivatives	$ (9,859)	$ (10,726)

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Subsequent Events (Details Textual) (USD $)	0 Months Ended				12 Months Ended			0 Months Ended
	Dec. 20, 2013	Nov. 15, 2013	Jul. 31, 2013	Feb. 12, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 17, 2014 Subsequent Event [Member] Fields
Subsequent Event [Line Items]
Number of Operated Fields Sold								1
Subsequent Events (Textual) [Abstract]
Preferred Stock Outstanding Shares Value					$ 109,744,000	$ 30,000,000
Stock Split ratio				10,000
Sale of oil and gas property or equipment		60,000,000	10,500,000		128,712,000	(38,000)	150,000
Escrows release related to the sold properties					29,800,000
Payables Restriction Covenant-Maximum amount of trade payables excluding certain vendors					6,000,000
Amended leverage ratio					2.5
Number of Non-operated Fields Sold								15
Proceeds from sale of business	$ 10,000,000				$ 131,800,000			$ 50,000,000

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Defined Contribution Plan (Details Textual) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Contribution Plan (Textual) [Abstract]
Maximum percentage of annual compensation that an employee can contribute	90.00%
Safe Harbor contribution percentage per plan year	3.00%
Employees percentage of vested contributions they made to the plan	100.00%
Vesting Period for other employer contributions	3 years
Defined contribution plan employer contribution amount	$ 0.5	$ 0.3	$ 0.5

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes to asset retirement obligations
Beginning of year	$ 345,505	$ 288,686
Revaluation of liability	2,341	53,118
Asset retirement obligations relieved due to sale of properties	(48,454)	0
Liabilities settled	(46,114)	(32,720)
Accretion	23,454	36,421	27,410
End of year	276,732	345,505	288,686
Less: Current portion	(43,109)	(41,572)
LT Asset retirement obligations	$ 233,623	$ 303,933

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

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

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

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

	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	)	$	—

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Gain on Involuntary Conversion (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Gain on Involuntary Conversion (Textual) [Abstract]
Receivable under our insurance policy	$ 0	$ 3,100,000
Proceeds received from insurance recovery	24,090,000	0	0
Gain due to involuntary conversion of asset	17,827,000	3,100,000	0
High Island 443 A-2
Gain on Involuntary Conversion (Textual) [Abstract]
Receivable under our insurance policy	3,100,000
Insurance claim, deductible amount	500,000
Proceeds received from insurance recovery	24,100,000
Gain due to involuntary conversion of asset	$ 17,800,000

XML

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

QUARTERLY FINANCIAL DATA

QUARTERLY FINANCIAL DATA (Unaudited)

The table below sets forth unaudited financial information for each quarter of the last two years (in thousands):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2013
Total revenues	$	59,988		$	66,374		$	63,757		$	67,889
Loss (income) from operations	(8,972		)	(30,683		)	(8,881		)	44,004
Net (loss) income	(16,212		)	(39,518		)	(18,415		)	(41,228		)
Net (loss) income attributable to common unit holders	(19,355		)	(44,201		)	(23,170		)	(36,418		)
Year ended December 31, 2012
Total revenues	$	76,181		$	106,594		$	57,125		$	64,578
Income (loss) from operations	1,245			28,721			(25,153		)	(39,631		)
Net (loss) income	(5,654		)	21,517			(32,575		)	(47,256		)
Net (loss) income attributable to common unit holders	(7,454		)	19,573			(34,807		)	(49,488		)

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Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table
Fair Value of Derivative Assets	$ 1,370	$ 8,043
Fair Value of Derivative Liability	(9,859)	(10,726)
Oil and Natural Gas Derivatives [Member]
Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table
Fair Value of Derivative Assets	1,370	8,043
Fair Value of Derivative Liability	(9,859)	(10,726)
Level 1 [Member]
Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table
Fair Value of Derivative Assets	0	0
Fair Value of Derivative Liability	0	0
Level 1 [Member] | Oil and Natural Gas Derivatives [Member]
Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table
Fair Value of Derivative Assets	0	0
Fair Value of Derivative Liability	0	0
Level 2 [Member]
Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table
Fair Value of Derivative Assets	1,370	8,043
Fair Value of Derivative Liability	(9,859)	(10,726)
Level 2 [Member] | Oil and Natural Gas Derivatives [Member]
Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table
Fair Value of Derivative Assets	1,370	8,043
Fair Value of Derivative Liability	(9,859)	(10,726)
Level 3 [Member]
Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table
Fair Value of Derivative Assets	0	0
Fair Value of Derivative Liability	0	0
Level 3 [Member] | Oil and Natural Gas Derivatives [Member]
Fair Value of Assets and Liabilities by Level within Fair Value Hierarchy Table
Fair Value of Derivative Assets	0	0
Fair Value of Derivative Liability	$ 0	$ 0

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Summary of Significant Accounting Policies (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Future amortization expense
2014	$ 2,390
2015	1,463
2016	0
2017	0
2018	0
Total Future amortization expense	$ 3,853

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Supplemental Oil and Natural Gas Reserve Information (Tables)

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to our oil and natural gas activities for the years ended December 31, 2013, 2012 and 2011:

	Year Ending December 31,
	2013		2012		2011
	(in thousands)
Oil and Gas Activities:
Exploration costs	$	200	$	1,682	$	1,004
Development costs	130,953		42,238		21,169
Acquisition costs	3,250		3,455		27,398
Costs incurred	$	134,403	$	47,375	$	49,571

Estimated quantities of proved domestic oil and natural gas reserves

Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed reserves in barrels (“MBbls”) and cubic feet (“MMcf”) for each of the periods indicated were as follows:

	Crude Oil and  NGLs (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved reserves at December 31, 2011	20,123		150,393		45,189
Purchases of minerals in place	—		—		—
Extensions and discoveries	3,761		11,343		5,652
Revisions of previous estimates	(94	)	(30,759	)	(5,221	)
Production	(2,301	)	(17,884	)	(5,281	)
Proved reserves at December 31, 2012	21,489		113,093		40,339
Extensions and discoveries	1,950		9,431		3,522
Revisions of previous estimates	(1,633	)	(16,017	)	(4,302	)
Production	(1,941	)	(13,294	)	(4,157	)
Purchases of minerals in place	11		—		11
Sales of minerals in place	(6,829	)	(15,423	)	(9,400	)
Proved reserves at December 31, 2013	13,047		77,790		26,012
Proved developed reserves at December 31, 2013	9,973		53,907		18,957

Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves

	December 31,
	2013		2012		2011
	(in thousands)
Future cash inflows	$	1,611,000	$	2,552,252	$	2,641,791
Future cost:
Production	573,233		695,079		714,076
Development	212,376		496,834		544,523
Future income taxes	—		—		—
Future net cash flows	825,391		1,360,339		1,383,192
10% annual discount for estimated timing of cash flows	189,441		302,546		321,784
Standardized measure of discounted future net cash flows	$	635,950	$	1,057,793	$	1,061,408

Changes in standardized measure of discounted future net cash flows from oil and gas proved reserves

Changes in Standardized Measure of Discounted Future Net Cash Flows from Oil and Gas Proved Reserves

	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Beginning of year:	$	1,057,793		$	1,061,408		$	392,189
Purchase of minerals in place	348			—			612,048
Extensions and discoveries and improved recovery, net of future production and development cost	108,261			202,334			314,920
Accretion of discount	87,339			83,566			34,238
Net change in sales prices net of production costs	(314,721		)	(61,407		)	112,923
Changes in estimated future development costs	162,099			6,420			(359,942		)
Previously estimated future development costs incurred	74,073			39,433			17,198
Revisions of quantity estimates	(132,242		)	(186,902		)	60,822
Sales, net of production costs	(86,673		)	(88,837		)	(131,500		)
Timing differences and other	(31,392		)	1,778			8,512
Sales of minerals in place	(288,935		)	—			—
Net increase (decrease)	(421,843		)	(3,615		)	669,219
End of year	$	635,950		$	1,057,793		$	1,061,408

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Debt and Notes Payable (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt and notes payable
Total debt	$ 184,186	$ 204,670
Less: current portion	(257)	(3,552)
Total long-term debt	183,929	201,118
Senior Secured Revolving Credit Facility | Senior Secured Revolving Credit Facility
Debt and notes payable
Total debt	34,500	52,000
13.75% Senior Secured Notes, net of discount | 13.75% Senior Secured Notes, net of discount
Debt and notes payable
Total debt	149,383	149,118
AFCO Credit Corporation-insurance note payable | AFCO Credit Corporation-insurance note payable
Debt and notes payable
Total debt	0	3,552
Other debt | Other debt
Debt and notes payable
Total debt	$ 303	$ 0

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Supplemental Oil and Natural Gas Reserve Information (Details Textual)	12 Months Ended
	Dec. 31, 2013 MMBoe	Dec. 31, 2012 MMBoe
Supplemental Oil and Natural Gas Reserve Information (Textual) [Abstract]
Proved undeveloped reserves booked period	5 years
Discounting rate for estimating cash flows	10.00%
Proved undeveloped reserves	7.1	15.9
Crude Oil and NGL Per Barrel [Member]
Supplemental Oil and Natural Gas Reserve Information (Textual) [Abstract]
Proved undeveloped reserves	3.1	9.2
Natural Gas
Supplemental Oil and Natural Gas Reserve Information (Textual) [Abstract]
Proved undeveloped reserves	23.9	40.1

XML

Commitments and Contingencies (Details Textual) (USD $) In Millions, unless otherwise specified	12 Months Ended						12 Months Ended		12 Months Ended		1 Months Ended		0 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 W&T Total [Member]	Dec. 31, 2013 W&T Operating Properties [Member]	Nov. 30, 2010 W&T Operating Properties [Member]	Dec. 31, 2013 W&T Non-operating Properties [Member]	Dec. 31, 2013 ARGO [Member]	Dec. 31, 2013 Maritech [Member]	Dec. 31, 2013 Merit [Member] Installment	Jan. 31, 2013 Puported Derivative Action [Member] investor	Dec. 31, 2013 Funding obligation for Future Costs on Acquired Properties [Member] W&T Total [Member]	Nov. 06, 2012 Damage from Fire, Explosion or Other Hazard [Member] mi worker
Long-term Purchase Commitment [Line Items]
Distance from Specific Area													17
Loss Contingency, Number of Victims													3
Number of plaintiffs seeking recovery for injuries in connection with West Delta 32 incident											6
Rent expense under operating leases	$ 1.7	$ 1.5	$ 1.0
Escrow to be funded				49.2	18.0		31.2		13.1	60.0
Other Commitment												63.8
Escrow paid/funded						43.1	17.5		12.4
Remaining balance of escrow to be paid							13.7		0.7
Issuance of performance bonds								32.6
Payments for surety bonds										$ 33
Number of monthly installments to be deposited in escrow account										30

XML

Derivative Instruments - Notional Volumes of Derivative Contracts (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (8,489)	$ (2,683)
Derivative gain (loss)	(8,489)	(2,683)
Crude Oil [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(9,028)	(8,071)
Derivative gain (loss)	(9,028)	(8,071)
Natural Gas (MMcf)
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	539	5,388
Derivative gain (loss)	539	5,388
1/14 - 2/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(15)
Derivative gain (loss)	(15)
1/14 - 2/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	19,000
Derivative, Swap Type, Fixed Price	96.90
Derivative Assets (Liabilities), at Fair Value, Net	(60)
Derivative gain (loss)	(60)
1/14 - 2/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	82,000
Derivative, Swap Type, Fixed Price	4.60
Derivative Assets (Liabilities), at Fair Value, Net	45
Derivative gain (loss)	45
1/14 - 5/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	600
Derivative gain (loss)	600
1/14 - 5/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	10,083
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	136
Derivative gain (loss)	136
1/14 - 5/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	129,960
Derivative, Swap Type, Fixed Price	4.94
Derivative Assets (Liabilities), at Fair Value, Net	464
Derivative gain (loss)	464
6/14 - 6/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	101
Derivative gain (loss)	101
6/14 - 6/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
6/14 - 6/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	129,960
Derivative, Swap Type, Fixed Price	4.94
Derivative Assets (Liabilities), at Fair Value, Net	101
Derivative gain (loss)	101
1/14 - 12/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(5,172)
Derivative gain (loss)	(5,172)
1/14 - 12/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	15,000
Derivative, Swap Type, Fixed Price	65.00
Derivative Assets (Liabilities), at Fair Value, Net	(5,172)
Derivative gain (loss)	(5,172)
1/14 - 12/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
1/14 - 1/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(60)
Derivative gain (loss)	(60)
1/14 - 1/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	4,723
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(46)
Derivative gain (loss)	(46)
1/14 - 1/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	43,347
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(14)
Derivative gain (loss)	(14)
2/14 - 2/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(133)
Derivative gain (loss)	(133)
2/14 - 2/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	13,313
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(128)
Derivative gain (loss)	(128)
2/14 - 2/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	32,636
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(5)
Derivative gain (loss)	(5)
3/14 - 3/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(83)
Derivative gain (loss)	(83)
3/14 - 3/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	8,413
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(78)
Derivative gain (loss)	(78)
3/14 - 3/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	46,764
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(5)
Derivative gain (loss)	(5)
4/14 - 4/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(109)
Derivative gain (loss)	(109)
4/14 - 4/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	12,473
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(108)
Derivative gain (loss)	(108)
4/14 - 4/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	41,253
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(1)
Derivative gain (loss)	(1)
5/14 - 5/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(92)
Derivative gain (loss)	(92)
5/14 - 5/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	11,793
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(92)
Derivative gain (loss)	(92)
5/14 - 5/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	40,391
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
6/14 - 6/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(109)
Derivative gain (loss)	(109)
6/14 - 6/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	15,546
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(108)
Derivative gain (loss)	(108)
6/14 - 6/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	20,112
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(1)
Derivative gain (loss)	(1)
7/14 - 7/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(74)
Derivative gain (loss)	(74)
7/14 - 7/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	11,845
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(72)
Derivative gain (loss)	(72)
7/14 - 7/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	39,283
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(2)
Derivative gain (loss)	(2)
8/14 - 8/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(71)
Derivative gain (loss)	(71)
8/14 - 8/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	13,165
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(69)
Derivative gain (loss)	(69)
8/14 - 8/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	34,246
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(2)
Derivative gain (loss)	(2)
9/14 - 9/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(76)
Derivative gain (loss)	(76)
9/14 - 9/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	16,235
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(74)
Derivative gain (loss)	(74)
9/14 - 9/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	29,753
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(2)
Derivative gain (loss)	(2)
10/14 - 10/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(62)
Derivative gain (loss)	(62)
10/14 - 10/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	15,605
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(60)
Derivative gain (loss)	(60)
10/14 - 10/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	28,635
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(2)
Derivative gain (loss)	(2)
11/14 - 11/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(64)
Derivative gain (loss)	(64)
11/14 - 11/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	18,525
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(61)
Derivative gain (loss)	(61)
11/14 - 11/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	27,081
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(3)
Derivative gain (loss)	(3)
12/14 - 12/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(64)
Derivative gain (loss)	(64)
12/14 - 12/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	22,526
Derivative, Swap Type, Fixed Price	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(57)
Derivative gain (loss)	(57)
12/14 - 12/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	34,114
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(7)
Derivative gain (loss)	(7)
1/14 - 1/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(489)
Derivative gain (loss)	(489)
1/14 - 1/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	46,000
Derivative, Swap Type, Fixed Price	87.85
Derivative Assets (Liabilities), at Fair Value, Net	(489)
Derivative gain (loss)	(489)
1/14 - 1/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
2/14 - 2/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(263)
Derivative gain (loss)	(263)
2/14 - 2/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	25,000
Derivative, Swap Type, Fixed Price	87.85
Derivative Assets (Liabilities), at Fair Value, Net	(263)
Derivative gain (loss)	(263)
2/14 - 2/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
3/14 - 3/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(570)
Derivative gain (loss)	(570)
3/14 - 3/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	56,000
Derivative, Swap Type, Fixed Price	87.85
Derivative Assets (Liabilities), at Fair Value, Net	(570)
Derivative gain (loss)	(570)
3/14 - 3/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
4/14 - 4/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(431)
Derivative gain (loss)	(431)
4/14 - 4/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	45,000
Derivative, Swap Type, Fixed Price	87.85
Derivative Assets (Liabilities), at Fair Value, Net	(431)
Derivative gain (loss)	(431)
4/14 - 4/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
5/14 - 5/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(400)
Derivative gain (loss)	(400)
5/14 - 5/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	46,000
Derivative, Swap Type, Fixed Price	87.85
Derivative Assets (Liabilities), at Fair Value, Net	(400)
Derivative gain (loss)	(400)
5/14 - 5/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
6/14 - 6/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(374)
Derivative gain (loss)	(374)
6/14 - 6/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	48,000
Derivative, Swap Type, Fixed Price	87.85
Derivative Assets (Liabilities), at Fair Value, Net	(377)
Derivative gain (loss)	(377)
6/14 - 6/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	40,391
Derivative, Swap Type, Fixed Price	4.19
Derivative Assets (Liabilities), at Fair Value, Net	3
Derivative gain (loss)	3
7/14 - 7/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(249)
Derivative gain (loss)	(249)
7/14 - 7/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	36,000
Derivative, Swap Type, Fixed Price	87.85
Derivative Assets (Liabilities), at Fair Value, Net	(250)
Derivative gain (loss)	(250)
7/14 - 7/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	20,112
Derivative, Swap Type, Fixed Price	4.19
Derivative Assets (Liabilities), at Fair Value, Net	1
Derivative gain (loss)	1
8/14 - 8/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(207)
Derivative gain (loss)	(207)
8/14 - 8/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	34,000
Derivative, Swap Type, Fixed Price	87.85
Derivative Assets (Liabilities), at Fair Value, Net	(208)
Derivative gain (loss)	(208)
8/14 - 8/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	39,283
Derivative, Swap Type, Fixed Price	4.19
Derivative Assets (Liabilities), at Fair Value, Net	1
Derivative gain (loss)	1
9/14 - 9/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(140)	(120)
Derivative gain (loss)	(140)	(120)
9/14 - 9/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	26,000	28,006
Derivative, Swap Type, Fixed Price	87.85	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(141)	(120)
Derivative gain (loss)	(141)	(120)
9/14 - 9/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	34,246	0
Derivative, Swap Type, Fixed Price	4.19	0
Derivative Assets (Liabilities), at Fair Value, Net	1	0
Derivative gain (loss)	1	0
10/14 - 10/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(127)	(130)
Derivative gain (loss)	(127)	(130)
10/14 - 10/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	27,000	31,605
Derivative, Swap Type, Fixed Price	87.85	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(128)	(130)
Derivative gain (loss)	(128)	(130)
10/14 - 10/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	29,753	0
Derivative, Swap Type, Fixed Price	4.19	0
Derivative Assets (Liabilities), at Fair Value, Net	1	0
Derivative gain (loss)	1	0
11/14 - 11/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(83)	(152)
Derivative gain (loss)	(83)	(152)
11/14 - 11/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	20,000	38,743
Derivative, Swap Type, Fixed Price	87.85	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(83)	(152)
Derivative gain (loss)	(83)	(152)
11/14 - 11/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	28,635	0
Derivative, Swap Type, Fixed Price	4.19	0
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Derivative gain (loss)	0	0
12/14 - 12/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(108)	(17)
Derivative gain (loss)	(108)	(17)
12/14 - 12/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	31,000	4,723
Derivative, Swap Type, Fixed Price	87.85	88.80
Derivative Assets (Liabilities), at Fair Value, Net	(105)	(17)
Derivative gain (loss)	(105)	(17)
12/14 - 12/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	27,081	0
Derivative, Swap Type, Fixed Price	4.19	0
Derivative Assets (Liabilities), at Fair Value, Net	(3)	0
Derivative gain (loss)	(3)	0
1/15 - 1/15
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(5)
Derivative gain (loss)	(5)
1/15 - 1/15 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
1/15 - 1/15 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	34,114
Derivative, Swap Type, Fixed Price	4.19
Derivative Assets (Liabilities), at Fair Value, Net	(5)
Derivative gain (loss)	(5)
2/15 - 2/15
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(4)
Derivative gain (loss)	(4)
2/15 - 2/15 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
2/15 - 2/15 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	27,838
Derivative, Swap Type, Fixed Price	4.19
Derivative Assets (Liabilities), at Fair Value, Net	(4)
Derivative gain (loss)	(4)
3/15 - 3/15
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(3)
Derivative gain (loss)	(3)
3/15 - 3/15 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
3/15 - 3/15 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	24,461
Derivative, Swap Type, Fixed Price	4.19
Derivative Assets (Liabilities), at Fair Value, Net	(3)
Derivative gain (loss)	(3)
1/15 - 1/15
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(8)
Derivative gain (loss)	(8)
1/15 - 1/15 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
1/15 - 1/15 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	27,838
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(8)
Derivative gain (loss)	(8)
2/15 - 2/15
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(6)
Derivative gain (loss)	(6)
2/15 - 2/15 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
2/15 - 2/15 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	24,461
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(6)
Derivative gain (loss)	(6)
3/15 - 3/15
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(5)
Derivative gain (loss)	(5)
3/15 - 3/15 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
3/15 - 3/15 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	26,443
Derivative, Swap Type, Fixed Price	4.09
Derivative Assets (Liabilities), at Fair Value, Net	(5)
Derivative gain (loss)	(5)
1/14 - 1/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(57)
Derivative gain (loss)	(57)
1/14 - 1/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	46,006
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	(57)
Derivative gain (loss)	(57)
1/14 - 1/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
2/14 - 2/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(45)
Derivative gain (loss)	(45)
2/14 - 2/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	39,159
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	(45)
Derivative gain (loss)	(45)
2/14 - 2/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
3/14 - 3/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(33)
Derivative gain (loss)	(33)
3/14 - 3/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	36,822
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	(33)
Derivative gain (loss)	(33)
3/14 - 3/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
4/14 - 4/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(16)
Derivative gain (loss)	(16)
4/14 - 4/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	34,069
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	(16)
Derivative gain (loss)	(16)
4/14 - 4/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
5/14 - 5/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	3
Derivative gain (loss)	3
5/14 - 5/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	35,200
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	3
Derivative gain (loss)	3
5/14 - 5/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
6/14 - 6/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	18
Derivative gain (loss)	18
6/14 - 6/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	31,668
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	18
Derivative gain (loss)	18
6/14 - 6/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
7/14 - 7/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	64
Derivative gain (loss)	64
7/14 - 7/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	48,509
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	64
Derivative gain (loss)	64
7/14 - 7/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
8/14 - 8/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	87
Derivative gain (loss)	87
8/14 - 8/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	46,473
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	87
Derivative gain (loss)	87
8/14 - 8/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
9/14 - 9/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	110
Derivative gain (loss)	110
9/14 - 9/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	45,830
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	110
Derivative gain (loss)	110
9/14 - 9/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
10/14 - 10/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	124
Derivative gain (loss)	124
10/14 - 10/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	44,282
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	124
Derivative gain (loss)	124
10/14 - 10/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
11/14 - 11/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	131
Derivative gain (loss)	131
11/14 - 11/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	40,874
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	131
Derivative gain (loss)	131
11/14 - 11/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
12/14 - 12/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	80
Derivative gain (loss)	80
12/14 - 12/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)	26,424
Derivative, Swap Type, Fixed Price	101
Derivative Assets (Liabilities), at Fair Value, Net	80
Derivative gain (loss)	80
12/14 - 12/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)	0
Derivative, Swap Type, Fixed Price	0
Derivative Assets (Liabilities), at Fair Value, Net	0
Derivative gain (loss)	0
1/13 - 10/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		2,097
Derivative gain (loss)		2,097
1/13 - 10/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		27,750
Derivative, Swap Type, Fixed Price		96.90
Derivative Assets (Liabilities), at Fair Value, Net		983
Derivative gain (loss)		983
1/13 - 10/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		104,000
Derivative, Swap Type, Fixed Price		4.60
Derivative Assets (Liabilities), at Fair Value, Net		1,114
Derivative gain (loss)		1,114
11/13 - 11/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		169
Derivative gain (loss)		169
11/13 - 11/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		26,800
Derivative, Swap Type, Fixed Price		96.90
Derivative Assets (Liabilities), at Fair Value, Net		88
Derivative gain (loss)		88
11/13 - 11/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		104,000
Derivative, Swap Type, Fixed Price		4.60
Derivative Assets (Liabilities), at Fair Value, Net		81
Derivative gain (loss)		81
12/13 - 12/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		156
Derivative gain (loss)		156
12/13 - 12/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		27,750
Derivative, Swap Type, Fixed Price		96.90
Derivative Assets (Liabilities), at Fair Value, Net		95
Derivative gain (loss)		95
12/13 - 12/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		104,000
Derivative, Swap Type, Fixed Price		4.60
Derivative Assets (Liabilities), at Fair Value, Net		61
Derivative gain (loss)		61
1/14 - 2/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		216
Derivative gain (loss)		216
1/14 - 2/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		19,000
Derivative, Swap Type, Fixed Price		96.90
Derivative Assets (Liabilities), at Fair Value, Net		136
Derivative gain (loss)		136
1/14 - 2/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		82,000
Derivative, Swap Type, Fixed Price		4.60
Derivative Assets (Liabilities), at Fair Value, Net		80
Derivative gain (loss)		80
1/13 - 6/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		2,521
Derivative gain (loss)		2,521
1/13 - 6/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		15,542
Derivative, Swap Type, Fixed Price		101
Derivative Assets (Liabilities), at Fair Value, Net		715
Derivative gain (loss)		715
1/13 - 6/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		200,669
Derivative, Swap Type, Fixed Price		4.94
Derivative Assets (Liabilities), at Fair Value, Net		1,806
Derivative gain (loss)		1,806
7/13 - 7/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		241
Derivative gain (loss)		241
7/13 - 7/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		7,132
Derivative, Swap Type, Fixed Price		101
Derivative Assets (Liabilities), at Fair Value, Net		47
Derivative gain (loss)		47
7/13 - 7/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		148,788
Derivative, Swap Type, Fixed Price		4.94
Derivative Assets (Liabilities), at Fair Value, Net		194
Derivative gain (loss)		194
8/13 - 8/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		216
Derivative gain (loss)		216
8/13 - 8/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		5,980
Derivative, Swap Type, Fixed Price		101
Derivative Assets (Liabilities), at Fair Value, Net		40
Derivative gain (loss)		40
8/13 - 8/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		139,212
Derivative, Swap Type, Fixed Price		4.94
Derivative Assets (Liabilities), at Fair Value, Net		176
Derivative gain (loss)		176
9/13 - 9/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		171
Derivative gain (loss)		171
9/13 - 9/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		3,897
Derivative, Swap Type, Fixed Price		101
Derivative Assets (Liabilities), at Fair Value, Net		26
Derivative gain (loss)		26
9/13 - 9/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		116,125
Derivative, Swap Type, Fixed Price		4.94
Derivative Assets (Liabilities), at Fair Value, Net		145
Derivative gain (loss)		145
10/13 - 10/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		132
Derivative gain (loss)		132
10/13 - 10/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		3,259
Derivative, Swap Type, Fixed Price		101
Derivative Assets (Liabilities), at Fair Value, Net		22
Derivative gain (loss)		22
10/13 - 10/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		91,166
Derivative, Swap Type, Fixed Price		4.94
Derivative Assets (Liabilities), at Fair Value, Net		110
Derivative gain (loss)		110
11/13 - 11/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		71
Derivative gain (loss)		71
11/13 - 11/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
11/13 - 11/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		64,926
Derivative, Swap Type, Fixed Price		4.94
Derivative Assets (Liabilities), at Fair Value, Net		71
Derivative gain (loss)		71
12/13 - 12/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		177
Derivative gain (loss)		177
12/13 - 12/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		10,042
Derivative, Swap Type, Fixed Price		101
Derivative Assets (Liabilities), at Fair Value, Net		70
Derivative gain (loss)		70
12/13 - 12/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		119,462
Derivative, Swap Type, Fixed Price		4.94
Derivative Assets (Liabilities), at Fair Value, Net		107
Derivative gain (loss)		107
1/14 - 5/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		908
Derivative gain (loss)		908
1/14 - 5/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		10,083
Derivative, Swap Type, Fixed Price		101
Derivative Assets (Liabilities), at Fair Value, Net		361
Derivative gain (loss)		361
1/14 - 5/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		129,960
Derivative, Swap Type, Fixed Price		4.94
Derivative Assets (Liabilities), at Fair Value, Net		547
Derivative gain (loss)		547
6/14 - 6/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		111
Derivative gain (loss)		111
6/14 - 6/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
6/14 - 6/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		129,960
Derivative, Swap Type, Fixed Price		4.94
Derivative Assets (Liabilities), at Fair Value, Net		111
Derivative gain (loss)		111
1/13 - 12/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(864)
Derivative gain (loss)		(864)
1/13 - 12/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		19,750
Derivative, Swap Type, Fixed Price		85.90
Derivative Assets (Liabilities), at Fair Value, Net		(1,649)
Derivative gain (loss)		(1,649)
1/13 - 12/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		47,000
Derivative, Swap Type, Fixed Price		5.00
Derivative Assets (Liabilities), at Fair Value, Net		785
Derivative gain (loss)		785
1/14 - 12/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(4,199)
Derivative gain (loss)		(4,199)
1/14 - 12/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		15,000
Derivative, Swap Type, Fixed Price		65.00
Derivative Assets (Liabilities), at Fair Value, Net		(4,199)
Derivative gain (loss)		(4,199)
1/14 - 12/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
1/13 - 1/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(29)
Derivative gain (loss)		(29)
1/13 - 1/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		9,042
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(29)
Derivative gain (loss)		(29)
1/13 - 1/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
2/13 - 2/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(84)
Derivative gain (loss)		(84)
2/13 - 2/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		23,522
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(84)
Derivative gain (loss)		(84)
2/13 - 2/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
3/13 - 3/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(67)
Derivative gain (loss)		(67)
3/13 - 3/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		16,792
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(67)
Derivative gain (loss)		(67)
3/13 - 3/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
4/13 - 4/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(103)
Derivative gain (loss)		(103)
4/13 - 4/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		23,812
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(103)
Derivative gain (loss)		(103)
4/13 - 4/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
5/13 - 5/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(110)
Derivative gain (loss)		(110)
5/13 - 5/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		24,012
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(110)
Derivative gain (loss)		(110)
5/13 - 5/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
6/13 - 6/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(140)
Derivative gain (loss)		(140)
6/13 - 6/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		29,752
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(140)
Derivative gain (loss)		(140)
6/13 - 6/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
7/13 - 7/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(108)
Derivative gain (loss)		(108)
7/13 - 7/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		23,143
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(108)
Derivative gain (loss)		(108)
7/13 - 7/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
8/13 - 8/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(114)
Derivative gain (loss)		(114)
8/13 - 8/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		24,915
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(114)
Derivative gain (loss)		(114)
8/13 - 8/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
9/13 - 9/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(127)
Derivative gain (loss)		(127)
9/13 - 9/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		28,688
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(127)
Derivative gain (loss)		(127)
9/13 - 9/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
2/14 - 2/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(48)
Derivative gain (loss)		(48)
2/14 - 2/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		13,313
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(48)
Derivative gain (loss)		(48)
2/14 - 2/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
3/14 - 3/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(29)
Derivative gain (loss)		(29)
3/14 - 3/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		8,413
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(29)
Derivative gain (loss)		(29)
3/14 - 3/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
4/14 - 4/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(41)
Derivative gain (loss)		(41)
4/14 - 4/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		12,473
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(41)
Derivative gain (loss)		(41)
4/14 - 4/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
5/14 - 5/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(37)
Derivative gain (loss)		(37)
5/14 - 5/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		11,793
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(37)
Derivative gain (loss)		(37)
5/14 - 5/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
6/14 - 6/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(46)
Derivative gain (loss)		(46)
6/14 - 6/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		15,546
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(46)
Derivative gain (loss)		(46)
6/14 - 6/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
7/14 - 7/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(33)
Derivative gain (loss)		(33)
7/14 - 7/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		11,845
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(33)
Derivative gain (loss)		(33)
7/14 - 7/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
8/14 - 8/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(34)
Derivative gain (loss)		(34)
8/14 - 8/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		13,165
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(34)
Derivative gain (loss)		(34)
8/14 - 8/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
9/14 - 9/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(41)
Derivative gain (loss)		(41)
9/14 - 9/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		16,235
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(41)
Derivative gain (loss)		(41)
9/14 - 9/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
10/14 - 10/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(38)
Derivative gain (loss)		(38)
10/14 - 10/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		15,605
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(38)
Derivative gain (loss)		(38)
10/14 - 10/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
11/14 - 11/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(42)
Derivative gain (loss)		(42)
11/14 - 11/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		18,525
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(42)
Derivative gain (loss)		(42)
11/14 - 11/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
12/14 - 12/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(46)
Derivative gain (loss)		(46)
12/14 - 12/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		22,526
Derivative, Swap Type, Fixed Price		88.80
Derivative Assets (Liabilities), at Fair Value, Net		(46)
Derivative gain (loss)		(46)
12/14 - 12/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
1/13 - 1/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(272)
Derivative gain (loss)		(272)
1/13 - 1/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		66,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(272)
Derivative gain (loss)		(272)
1/13 - 1/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
2/13 - 2/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(154)
Derivative gain (loss)		(154)
2/13 - 2/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		34,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(154)
Derivative gain (loss)		(154)
2/13 - 2/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
3/13 - 3/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(246)
Derivative gain (loss)		(246)
3/13 - 3/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		50,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(246)
Derivative gain (loss)		(246)
3/13 - 3/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
4/13 - 4/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(184)
Derivative gain (loss)		(184)
4/13 - 4/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		35,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(184)
Derivative gain (loss)		(184)
4/13 - 4/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
5/13 - 5/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(198)
Derivative gain (loss)		(198)
5/13 - 5/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		36,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(198)
Derivative gain (loss)		(198)
5/13 - 5/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
6/13 - 6/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(129)
Derivative gain (loss)		(129)
6/13 - 6/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		23,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(129)
Derivative gain (loss)		(129)
6/13 - 6/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
7/13 - 7/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(84)
Derivative gain (loss)		(84)
7/13 - 7/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		15,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(84)
Derivative gain (loss)		(84)
7/13 - 7/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
8/13 - 8/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(60)
Derivative gain (loss)		(60)
8/13 - 8/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		11,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(60)
Derivative gain (loss)		(60)
8/13 - 8/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
9/13 - 9/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(106)
Derivative gain (loss)		(106)
9/13 - 9/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		20,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(106)
Derivative gain (loss)		(106)
9/13 - 9/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
10/13 - 10/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(21)
Derivative gain (loss)		(21)
10/13 - 10/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		4,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(21)
Derivative gain (loss)		(21)
10/13 - 10/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
11/13 - 11/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(1)
Derivative gain (loss)		(1)
11/13 - 11/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		250
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(1)
Derivative gain (loss)		(1)
11/13 - 11/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
12/13 - 12/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(12)
Derivative gain (loss)		(12)
12/13 - 12/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		2,500
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(12)
Derivative gain (loss)		(12)
12/13 - 12/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
1/14 - 1/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(211)
Derivative gain (loss)		(211)
1/14 - 1/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		46,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(211)
Derivative gain (loss)		(211)
1/14 - 1/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
2/14 - 2/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(110)
Derivative gain (loss)		(110)
2/14 - 2/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		25,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(110)
Derivative gain (loss)		(110)
2/14 - 2/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
3/14 - 3/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(239)
Derivative gain (loss)		(239)
3/14 - 3/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		56,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(239)
Derivative gain (loss)		(239)
3/14 - 3/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
4/14 - 4/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(186)
Derivative gain (loss)		(186)
4/14 - 4/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		45,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(186)
Derivative gain (loss)		(186)
4/14 - 4/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
5/14 - 5/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(182)
Derivative gain (loss)		(182)
5/14 - 5/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		46,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(182)
Derivative gain (loss)		(182)
5/14 - 5/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
6/14 - 6/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(181)
Derivative gain (loss)		(181)
6/14 - 6/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		48,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(181)
Derivative gain (loss)		(181)
6/14 - 6/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
7/14 - 7/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(129)
Derivative gain (loss)		(129)
7/14 - 7/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		36,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(129)
Derivative gain (loss)		(129)
7/14 - 7/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
8/14 - 8/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(117)
Derivative gain (loss)		(117)
8/14 - 8/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		34,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(117)
Derivative gain (loss)		(117)
8/14 - 8/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
9/14 - 9/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(86)
Derivative gain (loss)		(86)
9/14 - 9/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		26,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(86)
Derivative gain (loss)		(86)
9/14 - 9/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
10/14 - 10/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(86)
Derivative gain (loss)		(86)
10/14 - 10/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		27,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(86)
Derivative gain (loss)		(86)
10/14 - 10/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
11/14 - 11/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(61)
Derivative gain (loss)		(61)
11/14 - 11/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		20,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(61)
Derivative gain (loss)		(61)
11/14 - 11/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
12/14 - 12/14
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(87)
Derivative gain (loss)		(87)
12/14 - 12/14 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		31,000
Derivative, Swap Type, Fixed Price		87.85
Derivative Assets (Liabilities), at Fair Value, Net		(87)
Derivative gain (loss)		(87)
12/14 - 12/14 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		0
9/13 - 9/13
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		72
Derivative gain (loss)		72
9/13 - 9/13 | Crude Oil [Member]
Derivative [Line Items]
Volume (Bbls & MMBtu)		(17,500)
Derivative, Swap Type, Fixed Price		89.15
Derivative Assets (Liabilities), at Fair Value, Net		72
Derivative gain (loss)		72
9/13 - 9/13 | Natural Gas (MMcf)
Derivative [Line Items]
Volume (Bbls & MMBtu)		0
Derivative, Swap Type, Fixed Price		0
Derivative Assets (Liabilities), at Fair Value, Net		0
Derivative gain (loss)		$ 0

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Reclassifications: Certain reclassifications have been made to conform 2011 and 2012 balances to our 2013 presentation. Such reclassifications had no effect on net income or cash flow.

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

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

We account for business combinations using the purchase method, in accordance with Accounting Standards Codification 810 from the Financial Accounting Standards Board (“FASB”). We use estimates to record the fair value of assets acquired and liabilities assumed.

Oil and natural gas reserves estimates, which are the basis for unit-of-production depletion and the impairment test, are based on assumptions that have inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

Cash and Cash Equivalents: We consider all demand deposits, money market accounts and certificates of deposit purchased with an original maturity of three months or less to be cash and cash equivalents.

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

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

We record revenues based on physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create gas imbalances that we recognize as a receivable (payable) when there are not sufficient reserves to make up the gas imbalance. A gas imbalance receivable (payable) can also be a result of imbalances acquired in conjunction with the acquisition of oil and gas properties. At December 31, 2013 and December 31, 2012, our net gas receivable imbalances were $1.2 million and $0.4 million, respectively.

Allowance for Doubtful Accounts: Trade and other receivables are recorded at their outstanding balances adjusted for an allowance for doubtful accounts. The allowance for doubtful accounts is determined by analyzing the payment history and credit worthiness of each debtor. Receivable balances are charged off when they are considered uncollectible by management. Recoveries of receivables previously charged off are recorded as income when received. At December 31, 2013 and December 31, 2012, allowance for doubtful accounts totaled $0.8 million and $0.5 million, respectively.

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

Depreciation, depletion and amortization (“DD&A”) of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. DD&A expense related to oil and natural gas properties for the years ended December 31, 2013, 2012 and 2011 was $41.4 million, $46.5 million and $46.6 million, respectively. As more fully described below, proved reserves are estimated annually by our independent petroleum engineer, and are subject to future revisions based on availability of additional information. DD&A is calculated each quarter based upon the latest estimated reserves data available. Asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Upon sale or retirement of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to operations.

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural gas properties by field to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices. For the years ended December 31, 2013, 2012 and 2011, we recorded an impairment charge of approximately $79.1 million, $31.0 million and $13.0 million, respectively.

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

Other Property and Equipment: Other property and equipment consists principally of furniture, fixtures and equipment and leasehold improvements. Other property and equipment and related accumulated depreciation and amortization are relieved upon retirement or sale and the gain or loss is included in operations. Maintenance and repairs are charged to operations. Renewals and betterments that extend the useful life of property and equipment are capitalized to the appropriate property and equipment accounts. Depreciation of other property and equipment is computed using the straight-line method based on estimated useful lives of the property and equipment. Depreciation expense of other property and equipment for the years ended December 31, 2013, 2012 and 2011 was $2.2 million, $0.8 million and $0.6 million, respectively.

In accordance with authoritative guidance on accounting for the impairment or disposal of long-lived assets, we assess the recoverability of the carrying value of our non-oil and natural gas long-lived assets when events occur that indicate an impairment in value may exist. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If this occurs, an impairment loss is recognized for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset.

Oil and Natural Gas Reserve Quantities: Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our independent engineering firm prepares a reserve and economic evaluation of all our properties on a well-by-well basis utilizing information provided to it by us and information available from state agencies that collect information reported to it by the operators of our properties. As discussed below, the estimate of our proved reserves as of December 31, 2013 and 2012 have been prepared and presented in accordance with SEC rules and applicable accounting standards. These rules require companies to prepare their reserve estimates using reserve definitions and pricing based on 12-month un-weighted first-day-of-the-month average pricing.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to DD&A and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the report. The accuracy of our reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the quantities of oil, natural gas, and natural gas liquids ultimately recovered.

Debt Issue Costs: Debt issue costs associated with long-term debt under revolving credit facilities and senior notes are carried at cost, net of amortization using the straight-line method over the term of the applicable long-term debt facility or the term of the notes, which approximates the effective interest method. Amortization expense for the years ended December 31, 2013, 2012 and 2011 amounted to $4.6 million, $4.8 million and $2.9 million, respectively.

Future amortization expense is as follows:

Year Ending December 31,	(in thousands)
2014	$	2,390
2015	1,463
2016	—
2017	—
2018	—
	$	3,853

Derivative Financial Instruments: We utilize certain derivative contracts to reduce our exposure to fluctuating oil and natural gas prices. The oil and natural gas reference prices of these derivative contracts are based upon futures which have a high degree of correlation with actual prices received by us. We did not designate any of our derivative contracts as qualifying cash flow hedges. Accordingly, all gains and losses from our price risk management activities are currently included in earnings. Open positions are marked-to-market and recorded as unrealized gain (loss) on derivative financial instruments. When settled, the resulting cash flows are reported as cash flows from operating activities.

Asset Retirement Obligations: Accounting guidance for asset retirement obligations requires companies to recognize a liability for the present value of all obligations associated with retirement of tangible long-lived assets and to capitalize an equal amount as part of the cost of the related oil and natural gas properties. We recognize the legal obligation of the dismantlement, restoration and abandonment costs associated with our oil and natural gas properties with our asset retirement obligations. These costs are impacted by our estimated remaining lives of the properties, as well as current market conditions associated with these activities.

Environmental Expenditures: We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed.

Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component is fixed or reliably determinable.

Income Taxes: We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes.

We are subject to the Texas margin tax which is generally calculated as 1% of gross margin. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. During the years ended December 31, 2013, 2012 and 2011, the margin tax was immaterial to the consolidated financial statements.

Recent Accounting Pronouncements: Management does not believe that any recently issued accounting pronouncements would have a material effect on the accompanying consolidated financial statements.

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Uncertain Tax Positions (Details Textual) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Uncertain Tax Positions (Textual) [Abstract]
Unrecognized tax benefits	$ 0	$ 0
Accrued interest or penalties related to uncertain tax positions	$ 0	$ 0

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Divestitures (Details Textual) (USD $)	0 Months Ended				12 Months Ended
	Dec. 20, 2013 Fields	Nov. 15, 2013	Jul. 31, 2013 Fields	Mar. 26, 2013 Fields	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Divestitures [Line Items]
Number of fields sold	1		1	4
Business divestitures sale price				$ 52,500,000
Sale of oil and gas property or equipment		60,000,000	10,500,000		128,712,000	(38,000)	150,000
Proceeds from sale of business	10,000,000				131,800,000
Line of Credit [Member]
Divestitures [Line Items]
Pay Down Credit Facility From Sale Proceeds				$ 36,000,000

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Oil and Gas Properties (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Capitalized costs related to oil and gas properties

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

	At December 31,
	2013			2012
	(in thousands)
Proved properties	$	490,109		$	451,338
Accumulated depletion, depreciation, amortization and impairment	(293,973		)	(191,326		)
Oil and Natural Gas Properties, net	$	196,136		$	260,012

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Future amortization expense

Future amortization expense is as follows:

Year Ending December 31,	(in thousands)
2014	$	2,390
2015	1,463
2016	—
2017	—
2018	—
	$	3,853

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Members' Deficit (Details Textual) (USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended		3 Months Ended	12 Months Ended			3 Months Ended
	Feb. 12, 2013	Mar. 31, 2013 PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (PPBE) [Member]	Mar. 31, 2013 Preferred Units, Class E [Member] PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (PPBE) [Member]	Dec. 31, 2013 Preferred Units, Class E [Member] PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (PPBE) [Member]	Mar. 31, 2013 Preferred Units, Class B [Member] PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (PPBE) [Member]	Feb. 12, 2013 Preferred Units, Class B [Member] Ppva Black Elk Equity [Member]	Mar. 31, 2013 Preferred Units, Class D [Member] PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (PPBE) [Member]
Class of Stock [Line Items]
Additional units issued		43,000,000	50,000,000		3,800,000	1,131,458
Aggregate offering price of additional units issued		$ 50.0
Outstanding units							30,000,000
Paid-in-kind dividends				16,700,000			13,000,000
Preferred units preference return (percent)			20.00%
Preferred units expected preference return (percent)			36.00%
Unit split ratio	10,000

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Oil and Gas Properties (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Capitalized costs related to oil and gas properties
Proved properties	$ 490,109	$ 451,338
Accumulated depletion, depreciation, amortization and impairment	(293,973)	(191,326)
Oil and Natural Gas Properties, net	$ 196,136	$ 260,012

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Accounts Payable and Accrued Expenses (Tables)

12 Months Ended

Dec. 31, 2013

Payables and Accruals [Abstract]

Schedules of accounts payable and accrued expenses

Below are the components of accounts payable and accrued expenses:

	At December 31,
	2013		2012
	(in thousands)
Accounts payable—trade	$	122,015	$	61,530
Accrued operating expenses	19,014		42,194
Interest payable	2,410		1,913
Other payables	12,441		3,099
	$	155,880	$	108,736

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedules of change to our asset retirement obligations

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

	At December 31,
	2013			2012
	(in thousands)
Beginning of year	$	345,505		$	288,686
Revaluation of liability	2,341			53,118
Liabilities relieved due to sale of properties	(48,454		)	—
Liabilities settled	(46,114		)	(32,720		)
Accretion expense	23,454			36,421
End of year	$	276,732		$	345,505
Less: Current portion	$	(43,109	)	$	(41,572	)
LT Asset retirement obligations	$	233,623		$	303,933

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Risks and Uncertainties

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

RISKS AND UNCERTAINTIES

RISKS, AND UNCERTAINTIES

While cash flows were lower than previously projected primarily due to lower production and sales of assets in the 3rd and 4th quarters, we continued our development operations by supplementing our cash flows from operating activities with funds raised through borrowings in 2013 and capital contributions from our members. We retained financial and technical advisors to provide recommendations on achieving improvements in production, operating expense, cash flows from operations, work over, capital expenditures and business planning.

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $(109.6) million at December 31, 2013 and we incurred net losses of $(32.9) million during the year ended December 31, 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 our surety bonds that secure our P&A obligations led to significant cash reductions in the fourth quarter of 2012 and the year 2013. To increase liquidity, we stretched accounts payable, aggressively pursued accounts receivable and sold non-core assets.

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

Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our plugging and abandonment (“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 our surety bonds for P&A obligations. We are currently in discussions with surety agencies to replace the 100% cash-backed letters of credit.

As of December 31, 2013 we have obtained a waiver of certain supplemental bonding requirements from Capital One. The current ratio covenant has been removed in the Seventh Amendment, Ninth Amendment and Tenth Amendment and has been replaced with a payables restriction covenant. Our liquidity projections demonstrate improvement of our financial position and we believe that we will meet our interest coverage ratio covenant, debt leverage ratio covenant and payables restriction covenant going forward.

Our capital budget may be adjusted in the future as business conditions warrant and the ultimate amount of capital we expend may fluctuate materially based on market conditions.

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

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

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

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

MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

Major Customers

The following purchasers and operators accounted for 10% or more of our oil and natural gas sales:

	Year Ended December 31,
	2013		2012		2011
Shell Trading (US) Company	62	%	18	%	51	%
JP Morgan Ventures Energy Corporation	—	%	41	%	8	%

In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of our customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. We believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.

Concentrations of Credit Risk

We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. We had cash deposits in certain banks that at times exceeded the maximum limits federally insured by the Federal Deposit Insurance Corporation. We monitor the financial condition of the banks and have experienced no losses on those accounts.

Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Based on the current demand for oil and natural gas, we do not expect that termination of sales to any of our current purchasers would have a material adverse effect on our ability to find replacement purchasers and to sell our production at favorable market prices.

Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We actively monitor our credit risks related to financial institutions and counterparties including monitoring credit agency ratings, financial position and current news to mitigate this credit risk.

A substantial portion of our oil and natural gas reserves and production are located in the Gulf of Mexico. Our company may be disproportionally exposed to the impact of delays of interruptions of production from these wells due to mechanical problems, damages to the current producing reservoirs and significant governmental regulations, including any curtailment of production or interruption of transportation of oil or natural gas produced from these wells.

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivative Instruments

At December 31, 2013, the notional volumes of our commodity derivative contracts were as follows:

	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)
1/14 - 2/14	19,000	$	96.90	$	(60	)	$	(60	)	82,000	$	4.60	$	45		$	45		$	(15	)	$	(15	)
1/14 - 5/14	10,083	100.80		136			136			129,960	4.94		$	464		464			600			600
6/14 - 6/14	—	—		—			—			129,960	4.94		101			101			101			101
1/14 - 12/14	15,000	65.00		(5,172		)	(5,172		)	—	—		—			—			(5,172		)	(5,172		)
1/14 - 1/14	4,723	88.80		(46		)	(46		)	43,347	4.09		(14		)	(14		)	(60		)	(60		)
2/14 - 2/14	13,313	88.80		(128		)	(128		)	32,636	4.09		(5		)	(5		)	(133		)	(133		)
3/14 - 3/14	8,413	88.80		(78		)	(78		)	46,764	4.09		(5		)	(5		)	(83		)	(83		)
4/14 - 4/14	12,473	88.80		(108		)	(108		)	41,253	4.09		(1		)	(1		)	(109		)	(109		)
5/14 - 5/14	11,793	88.80		(92		)	(92		)	40,391	4.09		—			—			(92		)	(92		)
6/14 - 6/14	15,546	88.80		(108		)	(108		)	20,112	4.09		(1		)	(1		)	(109		)	(109		)
7/14 - 7/14	11,845	88.80		(72		)	(72		)	39,283	4.09		(2		)	(2		)	(74		)	(74		)
8/14 - 8/14	13,165	88.80		(69		)	(69		)	34,246	4.09		(2		)	(2		)	(71		)	(71		)
9/14 - 9/14	16,235	88.80		(74		)	(74		)	29,753	4.09		(2		)	(2		)	(76		)	(76		)
10/14 - 10/14	15,605	88.80		(60		)	(60		)	28,635	4.09		(2		)	(2		)	(62		)	(62		)
11/14 - 11/14	18,525	88.80		(61		)	(61		)	27,081	4.09		(3		)	(3		)	(64		)	(64		)
12/14 - 12/14	22,526	88.80		(57		)	(57		)	34,114	4.09		(7		)	(7		)	(64		)	(64		)
1/14 - 1/14	46,000	87.85		(489		)	(489		)	—	—		—			—			(489		)	(489		)
2/14 - 2/14	25,000	87.85		(263		)	(263		)	—	—		—			—			(263		)	(263		)
3/14 - 3/14	56,000	87.85		(570		)	(570		)	—	—		—			—			(570		)	(570		)
4/14 - 4/14	45,000	87.85		(431		)	(431		)	—	—		—			—			(431		)	(431		)
5/14 - 5/14	46,000	87.85		(400		)	(400		)	—	—		—			—			(400		)	(400		)
6/14 - 6/14	48,000	87.85		(377		)	(377		)	40,391	4.19		3			3			(374		)	(374		)
7/14 - 7/14	36,000	87.85		(250		)	(250		)	20,112	4.19		1			1			(249		)	(249		)
8/14 - 8/14	34,000	87.85		(208		)	(208		)	39,283	4.19		1			1			(207		)	(207		)
9/14 - 9/14	26,000	87.85		(141		)	(141		)	34,246	4.19		1			1			(140		)	(140		)
10/14 - 10/14	27,000	87.85		(128		)	(128		)	29,753	4.19		1			1			(127		)	(127		)
11/14 - 11/14	20,000	87.85		(83		)	(83		)	28,635	4.19		—			—			(83		)	(83		)
12/14 - 12/14	31,000	87.85		(105		)	(105		)	27,081	4.19		(3		)	(3		)	(108		)	(108		)
1/15 - 1/15	—	—		—			—			34,114	4.19		(5		)	(5		)	(5		)	(5		)
2/15 - 2/15	—	—		—			—			27,838	4.19		(4		)	(4		)	(4		)	(4		)
3/15 - 3/15	—	—		—			—			24,461	4.19		(3		)	(3		)	(3		)	(3		)
1/15 - 1/15	—	—		—			—			27,838	4.09		(8		)	(8		)	(8		)	(8		)
2/15 - 2/15	—	—		—			—			24,461	4.09		(6		)	(6		)	(6		)	(6		)
3/15 - 3/15	—	—		—			—			26,443	4.09		(5		)	(5		)	(5		)	(5		)
1/14 - 1/14	46,006	100.72		(57		)	(57		)	—	—		—			—			(57		)	(57		)
2/14 - 2/14	39,159	100.72		(45		)	(45		)	—	—		—			—			(45		)	(45		)
3/14 - 3/14	36,822	100.72		(33		)	(33		)	—	—		—			—			(33		)	(33		)
4/14 - 4/14	34,069	100.72		(16		)	(16		)	—	—		—			—			(16		)	(16		)
5/14 - 5/14	35,200	100.72		3			3			—	—		—			—			3			3
6/14 - 6/14	31,668	100.72		18			18			—	—		—			—			18			18
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		124			124			—	—		—			—			124			124
11/14 - 11/14	40,874	100.72		131			131			—	—		—			—			131			131
12/14 - 12/14	26,424	100.72		80			80			—	—		—			—			80			80
				(9,028		)	(9,028		)				539			539			(8,489		)	(8,489		)

At December 31, 2012, the notional volumes of our commodity derivative contracts were as follows:

	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)
1/13 - 10/13	27,750	$	96.90	$	983		$	983		104,000	$	4.60	$	1,114	$	1,114	$	2,097		$	2,097
11/13 - 11/13	26,800	96.90		88			88			104,000	4.60		$	81	$	81	169			169
12/13 - 12/13	27,750	96.90		95			95			104,000	4.60		61		61		156			156
1/14 - 2/14	19,000	96.90		136			136			82,000	4.60		80		80		216			216
1/13 - 6/13	15,542	100.80		715			715			200,669	4.94		1,806		1,806		2,521			2,521
7/13 - 7/13	7,132	100.80		47			47			148,788	4.94		194		194		241			241
8/13 - 8/13	5,980	100.80		40			40			139,212	4.94		176		176		216			216
9/13 - 9/13	3,897	100.80		26			26			116,125	4.94		145		145		171			171
10/13 - 10/13	3,259	100.80		22			22			91,166	4.94		110		110		132			132
11/13 - 11/13	—	—		—			—			64,926	4.94		71		71		71			71
12/13 - 12/13	10,042	100.80		70			70			119,462	4.94		107		107		177			177
1/14 - 5/14	10,083	100.80		361			361			129,960	4.94		547		547		908			908
6/14 - 6/14	—	—		—			—			129,960	4.94		111		111		111			111
1/13 - 12/13	19,750	85.90		(1,649		)	(1,649		)	47,000	5.00		785		785		(864		)	(864		)
1/14 - 12/14	15,000	65.00		(4,199		)	(4,199		)	—	—		—		—		(4,199		)	(4,199		)
1/13 - 1/13	9,042	88.80		(29		)	(29		)	—	—		—		—		(29		)	(29		)
2/13 - 2/13	23,522	88.80		(84		)	(84		)	—	—		—		—		(84		)	(84		)
3/13 - 3/13	16,792	88.80		(67		)	(67		)	—	—		—		—		(67		)	(67		)
4/13 - 4/13	23,812	88.80		(103		)	(103		)	—	—		—		—		(103		)	(103		)
5/13 - 5/13	24,012	88.80		(110		)	(110		)	—	—		—		—		(110		)	(110		)
6/13 - 6/13	29,752	88.80		(140		)	(140		)	—	—		—		—		(140		)	(140		)
7/13 - 7/13	23,143	88.80		(108		)	(108		)	—	—		—		—		(108		)	(108		)
8/13 - 8/13	24,915	88.80		(114		)	(114		)	—	—		—		—		(114		)	(114		)
9/13 - 9/13	28,688	88.80		(127		)	(127		)	—	—		—		—		(127		)	(127		)
10/13 - 10/13	28,006	88.80		(120		)	(120		)	—	—		—		—		(120		)	(120		)
11/13 - 11/13	31,605	88.80		(130		)	(130		)	—	—		—		—		(130		)	(130		)
12/13 - 12/13	38,743	88.80		(152		)	(152		)	—	—		—		—		(152		)	(152		)
1/14 - 1/14	4,723	88.80		(17		)	(17		)	—	—		—		—		(17		)	(17		)
2/14 - 2/14	13,313	88.80		(48		)	(48		)	—	—		—		—		(48		)	(48		)
3/14 - 3/14	8,413	88.80		(29		)	(29		)	—	—		—		—		(29		)	(29		)
4/14 - 4/14	12,473	88.80		(41		)	(41		)	—	—		—		—		(41		)	(41		)
5/14 - 5/14	11,793	88.80		(37		)	(37		)	—	—		—		—		(37		)	(37		)
6/14 - 6/14	15,546	88.80		(46		)	(46		)	—	—		—		—		(46		)	(46		)
7/14 - 7/14	11,845	88.80		(33		)	(33		)	—	—		—		—		(33		)	(33		)
8/14 - 8/14	13,165	88.80		(34		)	(34		)	—	—		—		—		(34		)	(34		)
9/14 - 9/14	16,235	88.80		(41		)	(41		)	—	—		—		—		(41		)	(41		)
10/14 - 10/14	15,605	88.80		(38		)	(38		)	—	—		—		—		(38		)	(38		)
11/14 - 11/14	18,525	88.80		(42		)	(42		)	—	—		—		—		(42		)	(42		)
12/14 - 12/14	22,526	88.80		(46		)	(46		)	—	—		—		—		(46		)	(46		)
1/13 - 1/13	66,000	87.85		(272		)	(272		)	—	—		—		—		(272		)	(272		)
2/13 - 2/13	34,000	87.85		(154		)	(154		)	—	—		—		—		(154		)	(154		)
3/13 - 3/13	50,000	87.85		(246		)	(246		)	—	—		—		—		(246		)	(246		)
4/13 - 4/13	35,000	87.85		(184		)	(184		)	—	—		—		—		(184		)	(184		)
5/13 - 5/13	36,000	87.85		(198		)	(198		)	—	—		—		—		(198		)	(198		)
6/13 - 6/13	23,000	87.85		(129		)	(129		)	—	—		—		—		(129		)	(129		)
7/13 - 7/13	15,000	87.85		(84		)	(84		)	—	—		—		—		(84		)	(84		)
8/13 - 8/13	11,000	87.85		(60		)	(60		)	—	—		—		—		(60		)	(60		)
9/13 - 9/13	20,000	87.85		(106		)	(106		)	—	—		—		—		(106		)	(106		)
10/13 - 10/13	4,000	87.85		(21		)	(21		)	—	—		—		—		(21		)	(21		)
11/13 - 11/13	250	87.85		(1		)	(1		)	—	—		—		—		(1		)	(1		)
12/13 - 12/13	2,500	87.85		(12		)	(12		)	—	—		—		—		(12		)	(12		)
1/14 - 1/14	46,000	87.85		(211		)	(211		)	—	—		—		—		(211		)	(211		)
2/14 - 2/14	25,000	87.85		(110		)	(110		)	—	—		—		—		(110		)	(110		)
3/14 - 3/14	56,000	87.85		(239		)	(239		)	—	—		—		—		(239		)	(239		)
4/14 - 4/14	45,000	87.85		(186		)	(186		)	—	—		—		—		(186		)	(186		)
5/14 - 5/14	46,000	87.85		(182		)	(182		)	—	—		—		—		(182		)	(182		)
6/14 - 6/14	48,000	87.85		(181		)	(181		)	—	—		—		—		(181		)	(181		)
7/14 - 7/14	36,000	87.85		(129		)	(129		)	—	—		—		—		(129		)	(129		)
8/14 - 8/14	34,000	87.85		(117		)	(117		)	—	—		—		—		(117		)	(117		)
9/14 - 9/14	26,000	87.85		(86		)	(86		)	—	—		—		—		(86		)	(86		)

10/14 - 10/14	27,000		87.85		(86		)	(86		)	—	—		—		—		(86		)	(86		)
11/14 - 11/14	20,000		87.85		(61		)	(61		)	—	—		—		—		(61		)	(61		)
12/14 - 12/14	31,000		87.85		$	(87	)	$	(87	)	—	—		$	—	$	—	$	(87	)	$	(87	)
9/13 - 9/13	(17,500	)	$	89.15	$	72		$	72		—	$	—	$	—	$	—	$	72		$	72
					$	(8,071	)	$	(8,071	)				$	5,388	$	5,388	$	(2,683	)	$	(2,683	)

Fair values, on a gross basis, of derivatives not Designated as Hedging Instruments Recorded in the Consolidated Balance Sheet

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

	Asset Derivatives			Liability Derivatives
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair value at December 31, 2013		Balance Sheet Location	Fair value at December 31, 2013
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	1,370	Current	$	(9,828	)
	Non-current	—		Non-current	(31		)
Total derivative instruments		$	1,370		$	(9,859	)

	Asset Derivatives			Liability Derivatives
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
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	6,808	Current	$	(4,400	)
	Non-current	1,235		Non-current	(6,326		)
Total derivative instruments		$	8,043		$	(10,726	)

Effect of Derivative Instruments on Consolidated Statements of Operations

		Twelve Months Ended December 31,
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Statements of Operations Location	2013			2012			2011
Commodity Contracts	Realized (loss) gain on derivative financial instruments	$	(1,522	)	$	23,364		$	8,099
Commodity Contracts	Unrealized gain (loss) on derivative financial instruments	(5,806		)	(4,783		)	17,556
Total derivative instruments		$	(7,328	)	$	18,581		$	25,655

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Risks and Uncertainties (Details) (USD $)	0 Months Ended	3 Months Ended								12 Months Ended
	Dec. 20, 2013	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Risks and Uncertainties (Textual) [Abstract]
Net working capital		$ (109,600,000)								$ (109,600,000)
Net (loss) income		(41,228,000)	(18,415,000)	(39,518,000)	(16,212,000)	(47,256,000)	(32,575,000)	21,517,000	(5,654,000)	(32,917,000)	(63,968,000)	15,041,000
Proceeds from sales	$ 10,000,000									$ 131,800,000

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Debt and Notes Payable (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Scheduled maturities of principal amounts of debt obligations
2014	$ 257
2015	184,530
2016	16
2017	0
2018	0
Notes and loans payable	184,803
Unamortized discount on 13.75% Senior Secured Notes	(617)	(882)
Total debt	$ 184,186	$ 204,670

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 6,227	$ 1,383
Restricted cash	775	0
Accounts receivable, net of allowance for doubtful accounts of $811 and $509 at December 31, 2013 and 2012, respectively	61,747	46,553
Accounts receivable - insurance recovery	0	3,100
Due from affiliates	273	347
Prepaid expenses and other	7,109	27,972
Current portion of escrow for abandonment costs	21,976	0
Derivative assets	1,370	2,408
TOTAL CURRENT ASSETS	99,477	81,763
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $293,973 and $191,326 at December 31, 2013 and 2012, respectively	196,136	260,012
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $5,350 and $1,717 at December 31, 2013 and 2012, respectively	4,862	1,968
OTHER ASSETS
Debt issue costs, net	1,488	3,230
Asset retirement obligation escrow receivable	20,348	20,348
Escrow for abandonment costs	235,473	215,263
Other assets	7,830	7,880
TOTAL OTHER ASSETS	265,139	246,721
TOTAL ASSETS	565,614	590,464
CURRENT LIABILITIES:
Accounts payable and accrued expenses	155,880	108,736
Derivative liabilities	9,828	0
Asset retirement obligations	43,109	41,572
Current portion of debt and notes payable	257	3,552
TOTAL CURRENT LIABILITIES	209,074	153,860
LONG-TERM LIABILITIES
Gas imbalance payable	1,888	2,521
Dividends payable	0	12,408
Derivative liabilities	31	5,091
Asset retirement obligations, net of current portion	233,623	303,933
Debt, net of current portion, net of unamortized discount of $617 and $882 at December 31, 2013 and 2012, respectively	183,929	201,118
TOTAL LONG-TERM LIABILITIES	419,471	525,071
TOTAL LIABILITIES	628,545	678,931
CLASS E and CLASS D PREFERRED UNITS	109,744	30,000
COMMITMENTS AND CONTINGENCIES
MEMBERS’ DEFICIT	(172,675)	(118,467)
TOTAL LIABILITIES AND MEMBERS’ DEFICIT	$ 565,614	$ 590,464

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Accounts Payable and Accrued Expenses (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounts payable and accrued expenses
Accounts payable—trade	$ 122,015	$ 61,530
Accrued operating expenses	19,014	42,194
Interest payable	2,410	1,913
Other payables	12,441	3,099
Accounts payable and accrued expenses, Total	$ 155,880	$ 108,736

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$ (32,917)	$ (63,968)	$ 15,041
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	43,606	47,314	47,214
Impairment of oil and gas properties	79,090	31,033	12,967
Accretion of asset retirement obligations	23,454	36,421	27,410
Amortization of debt issue cost	4,611	4,777	2,915
Accretion of debt discount	265	232	203
Unrealized loss (gain) on derivative financial instruments	5,806	4,783	(17,556)
(Gain) loss on sale of assets	(105,771)	38	(142)
Provision on doubtful accounts	1,174	509	0
Gain due to involuntary conversion of asset	(17,827)	(3,100)	0
Changes in operating assets and liabilities:
Accounts receivable	(12,233)	5,238	(26,348)
Escrow Receivable, short term	(21,976)	0	0
Due to/from affiliates, net	74	(185)	413
Prepaid expenses and other assets	20,921	(1,744)	(13,513)
Other assets	253	0	0
Accounts payable and accrued expenses	36,732	36,427	38,199
Gas imbalance	(835)	999	(4,748)
Settlement of asset retirement obligations	(46,114)	(32,720)	(8,408)
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES	(21,688)	66,054	73,647
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties	(128,696)	(42,238)	(21,169)
Acquisitions of oil and gas properties	(3,250)	(3,455)	(27,398)
Sale of oil and gas properties	128,712	(38)	150
Additions to property and equipment	(477)	(570)	(1,699)
Cash assumed in consolidation of Freedom Well Services, LLC	473	0	0
Proceeds received from insurance recovery	24,090	0	0
Deposits	0	(312)	(540)
Restricted cash	(775)	0	0
Escrow payments, net	(20,210)	(43,110)	(57,985)
NET CASH USED IN INVESTING ACTIVITIES	(133)	(89,723)	(108,641)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on short term notes	1,081	17,644	18,979
Payments on short term notes	(4,554)	(18,247)	(16,895)
Borrowings on bank debt	54,000	171,500	158,457
Payments on bank debt	(71,500)	(143,500)	(134,457)
Debt issuance costs	(2,362)	(3,022)	(2,770)
Contributions from preferred members	50,000	110	30,000
Distributions to members	0	(16,693)	(19,939)
NET CASH PROVIDED BY FINANCING ACTIVITIES	26,665	7,792	33,375
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	4,844	(15,877)	(1,619)
CASH AND CASH EQUIVALENTS—BEGINING OF PERIOD	1,383	17,260	18,879
CASH AND CASH EQUIVALENTS—END OF PERIOD	6,227	1,383	17,260
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	23,603	23,603	22,050
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Increase in asset retirement obligations	2,341	53,118	147,442
Asset retirement obligations relieved due to sale of properties	(48,454)	0
Assumption of gas imbalances	0	0	(1,159)
Increase in asset retirement obligation escrow receivable	0	0	20,348
Paid-in-kind dividends on preferred equity and accrued distributions to members	17,336	8,208	4,200
Class D preferred units transferred to Class E preferred units	$ 12,408	$ 0	$ 0

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Major Customers and Concentrations of Credit Risk (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Shell Trading (US) Company
Schedule purchasers and operators accounted for oil and natural gas sales
Customer accounted sales rate	62.00%	18.00%	51.00%
JP Morgan Ventures Energy Corporation
Schedule purchasers and operators accounted for oil and natural gas sales
Customer accounted sales rate	0.00%	41.00%	8.00%

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Major Customers and Concentrations of Credit Risk (Tables)

12 Months Ended

Dec. 31, 2013

Risks and Uncertainties [Abstract]

Schedule purchasers and operators accounted for oil and natural gas sales

The following purchasers and operators accounted for 10% or more of our oil and natural gas sales:

	Year Ended December 31,
	2013		2012		2011
Shell Trading (US) Company	62	%	18	%	51	%
JP Morgan Ventures Energy Corporation	—	%	41	%	8	%

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Supplemental Oil and Natural Gas Reserve Information (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Future cash inflows	$ 1,611,000	$ 2,552,252	$ 2,641,791
Future cost:
Production	573,233	695,079	714,076
Development	212,376	496,834	544,523
Future income taxes	0	0	0
Future net cash flows	825,391	1,360,339	1,383,192
10% annual discount for estimated timing of cash flows	189,441	302,546	321,784
Standardized measure of discounted future net cash flows	$ 635,950	$ 1,057,793	$ 1,061,408

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

General

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessment of the property would be necessary to adequately determine remediation costs, if any. Management does not consider the amounts that would result from any environmental site assessments to be significant to the consolidated financial position or results of our operations. Accordingly, no provision for potential remediation costs is reflected in the accompanying consolidated financial statements.

We are subject to claims and lawsuits that arise primarily in the ordinary course of business. It is the opinion of management that the disposition or ultimate resolution of such claims and lawsuits will not have a material adverse effect on our consolidated financial position or results of operations.

West Delta 32

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. At the time of the explosion, production on the platform had been shut in while crews of independent contractors performed maintenance and construction on the platform. Three workers died as a result of the explosion and subsequent fire, and others sustained varying degrees of personal injuries. An investigation by the Bureau of Safety Enforcement and Environment Agency (“BSEE”), in coordination with the U.S. Coast Guard, has been finalized. As a result of the investigation, it is possible that BSEE could issue Incidents of Non-Compliance. We are currently waiting for BSEE’s conclusion of its assessment of penalties.

The United States Chemical Safety and Hazard Investigation Board has also made inquiry regarding the incident but has decided not to formally opened an investigation. Additionally, civil lawsuits relating to the explosion have been filed and are pending in federal courts.

On January 31, 2013, the family of decedent Jerome Malagapo sued BEEOO in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Malagapo’s wife individually and on behalf of his estate and Mr. Malagapo’s children. The plaintiffs allege that Mr. Malagapo was employed by Grand Isle Shipyard, Inc. and was working on the West Delta 32 Block Platform and as a result of the incident died. The plaintiffs are seeking an unspecified amount of actual and punitive damages.

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

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

For each proceeding, we are currently evaluating the plaintiff’s petitions and determining appropriate courses of response with the aid of legal counsel. These proceedings are at a preliminary stage; accordingly, we currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings. We intend to vigorously defend the Company in these proceedings.

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

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 which took place on November 12, 2013. Since the mediation was unsuccessful, the Parties have now agreed to enter into binding Arbitration, pursuant to and in accordance with the MSA. The Arbitration proceedings are underway.

Operating Leases

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

Approximate future minimum lease payments for operating leases at December 31, 2013 were as follows:

Year Ending December 31,	(in thousands)
2014	$	7,274
2015	2,151
2016	1,973
2017	1,695
2018	1,536
Thereafter	3,093
	$	17,722

Rent expense of approximately $1.7 million, $1.5 million and $1.0 million was incurred under operating leases in the years ended December 31, 2013, 2012 and 2011, respectively.

Escrow Accounts

Pursuant to the purchase agreement from W&T Offshore, Inc. (“W&T”), 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 $49.2 million ($18.0 million operated and $31.2 million non-operated) for future P&A costs that may be incurred on such properties. We were required to fully fund such obligations by the end of 2012 with respect to the operating properties and by the end of 2016 with respect to non-operating properties. The maximum obligation of $63.8 million may be adjusted downward in certain situations. We may withdraw cash from the W&T Escrow Accounts as reimbursement for performed P&A obligations. However, no cash may be withdrawn if at any point we are in default under our stipulated payment schedules. As of November 2010, we fully funded the operating escrow account in the amount of $43.1 million and the payment schedule for the Non-Operated Properties Escrow Account was amended and commenced on December 2011. As of December 31, 2013, we have funded $17.5 million into the non-operating escrow account, leaving $13.7 million to be funded through May 1, 2017.

The obligations under the W&T Escrow Accounts are fully guaranteed by an affiliate of Platinum. W&T Offshore Inc. (“W&T”) has a first lien on the entirety of the W&T Escrow Accounts, and BP Corporation North America Inc. and Platinum are pari passu second lien holders. Once P&A obligations with respect to the interest in properties acquired from the W&T Acquisition have been fully satisfied, the lien on the W&T Escrow Accounts will be automatically extinguished. W&T also has a second priority lien with respect to the interest in properties acquired from the W&T Acquisition (with Platinum and BNP Paribas sharing a first priority lien), which lien will be released once the W&T Escrow Accounts have been fully funded.

On December 19, 2012, we entered into a Third Amendment to Purchase and Sale Agreement (the “Third Amendment”) with W&T. Pursuant to the Third Amendment, we caused performance bonds (the “ARGO Bonds”) in an aggregate amount of $32.6 million to be issued by Argonaut Insurance Company to W&T to guaranty our performance of certain plugging and abandonment obligations. Upon receipt of the ARGO Bonds, W&T (i) released its rights to any money held in an escrow account established to secure our performance of certain plugging and abandonment obligations with respect to the Operated Properties Escrow Account, (ii) released the security interest and deposit account control agreement formerly securing its rights in the Operated Properties Escrow Account and (iii) authorized the escrow agent to release such funds from the Operated Properties Escrow Account to or at our direction. In addition, we and W&T agreed that until the funding of an escrow account established to our performance of certain plugging and abandonment obligations with respect to certain non-operated properties is complete, we may not obtain reductions of the ARGO Bonds under any circumstances without W&T’s consent.

Pursuant to the purchase agreement for the Maritech Acquisition, we are required to fund an escrow account (the “Maritech Escrow Account”), relating to the properties that were acquired of $13.1 million to be used for future P&A costs that may be incurred on such properties. As of December 31, 2013, we have funded $12.4 million, leaving $0.7 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 December 31, 2013, we have fully funded the escrow obligation.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Future minimum lease payments table

Approximate future minimum lease payments for operating leases at December 31, 2013 were as follows:

Year Ending December 31,	(in thousands)
2014	$	7,274
2015	2,151
2016	1,973
2017	1,695
2018	1,536
Thereafter	3,093
	$	17,722

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Supplemental Oil and Natural Gas Reserve Information

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

SUPPLEMENTAL OIL AND NATURAL GAS RESERVE INFORMATION

SUPPLEMENTAL OIL AND NATURAL GAS RESERVE INFORMATION (UNAUDITED)

The supplementary data presented herein reflects information for all of our oil and natural gas producing activities.

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to our oil and natural gas activities for the years ended December 31, 2013, 2012 and 2011:

	Year Ending December 31,
	2013		2012		2011
	(in thousands)
Oil and Gas Activities:
Exploration costs	$	200	$	1,682	$	1,004
Development costs	130,953		42,238		21,169
Acquisition costs	3,250		3,455		27,398
Costs incurred	$	134,403	$	47,375	$	49,571

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and natural gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed reserves in barrels (“MBbls”) and cubic feet (“MMcf”) for each of the periods indicated were as follows:

	Crude Oil and  NGLs (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved reserves at December 31, 2011	20,123		150,393		45,189
Purchases of minerals in place	—		—		—
Extensions and discoveries	3,761		11,343		5,652
Revisions of previous estimates	(94	)	(30,759	)	(5,221	)
Production	(2,301	)	(17,884	)	(5,281	)
Proved reserves at December 31, 2012	21,489		113,093		40,339
Extensions and discoveries	1,950		9,431		3,522
Revisions of previous estimates	(1,633	)	(16,017	)	(4,302	)
Production	(1,941	)	(13,294	)	(4,157	)
Purchases of minerals in place	11		—		11
Sales of minerals in place	(6,829	)	(15,423	)	(9,400	)
Proved reserves at December 31, 2013	13,047		77,790		26,012
Proved developed reserves at December 31, 2013	9,973		53,907		18,957

Our proved undeveloped reserves at December 31, 2013 were 7.1 MMBoe, consisting of 3.1 MMBbls of oil and NGLs and 23.9 Bcf of natural gas. Decreases in proved undeveloped reserves in 2013 were primarily due to the reclassification of several PUDs that had reached the five year period and a lower pricing environment. All proved undeveloped reserves are scheduled to be drilled by 2017 excluding the twelve drills waiting on wellbore availability. Our proved undeveloped reserves at December 31, 2012 were 15.9 MMBoe, consisting of 9.2 MBbls of oil and NGLs and 40.1 Bcf of natural gas. Increases in proved undeveloped reserves were primarily due to continued evaluation of our existing asset base and the Merit Acquisition.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a standardized measure of the discounted net future cash flows and changes applicable to proved oil and natural gas reserves required by accounting guidance for disclosures about oil and natural gas producing activities. The future cash flows are based on estimated oil and natural gas reserves utilizing prices and costs in effect as of year-end, discounted at 10% per year and assuming continuation of existing economic conditions.

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of our proved oil and natural gas properties.

The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.

	December 31,
	2013		2012		2011
	(in thousands)
Future cash inflows	$	1,611,000	$	2,552,252	$	2,641,791
Future cost:
Production	573,233		695,079		714,076
Development	212,376		496,834		544,523
Future income taxes	—		—		—
Future net cash flows	825,391		1,360,339		1,383,192
10% annual discount for estimated timing of cash flows	189,441		302,546		321,784
Standardized measure of discounted future net cash flows	$	635,950	$	1,057,793	$	1,061,408

Changes in Standardized Measure of Discounted Future Net Cash Flows from Oil and Gas Proved Reserves

	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Beginning of year:	$	1,057,793		$	1,061,408		$	392,189
Purchase of minerals in place	348			—			612,048
Extensions and discoveries and improved recovery, net of future production and development cost	108,261			202,334			314,920
Accretion of discount	87,339			83,566			34,238
Net change in sales prices net of production costs	(314,721		)	(61,407		)	112,923
Changes in estimated future development costs	162,099			6,420			(359,942		)
Previously estimated future development costs incurred	74,073			39,433			17,198
Revisions of quantity estimates	(132,242		)	(186,902		)	60,822
Sales, net of production costs	(86,673		)	(88,837		)	(131,500		)
Timing differences and other	(31,392		)	1,778			8,512
Sales of minerals in place	(288,935		)	—			—
Net increase (decrease)	(421,843		)	(3,615		)	669,219
End of year	$	635,950		$	1,057,793		$	1,061,408

The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.

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Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unaudited financial information for each quarter
Total revenues	$ 67,889	$ 63,757	$ 66,374	$ 59,988	$ 64,578	$ 57,125	$ 106,594	$ 76,181	$ 258,008	$ 304,478	$ 339,944
Loss (income) from operations	44,004	(8,881)	(30,683)	(8,972)	(39,631)	(25,153)	28,721	1,245	4,533	(34,818)	46,673
Net (loss) income	(41,228)	(18,415)	(39,518)	(16,212)	(47,256)	(32,575)	21,517	(5,654)	(32,917)	(63,968)	15,041
Net (loss) income attributable to common unit holders	$ (36,418)	$ (23,170)	$ (44,201)	$ (19,355)	$ (49,488)	$ (34,807)	$ 19,573	$ (7,454)	$ (50,253)	$ (72,176)	$ 10,841

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Organization and Business

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION AND BUSINESS

ORGANIZATION AND BUSINESS

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

Effective January 1, 2013, our consolidated financial statements include the accounts of BEEOO, our wholly-owned subsidiaries Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corporation, and our variable interest entity Freedom Well Services, LLC ("FWS"), as we determined that we are the primary beneficiary of FWS and we have the power to direct the activities of FWS.

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 811	$ 509
Accumulated depreciation, depletion, amortization and impairment for oil and gas property	293,973	191,326
Accumulated depreciation for other property and equipment	5,350	1,717
Unamortized discount of debt	$ 617	$ 882

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Defined Contribution Plan

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

DEFINED CONTRIBUTION PLAN

EFINED CONTRIBUTION PLAN

We have a 401(k) Defined Contribution Plan (the “Plan”). Employees become eligible to contribute to the plan and to receive employer contributions the first of the month subsequent to completing one month of service. The Plan allows eligible employees to contribute up to 90% of their annual compensation, not to exceed the maximum amounts permitted by IRS regulations. The defined contribution plan provides that we will make a safe harbor contribution equal to 3% of compensation for the plan year. Employees are 100% vested in contributions that they make to the Plan and any safe harbor contributions. Other contributions made by us fully vest after three years of service. We provided matching contributions to the Plan for the years ended December 31, 2013, 2012 and 2011 of $0.5 million, $0.3 million and $0.5 million, respectively.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jun. 29, 2012	Mar. 31, 2014 Common Class A	Mar. 31, 2014 Common Class B	Mar. 31, 2014 Common Class C	Mar. 31, 2014 Common Class E
Entity Registrant Name	Black Elk Energy Offshore Operations, LLC
Entity Central Index Key	0001518909
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$ 0
Entity Common Stock, Shares Outstanding			1,361,300	114,277,308.5	12,031,250	109,743,693

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Members' Deficit

12 Months Ended

Dec. 31, 2013

Stockholders' Equity Note [Abstract]

MEMBERS' DEFICIT

MEMBERS’ DEFICIT

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

In the first quarter of 2013, we entered into contribution agreements with PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”) or entities designated by PPBE (together, the “Platinum Group”) pursuant to which we have issued 50.0 million additional Class E Preferred Units (the “Class E Units”) and 3.8 million additional Class B Units to the Platinum Group for an aggregate offering price of $50.0 million. The Class E Units are recorded under "Preferred Units" and the Class B Units are included in "Members Deficit" in the consolidated balance sheets. In addition, we also agreed to issue an additional 43 million Class E Units in exchange for $30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class D Preferred Units were recorded under "Preferred Units" in the consolidated balance sheets. The Class E Units 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 year ended December 31, 2013, we issued an additional amount of Class E Units of approximately 16.7 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.

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Consolidated Statements of Operations (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES:
Oil sales	$ 182,731	$ 210,720	$ 215,204
Natural gas sales	51,520	50,470	75,994
Plant product sales and other revenue	31,085	24,707	23,091
Realized (loss) gain on derivative financial instruments	(1,522)	23,364	8,099
Unrealized (loss) gain on derivative financial instruments	(5,806)	(4,783)	17,556
TOTAL REVENUES	258,008	304,478	339,944
OPERATING EXPENSES:
Lease operating	177,210	180,691	158,545
Production taxes	627	745	859
Workover	8,224	17,986	23,385
Exploration	200	1,682	1,004
Depreciation, depletion and amortization	43,606	47,314	47,214
Impairment	79,090	31,033	12,967
General and administrative	36,601	26,486	22,029
Gain due to involuntary conversion of asset	(17,827)	(3,100)	0
Accretion	23,454	36,421	27,410
Loss (gain) on sale of asset	(105,771)	38	(142)
Other operating expenses	8,061	0	0
TOTAL OPERATING EXPENSES	253,475	339,296	293,271
INCOME (LOSS) FROM OPERATIONS	4,533	(34,818)	46,673
OTHER INCOME (EXPENSE):
Interest income	110	319	373
Miscellaneous expense	(10,771)	(3,504)	(6,253)
Interest expense	(26,789)	(25,965)	(25,752)
TOTAL OTHER EXPENSE	(37,450)	(29,150)	(31,632)
NET (LOSS) INCOME	(32,917)	(63,968)	15,041
PREFERRED UNIT DIVIDENDS	17,336	8,208	4,200
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS	$ (50,253)	$ (72,176)	$ 10,841

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Accounts Payable and Accrued Expenses

12 Months Ended

Dec. 31, 2013

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE AND ACCRUED EXPENSES

ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Below are the components of accounts payable and accrued expenses:

	At December 31,
	2013		2012
	(in thousands)
Accounts payable—trade	$	122,015	$	61,530
Accrued operating expenses	19,014		42,194
Interest payable	2,410		1,913
Other payables	12,441		3,099
	$	155,880	$	108,736

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Oil and Gas Properties

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

OIL AND GAS PROPERTIES

OIL AND GAS PROPERTIES

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

	At December 31,
	2013			2012
	(in thousands)
Proved properties	$	490,109		$	451,338
Accumulated depletion, depreciation, amortization and impairment	(293,973		)	(191,326		)
Oil and Natural Gas Properties, net	$	196,136		$	260,012

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Uncertain Tax Positions

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

UNCERTAIN TAX POSITIONS

UNCERTAIN TAX POSITIONS

As we are considered a flow through entity for U.S. federal tax purposes, our only exposure to uncertain tax positions relates to the Texas margins tax.

We did not have unrecognized tax benefits as of December 31, 2013 and 2012, and do not expect this to change significantly over the next 12 months. In accordance with accounting guidance for income taxes, we will recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of December 31, 2013 , 2012 and 2011, we have not accrued interest or penalties related to uncertain tax positions.

Our tax years for fiscal years ended December 31, 2013, 2012, and 2011 are subject to examination in the United States and relevant state jurisdictions.

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Gain on Involuntary Conversion

12 Months Ended

Dec. 31, 2013

Gain On Involuntary Conversion [Abstract]

GAIN ON INVOLUNTARY CONVERSION

GAIN ON INVOLUNTARY CONVERSION

High Island 443 A-2

On September 27, 2012, an incident occurred on our High Island 443 A-2 ST well which required the closing of the blind/shear rams to properly shut in and maintain control of the well due to several days of unsuccessful attempts to repair a small hydrocarbon leak on a conductor riser. Additional surface diagnostics found the inner casing strings to be most likely compromised. On October 12, 2012, the Bureau of Safety and Environmental Enforcement (“BSEE”) advised us to plug and abandon the well. We have well control insurance and pursued reimbursement for this incident. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drill are also insurance recoverable.

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 December 31, 2013, the claim was finalized and we received at total of approximately$24.1 million, net of deductibles, in cash for the claim during 2013. Of this amount, $17.8 million was recognized as a gain on involuntary asset conversion on the consolidated statement of operations.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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 December 31, 2013 and 2012, and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands):

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

	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 December 31, 2013 and 2012, management estimates that the derivative contracts had a fair value of $(8.5) million and $(2.7) million, respectively. We estimated the fair value of derivative instruments using internally-developed models that use as their basis, readily observable market parameters.

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

As of December 31, 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 December 31, 2013 was $164.1 million.

Fair Value on a Non-Recurring Basis

As of December 31, 2013, oil and gas properties with a carrying value of $275.2 million were written down to their fair value of $196.1 million, resulting in an impairment charge, which is recognized under “Impairments” in the consolidated statements of operations, of $79.1 million for the year ended December 31, 2013. As of December 31, 2012, oil and gas properties with a carrying value of $291.0 million were written down to their fair value of $260.0 million, resulting in an impairment charge of $31.0 million. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

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Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Future minimum lease payments table
2014	$ 7,274
2015	2,151
2016	1,973
2017	1,695
2018	1,536
Thereafter	3,093
Operating lease, total	$ 17,722

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

Accounting guidance requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon our interim review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost.

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

	At December 31,
	2013			2012
	(in thousands)
Beginning of year	$	345,505		$	288,686
Revaluation of liability	2,341			53,118
Liabilities relieved due to sale of properties	(48,454		)	—
Liabilities settled	(46,114		)	(32,720		)
Accretion expense	23,454			36,421
End of year	$	276,732		$	345,505
Less: Current portion	$	(43,109	)	$	(41,572	)
LT Asset retirement obligations	$	233,623		$	303,933

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Derivative Instruments

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

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

At December 31, 2013, the notional volumes of our commodity derivative contracts were as follows:

	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)
1/14 - 2/14	19,000	$	96.90	$	(60	)	$	(60	)	82,000	$	4.60	$	45		$	45		$	(15	)	$	(15	)
1/14 - 5/14	10,083	100.80		136			136			129,960	4.94		$	464		464			600			600
6/14 - 6/14	—	—		—			—			129,960	4.94		101			101			101			101
1/14 - 12/14	15,000	65.00		(5,172		)	(5,172		)	—	—		—			—			(5,172		)	(5,172		)
1/14 - 1/14	4,723	88.80		(46		)	(46		)	43,347	4.09		(14		)	(14		)	(60		)	(60		)
2/14 - 2/14	13,313	88.80		(128		)	(128		)	32,636	4.09		(5		)	(5		)	(133		)	(133		)
3/14 - 3/14	8,413	88.80		(78		)	(78		)	46,764	4.09		(5		)	(5		)	(83		)	(83		)
4/14 - 4/14	12,473	88.80		(108		)	(108		)	41,253	4.09		(1		)	(1		)	(109		)	(109		)
5/14 - 5/14	11,793	88.80		(92		)	(92		)	40,391	4.09		—			—			(92		)	(92		)
6/14 - 6/14	15,546	88.80		(108		)	(108		)	20,112	4.09		(1		)	(1		)	(109		)	(109		)
7/14 - 7/14	11,845	88.80		(72		)	(72		)	39,283	4.09		(2		)	(2		)	(74		)	(74		)
8/14 - 8/14	13,165	88.80		(69		)	(69		)	34,246	4.09		(2		)	(2		)	(71		)	(71		)
9/14 - 9/14	16,235	88.80		(74		)	(74		)	29,753	4.09		(2		)	(2		)	(76		)	(76		)
10/14 - 10/14	15,605	88.80		(60		)	(60		)	28,635	4.09		(2		)	(2		)	(62		)	(62		)
11/14 - 11/14	18,525	88.80		(61		)	(61		)	27,081	4.09		(3		)	(3		)	(64		)	(64		)
12/14 - 12/14	22,526	88.80		(57		)	(57		)	34,114	4.09		(7		)	(7		)	(64		)	(64		)
1/14 - 1/14	46,000	87.85		(489		)	(489		)	—	—		—			—			(489		)	(489		)
2/14 - 2/14	25,000	87.85		(263		)	(263		)	—	—		—			—			(263		)	(263		)
3/14 - 3/14	56,000	87.85		(570		)	(570		)	—	—		—			—			(570		)	(570		)
4/14 - 4/14	45,000	87.85		(431		)	(431		)	—	—		—			—			(431		)	(431		)
5/14 - 5/14	46,000	87.85		(400		)	(400		)	—	—		—			—			(400		)	(400		)
6/14 - 6/14	48,000	87.85		(377		)	(377		)	40,391	4.19		3			3			(374		)	(374		)
7/14 - 7/14	36,000	87.85		(250		)	(250		)	20,112	4.19		1			1			(249		)	(249		)
8/14 - 8/14	34,000	87.85		(208		)	(208		)	39,283	4.19		1			1			(207		)	(207		)
9/14 - 9/14	26,000	87.85		(141		)	(141		)	34,246	4.19		1			1			(140		)	(140		)
10/14 - 10/14	27,000	87.85		(128		)	(128		)	29,753	4.19		1			1			(127		)	(127		)
11/14 - 11/14	20,000	87.85		(83		)	(83		)	28,635	4.19		—			—			(83		)	(83		)
12/14 - 12/14	31,000	87.85		(105		)	(105		)	27,081	4.19		(3		)	(3		)	(108		)	(108		)
1/15 - 1/15	—	—		—			—			34,114	4.19		(5		)	(5		)	(5		)	(5		)
2/15 - 2/15	—	—		—			—			27,838	4.19		(4		)	(4		)	(4		)	(4		)
3/15 - 3/15	—	—		—			—			24,461	4.19		(3		)	(3		)	(3		)	(3		)
1/15 - 1/15	—	—		—			—			27,838	4.09		(8		)	(8		)	(8		)	(8		)
2/15 - 2/15	—	—		—			—			24,461	4.09		(6		)	(6		)	(6		)	(6		)
3/15 - 3/15	—	—		—			—			26,443	4.09		(5		)	(5		)	(5		)	(5		)
1/14 - 1/14	46,006	100.72		(57		)	(57		)	—	—		—			—			(57		)	(57		)
2/14 - 2/14	39,159	100.72		(45		)	(45		)	—	—		—			—			(45		)	(45		)
3/14 - 3/14	36,822	100.72		(33		)	(33		)	—	—		—			—			(33		)	(33		)
4/14 - 4/14	34,069	100.72		(16		)	(16		)	—	—		—			—			(16		)	(16		)
5/14 - 5/14	35,200	100.72		3			3			—	—		—			—			3			3
6/14 - 6/14	31,668	100.72		18			18			—	—		—			—			18			18
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		124			124			—	—		—			—			124			124
11/14 - 11/14	40,874	100.72		131			131			—	—		—			—			131			131
12/14 - 12/14	26,424	100.72		80			80			—	—		—			—			80			80
				(9,028		)	(9,028		)				539			539			(8,489		)	(8,489		)

At December 31, 2012, the notional volumes of our commodity derivative contracts were as follows:

	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)
1/13 - 10/13	27,750	$	96.90	$	983		$	983		104,000	$	4.60	$	1,114	$	1,114	$	2,097		$	2,097
11/13 - 11/13	26,800	96.90		88			88			104,000	4.60		$	81	$	81	169			169
12/13 - 12/13	27,750	96.90		95			95			104,000	4.60		61		61		156			156
1/14 - 2/14	19,000	96.90		136			136			82,000	4.60		80		80		216			216
1/13 - 6/13	15,542	100.80		715			715			200,669	4.94		1,806		1,806		2,521			2,521
7/13 - 7/13	7,132	100.80		47			47			148,788	4.94		194		194		241			241
8/13 - 8/13	5,980	100.80		40			40			139,212	4.94		176		176		216			216
9/13 - 9/13	3,897	100.80		26			26			116,125	4.94		145		145		171			171
10/13 - 10/13	3,259	100.80		22			22			91,166	4.94		110		110		132			132
11/13 - 11/13	—	—		—			—			64,926	4.94		71		71		71			71
12/13 - 12/13	10,042	100.80		70			70			119,462	4.94		107		107		177			177
1/14 - 5/14	10,083	100.80		361			361			129,960	4.94		547		547		908			908
6/14 - 6/14	—	—		—			—			129,960	4.94		111		111		111			111
1/13 - 12/13	19,750	85.90		(1,649		)	(1,649		)	47,000	5.00		785		785		(864		)	(864		)
1/14 - 12/14	15,000	65.00		(4,199		)	(4,199		)	—	—		—		—		(4,199		)	(4,199		)
1/13 - 1/13	9,042	88.80		(29		)	(29		)	—	—		—		—		(29		)	(29		)
2/13 - 2/13	23,522	88.80		(84		)	(84		)	—	—		—		—		(84		)	(84		)
3/13 - 3/13	16,792	88.80		(67		)	(67		)	—	—		—		—		(67		)	(67		)
4/13 - 4/13	23,812	88.80		(103		)	(103		)	—	—		—		—		(103		)	(103		)
5/13 - 5/13	24,012	88.80		(110		)	(110		)	—	—		—		—		(110		)	(110		)
6/13 - 6/13	29,752	88.80		(140		)	(140		)	—	—		—		—		(140		)	(140		)
7/13 - 7/13	23,143	88.80		(108		)	(108		)	—	—		—		—		(108		)	(108		)
8/13 - 8/13	24,915	88.80		(114		)	(114		)	—	—		—		—		(114		)	(114		)
9/13 - 9/13	28,688	88.80		(127		)	(127		)	—	—		—		—		(127		)	(127		)
10/13 - 10/13	28,006	88.80		(120		)	(120		)	—	—		—		—		(120		)	(120		)
11/13 - 11/13	31,605	88.80		(130		)	(130		)	—	—		—		—		(130		)	(130		)
12/13 - 12/13	38,743	88.80		(152		)	(152		)	—	—		—		—		(152		)	(152		)
1/14 - 1/14	4,723	88.80		(17		)	(17		)	—	—		—		—		(17		)	(17		)
2/14 - 2/14	13,313	88.80		(48		)	(48		)	—	—		—		—		(48		)	(48		)
3/14 - 3/14	8,413	88.80		(29		)	(29		)	—	—		—		—		(29		)	(29		)
4/14 - 4/14	12,473	88.80		(41		)	(41		)	—	—		—		—		(41		)	(41		)
5/14 - 5/14	11,793	88.80		(37		)	(37		)	—	—		—		—		(37		)	(37		)
6/14 - 6/14	15,546	88.80		(46		)	(46		)	—	—		—		—		(46		)	(46		)
7/14 - 7/14	11,845	88.80		(33		)	(33		)	—	—		—		—		(33		)	(33		)
8/14 - 8/14	13,165	88.80		(34		)	(34		)	—	—		—		—		(34		)	(34		)
9/14 - 9/14	16,235	88.80		(41		)	(41		)	—	—		—		—		(41		)	(41		)
10/14 - 10/14	15,605	88.80		(38		)	(38		)	—	—		—		—		(38		)	(38		)
11/14 - 11/14	18,525	88.80		(42		)	(42		)	—	—		—		—		(42		)	(42		)
12/14 - 12/14	22,526	88.80		(46		)	(46		)	—	—		—		—		(46		)	(46		)
1/13 - 1/13	66,000	87.85		(272		)	(272		)	—	—		—		—		(272		)	(272		)
2/13 - 2/13	34,000	87.85		(154		)	(154		)	—	—		—		—		(154		)	(154		)
3/13 - 3/13	50,000	87.85		(246		)	(246		)	—	—		—		—		(246		)	(246		)
4/13 - 4/13	35,000	87.85		(184		)	(184		)	—	—		—		—		(184		)	(184		)
5/13 - 5/13	36,000	87.85		(198		)	(198		)	—	—		—		—		(198		)	(198		)
6/13 - 6/13	23,000	87.85		(129		)	(129		)	—	—		—		—		(129		)	(129		)
7/13 - 7/13	15,000	87.85		(84		)	(84		)	—	—		—		—		(84		)	(84		)
8/13 - 8/13	11,000	87.85		(60		)	(60		)	—	—		—		—		(60		)	(60		)
9/13 - 9/13	20,000	87.85		(106		)	(106		)	—	—		—		—		(106		)	(106		)
10/13 - 10/13	4,000	87.85		(21		)	(21		)	—	—		—		—		(21		)	(21		)
11/13 - 11/13	250	87.85		(1		)	(1		)	—	—		—		—		(1		)	(1		)
12/13 - 12/13	2,500	87.85		(12		)	(12		)	—	—		—		—		(12		)	(12		)
1/14 - 1/14	46,000	87.85		(211		)	(211		)	—	—		—		—		(211		)	(211		)
2/14 - 2/14	25,000	87.85		(110		)	(110		)	—	—		—		—		(110		)	(110		)
3/14 - 3/14	56,000	87.85		(239		)	(239		)	—	—		—		—		(239		)	(239		)
4/14 - 4/14	45,000	87.85		(186		)	(186		)	—	—		—		—		(186		)	(186		)
5/14 - 5/14	46,000	87.85		(182		)	(182		)	—	—		—		—		(182		)	(182		)
6/14 - 6/14	48,000	87.85		(181		)	(181		)	—	—		—		—		(181		)	(181		)
7/14 - 7/14	36,000	87.85		(129		)	(129		)	—	—		—		—		(129		)	(129		)
8/14 - 8/14	34,000	87.85		(117		)	(117		)	—	—		—		—		(117		)	(117		)
9/14 - 9/14	26,000	87.85		(86		)	(86		)	—	—		—		—		(86		)	(86		)

10/14 - 10/14	27,000		87.85		(86		)	(86		)	—	—		—		—		(86		)	(86		)
11/14 - 11/14	20,000		87.85		(61		)	(61		)	—	—		—		—		(61		)	(61		)
12/14 - 12/14	31,000		87.85		$	(87	)	$	(87	)	—	—		$	—	$	—	$	(87	)	$	(87	)
9/13 - 9/13	(17,500	)	$	89.15	$	72		$	72		—	$	—	$	—	$	—	$	72		$	72
					$	(8,071	)	$	(8,071	)				$	5,388	$	5,388	$	(2,683	)	$	(2,683	)

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

	Asset Derivatives			Liability Derivatives
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair value at December 31, 2013		Balance Sheet Location	Fair value at December 31, 2013
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	1,370	Current	$	(9,828	)
	Non-current	—		Non-current	(31		)
Total derivative instruments		$	1,370		$	(9,859	)

	Asset Derivatives			Liability Derivatives
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
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	6,808	Current	$	(4,400	)
	Non-current	1,235		Non-current	(6,326		)
Total derivative instruments		$	8,043		$	(10,726	)

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

		Twelve Months Ended December 31,
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Statements of Operations Location	2013			2012			2011
Commodity Contracts	Realized (loss) gain on derivative financial instruments	$	(1,522	)	$	23,364		$	8,099
Commodity Contracts	Unrealized gain (loss) on derivative financial instruments	(5,806		)	(4,783		)	17,556
Total derivative instruments		$	(7,328	)	$	18,581		$	25,655

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Debt and Notes Payable

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

DEBT AND NOTES PAYABLE

DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:

	December 31, 2013			December 31, 2012
	(in thousands)
Senior Secured Revolving Credit Facility	$	34,500		$	52,000
13.75% Senior Secured Notes, net of discount	149,383			149,118
AFCO Credit Corporation-insurance note payable	—			3,552
Other debt	303			—
Total debt	184,186			204,670
Less: current portion	(257		)	(3,552		)
Total long-term debt	$	183,929		$	201,118

Senior Secured Revolving Credit Facility

On December 24, 2010 we entered into a credit facility (the “Credit Facility”) comprised of a senior secured revolving credit facility (the “Revolving Credit Facility”) and a secured letter of credit to be used exclusively for the issuance of letters of credit in support of our future P&A liabilities relating to our oil and natural gas properties (the “Letter of Credit Facility”).

During 2013, we have entered into various amendments to the Credit Facility. These amendments have (1) changed our amount available for borrowing under the Revolving Credit Facility, (2) increased the secured letter of credit from $35 million to $47 million, (3) amended certain provisions governing our swap agreements, (4) updated the fees on the letters of credit to 2% on a go-forward basis, (5) updated the “change in control” definition, (6) amended the definition of debt included in the calculation of the covenants, (7) changed the maturity date to January 1, 2015 on the Credit Facility and to June 22, 2014 on the Letter of Credit Facility, (8) received waivers related to our financial covenants for the third and fourth quarters of 2013, (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 (the “Platinum Group”) during the first quarter of 2013 and (11) revised the definition of “Event of Default” to include non-compliance with new affirmative covenants, (12) restricted returns of capital to our unit holders or distributions of our property to our equity interest holders and (13) waived our right and the rights of the Lenders to request or obtain a borrowing base redetermination prior to the first scheduled redetermination date in 2014.

As of December 31, 2013, we had $34.5 million of borrowings outstanding and $66.6 million of letters of credit issued resulting in zero borrowings available under the Credit Facility. On March 17, 2014, our credit facility was paid off.

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 2.5 to 1.0, or 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 December 31, 2013, we were not in compliance with the total leverage ratio covenant, and the interest coverage ratio covenant. Our total leverage ratio was calculated to be 5.0 to 1.0, which was higher than the required maximum of 2.5 to 1.0. Our interest coverage ratio covenant was calculated to be 1.4to 1.0, which was lower than the minimum 3.0 to 1.0. Our payables restriction covenant was calculated at $46.9 million which was higher than the maximum of $6.0 million. We received a limited waiver relating to such covenants in the 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 December 31, 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.

13.75% Senior Secured Notes

On November 23, 2010, we issued $150 million face value of 13.75% Senior Secured Notes discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under our prior revolving credit facility, to fund Bureau of Ocean Energy Management, Regulation and Enforcement collateral requirements, and to prefund our escrow accounts. We pay interest on the Notes semi-annually in arrears, on June 1 and December 1 of each year, which commenced on June 1, 2011. The Notes will mature on December 1, 2015, of which all principal then outstanding will be due. As of December 31, 2013 and 2012, the recorded value of the Notes was $149.4 million and $149.1 million, respectively, which includes the unamortized discount of $0.6 million and $0.9 million, respectively. We incurred underwriting and debt issue costs of $7.2 million which have been capitalized and will be amortized over the life of the Notes.

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

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

On May 23, 2011, we commenced a consent solicitation that was completed on May 31, 2011 and resulted in our entry into the First Supplemental Indenture. We paid a consent solicitation fee of $4.5 million. The First Supplemental Indenture amended the Indenture to, among other things: (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 (as defined in Note 18) to consolidated leverage to be less than 1.4 to 1.0 as of the last day of each fiscal year. In addition, we and our subsidiaries (excluding FWS) are subject to various covenants, including restricted payments, incurrence of indebtedness and issuance of preferred stock, liens, dividends and other payments, merger, consolidation or sale of assets, transactions with affiliates, designation of restricted and unrestricted subsidiaries, and a maximum limit for capital expenditures. Our limitation on capital expenditures was amended in conjunction with the Consent Solicitation on May 31, 2011 to a maximum limit of $60 million for the fiscal year ending December 31, 2012 and 30% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expense for any year thereafter. As of December 31, 2013, we were in compliance with our covenants under the Indenture.

AFCO Credit Corporation—Insurance Notes Payable

In 2012, we entered into a note to finance annual insurance premiums related to our oil and natural gas properties for an aggregate $17.6 million. The note bore interest at an annual rate of 1.95% compounded monthly. The note was paid off during the first quarter of 2013.

The amounts of required principal payments based on our outstanding debt amounts as of December 31, 2013, were as follows:

Year Ending December 31,	(in thousands)
2014	$	257
2015	184,530
2016	16
2017	—
2018	—
	184,803
Unamortized discount on 13.75% Senior Secured Notes	(617		)
Total debt	$	184,186

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Supplemental Oil and Natural Gas Reserve Information (Details 1)	12 Months Ended
	Dec. 31, 2013 MBoe MBbls	Dec. 31, 2012 MBoe
Estimated quantities of proved domestic oil and natural gas reserves
Proved reserves, Beginning	40,339	45,189
Purchases of minerals in place	11	0
Extensions and discoveries	3,522	5,652
Revisions of previous estimates	(4,302)	(5,221)
Production	(4,157)	(5,281)
Sales of minerals in place	(9,400)
Proved reserves, Ending	26,012	40,339
Proved developed reserves at December 31, 2013	18,957
Crude Oil and NGLs (MBbls)
Estimated quantities of proved domestic oil and natural gas reserves
Proved reserves, Beginning	21,489	20,123
Purchases of minerals in place	11	0
Extensions and discoveries	1,950	3,761
Revisions of previous estimates	(1,633)	(94)
Production	(1,941)	(2,301)
Sales of minerals in place	(6,829)
Proved reserves, Ending	13,047	21,489
Proved developed reserves at December 31, 2013	9,973
Natural Gas (MMcf)
Estimated quantities of proved domestic oil and natural gas reserves
Proved reserves, Beginning	113,093	150,393
Purchases of minerals in place	0	0
Extensions and discoveries	9,431	11,343
Revisions of previous estimates	(16,017)	(30,759)
Production	(13,294)	(17,884)
Sales of minerals in place	(15,423)
Proved reserves, Ending	77,790	113,093
Proved developed reserves at December 31, 2013	53,907

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Supplemental Oil and Natural Gas Reserve Information (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in standardized measure of discounted future net cash flows from oil and gas proved reserves
Beginning of year:	$ 1,057,793	$ 1,061,408	$ 392,189
Purchase of minerals in place	348	0	612,048
Extensions and discoveries and improved recovery, net of future production and development cost	108,261	202,334	314,920
Accretion of discount	87,339	83,566	34,238
Net change in sales prices net of production costs	(314,721)	(61,407)	112,923
Changes in estimated future development costs	162,099	6,420	(359,942)
Previously estimated future development costs incurred	74,073	39,433	17,198
Revisions of quantity estimates	(132,242)	(186,902)	60,822
Sales, net of production costs	(86,673)	(88,837)	(131,500)
Timing differences and other	(31,392)	1,778	8,512
Decrease Due to Sales of Minerals in Place	(288,935)	0	0
Net increase (decrease)	(421,843)	(3,615)	669,219
End of year	$ 635,950	$ 1,057,793	$ 1,061,408

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Supplemental Oil and Natural Gas Reserve Information (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Activities:
Exploration costs	$ 200	$ 1,682	$ 1,004
Development costs	130,953	42,238	21,169
Acquisition costs	3,250	3,455	27,398
Costs incurred	$ 134,403	$ 47,375	$ 49,571

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Debt and Notes Payable (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt and notes payable

Our debt and notes payable are summarized as follows:

	December 31, 2013			December 31, 2012
	(in thousands)
Senior Secured Revolving Credit Facility	$	34,500		$	52,000
13.75% Senior Secured Notes, net of discount	149,383			149,118
AFCO Credit Corporation-insurance note payable	—			3,552
Other debt	303			—
Total debt	184,186			204,670
Less: current portion	(257		)	(3,552		)
Total long-term debt	$	183,929		$	201,118

Scheduled maturities of principal amounts of debt obligations

The amounts of required principal payments based on our outstanding debt amounts as of December 31, 2013, were as follows:

Year Ending December 31,	(in thousands)
2014	$	257
2015	184,530
2016	16
2017	—
2018	—
	184,803
Unamortized discount on 13.75% Senior Secured Notes	(617		)
Total debt	$	184,186

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Fair Value Measurements (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value Measurements (Textual) [Abstract]
Derivative contracts, fair value	$ (8,500,000)	$ (2,700,000)
Debt, fair value	164,100,000
Oil and gas properties with a carrying value	275,200,000	291,000,000
Oil and gas properties, fair value	196,136,000	260,012,000
Impairment	$ 79,090,000	$ 31,033,000	$ 12,967,000

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Major Customers and Concentrations of Credit Risk

12 Months Ended

Dec. 31, 2013

Risks and Uncertainties [Abstract]

MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

RISKS, AND UNCERTAINTIES

While cash flows were lower than previously projected primarily due to lower production and sales of assets in the 3rd and 4th quarters, we continued our development operations by supplementing our cash flows from operating activities with funds raised through borrowings in 2013 and capital contributions from our members. We retained financial and technical advisors to provide recommendations on achieving improvements in production, operating expense, cash flows from operations, work over, capital expenditures and business planning.

As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $(109.6) million at December 31, 2013 and we incurred net losses of $(32.9) million during the year ended December 31, 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 our surety bonds that secure our P&A obligations led to significant cash reductions in the fourth quarter of 2012 and the year 2013. To increase liquidity, we stretched accounts payable, aggressively pursued accounts receivable and sold non-core assets.

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

Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our plugging and abandonment (“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 our surety bonds for P&A obligations. We are currently in discussions with surety agencies to replace the 100% cash-backed letters of credit.

As of December 31, 2013 we have obtained a waiver of certain supplemental bonding requirements from Capital One. The current ratio covenant has been removed in the Seventh Amendment, Ninth Amendment and Tenth Amendment and has been replaced with a payables restriction covenant. Our liquidity projections demonstrate improvement of our financial position and we believe that we will meet our interest coverage ratio covenant, debt leverage ratio covenant and payables restriction covenant going forward.

Our capital budget may be adjusted in the future as business conditions warrant and the ultimate amount of capital we expend may fluctuate materially based on market conditions.

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

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

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

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

MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

Major Customers

The following purchasers and operators accounted for 10% or more of our oil and natural gas sales:

	Year Ended December 31,
	2013		2012		2011
Shell Trading (US) Company	62	%	18	%	51	%
JP Morgan Ventures Energy Corporation	—	%	41	%	8	%

In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of our customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. We believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.

Concentrations of Credit Risk

We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. We had cash deposits in certain banks that at times exceeded the maximum limits federally insured by the Federal Deposit Insurance Corporation. We monitor the financial condition of the banks and have experienced no losses on those accounts.

Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Based on the current demand for oil and natural gas, we do not expect that termination of sales to any of our current purchasers would have a material adverse effect on our ability to find replacement purchasers and to sell our production at favorable market prices.

Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We actively monitor our credit risks related to financial institutions and counterparties including monitoring credit agency ratings, financial position and current news to mitigate this credit risk.

A substantial portion of our oil and natural gas reserves and production are located in the Gulf of Mexico. Our company may be disproportionally exposed to the impact of delays of interruptions of production from these wells due to mechanical problems, damages to the current producing reservoirs and significant governmental regulations, including any curtailment of production or interruption of transportation of oil or natural gas produced from these wells.

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Subsequent Events

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

Actions taken after the 2013 Fiscal Year

Resignation of Bruce Koch

On January 9, 2014, Black Elk Energy Offshore Operations, LLC (the “Company”) announced the resignation of Bruce Koch, Vice President and Chief Financial Officer, effective January 7, 2014. The terms of Mr. Koch’s offer letter included a lump sum severance compensation in an amount equal to one year's annual base salary, plus the benefits for one year the he was entitled to under his employment agreement. In exchange for these benefits, the offer letter contains a general release of claims by Mr. Koch and covenants by Mr. Koch with respect to confidentiality and non-disparagement.

Appointment of Chief Financial Officer

On January 8, 2014, we appointed Jeffrey Shulse as our Chief Financial Officer. 

Senior Secured Revolving Credit Facility

On March 17, 2014 our credit facility was paid off.. 

Sale of Assets

On March 13, 2014 , Black Elk Energy Offshore Operations, LLC (the “Company” or “we”) entered into a Purchase and Sale Agreement (the “PSA”) with a wholly owned subsidiary of Fieldwood Energy LLC (“Fieldwood”). Pursuant to the PSA, Fieldwood acquired all of the Company’s interest in 1 operated and 15 non-operated fields in the offshore Gulf of Mexico, and further described in detail as Exhibit 10.1 and incorporated herein, for $50 million, subject to normal purchase price adjustments (the “Sale”). The Sale closed on March 17, 2014.

Pursuant to the PSA, and subject to specified limitations described therein, we agreed to indemnify Fieldwood its Affiliates (as defined in the PSA) and their respective directors, officers, employees, stockholders, members, agents, consultants, advisors and other representatives against certain retained liabilities (as defined in the PSA) as well as losses resulting from any breach of any representations, warranties and covenants of the Company, regardless of fault, contained in the PSA, and for certain other matters. Fieldwood has also agreed to indemnify us, our Affiliates (as defined in the PSA) and our respective directors, managers, general partners, officers, agents, employees, consultants, equity owners, stockholders and other representatives against certain losses (excluding certain retained liabilities of Seller) resulting from any breach of any representations, covenants or obligations of Fieldwood contained in the PSA and, subject to certain limitations, the operation and ownership of the assets acquired pursuant to the PSA, regardless of fault, and damages, including environmental damages, relating thereto.

New Swap Transactions. On January 24, 2014, we entered into the following swap transactions:

Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month	NYMEX Strike Price
February 2014 - February 2014	Swap	271,672	4.47
March 2014 - March 2014	Swap	342,217	4.47
April 2014 - April 2014	Swap	287,089	4.47
May 2014 - May 2014	Swap	282,346	4.47
June 2014 - June 2014	Swap	231,998	4.47
July 2014 - July 2014	Swap	245,330	4.47
August 2014 - August 2014	Swap	223,294	4.47
September 2014 - September 2014	Swap	207,094	4.47
October 2014 - October 2014	Swap	202,612	4.47
November 2014 - November 2014	Swap	186,296	4.47
December 2014 - December 2014	Swap	219,770	4.47
January 2015 - January 2015	Swap	203,909	4.47
February 2015 - February 2015	Swap	178,341	4.47
March 2015 - March 2015	Swap	177,093	4.47

New Swap Transactions. On March 20, 2014, we entered into the following swap transactions:

Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month	NYMEX Strike Price
February 2014 - February 2014	Swap	271,672	4.47
March 2014 - March 2014	Swap	342,217	4.47
April 2014 - April 2014	Swap	287,089	4.47
May 2014 - May 2014	Swap	282,346	4.47
June 2014 - June 2014	Swap	231,998	4.47
July 2014 - July 2014	Swap	245,330	4.47
August 2014 - August 2014	Swap	223,294	4.47
September 2014 - September 2014	Swap	207,094	4.47
October 2014 - October 2014	Swap	202,612	4.47
November 2014 - November 2014	Swap	186,296	4.47
December 2014 - December 2014	Swap	219,770	4.47
January 2015 - January 2015	Swap	203,909	4.47
February 2015 - February 2015	Swap	178,341	4.47
March 2015 - March 2015	Swap	177,093	4.47

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Derivative Instruments - Effect of Derivative Instruments on Financial Statements (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]
Realized (loss) gain on derivative financial instruments	$ (1,522)	$ 23,364	$ 8,099
Unrealized (loss) gain on derivative financial instruments	(5,806)	(4,783)	17,556
Derivative gain (loss)	(8,489)	(2,683)
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Unrealized (loss) gain on derivative financial instruments	0	(4,783)	17,556
Gain Loss On Derivative Instruments	(7,328)	18,581	25,655
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Realized Gain (Loss) on Derivative Financial Instruments [Member]
Derivative [Line Items]
Realized (loss) gain on derivative financial instruments	(1,522)	23,364	8,099
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Unrealized Gain (Loss) on Derivative Financial Instruments [Member]
Derivative [Line Items]
Unrealized (loss) gain on derivative financial instruments	$ (5,806)	$ (4,783)	$ 17,556

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Summary of Significant Accounting Policies (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Summary of Significant Accounting Policies (Textual) [Abstract]
Net gas receivable (payable) imbalances	$ 1,200,000	$ 400,000
Allowance for doubtful accounts	811,000	509,000
Depreciation, depletion and amortization expense	41,400,000	46,500,000		46,600,000
Impairment	79,090,000	31,033,000	12,967,000
Depreciation expense of other property and equipment	2,200,000	800,000	600,000
Amortization expense	$ 4,611,000	$ 4,777,000	$ 2,915,000
Texas margin tax	1.00%

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Consolidated Statements of Members' Deficit (USD $) In Thousands, unless otherwise specified	3 Months Ended				12 Months Ended
	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance		$ (118,467)		$ (29,708)	$ (118,467)	$ (29,708)	$ (20,610)
Contribution						110
Distribution					(3,955)	(16,693)	(19,939)
Dividends					(17,336)	(8,208)	(4,200)
Net (loss) income	(41,228)	(16,212)	(47,256)	(5,654)	(32,917)	(63,968)	15,041
Ending Balance	(172,675)		(118,467)		(172,675)	(118,467)	(29,708)
Accumulated Deficit
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance		(80,336)		(8,160)	(80,336)	(8,160)	(19,001)
Distribution					(3,955)
Dividends					(17,336)	(8,208)	(4,200)
Net (loss) income					(32,917)	(63,968)	15,041
Ending Balance	(134,544)		(80,336)		(134,544)	(80,336)	(8,160)
Members’ Capital
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance		(38,131)		(21,548)	(38,131)	(21,548)	(1,609)
Contribution					0	110
Distribution					0	(16,693)	(19,939)
Ending Balance	$ (38,131)		$ (38,131)		$ (38,131)	$ (38,131)	$ (21,548)

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Divestitures

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

DIVESTITURES

DIVESTITURES

Divestitures

On March 26, 2013, we completed the sale of four fields to Renaissance for approximately $52.5 million prior to normal adjustments. Funds were used to reduce the amount borrowed under the Credit Facility by $36 million for Capex. We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million and an additional sale was made on November 15, 2013 for SP65 to Renaissance for $60.0 million prior to normal adjustments. Funds were used to repay a portion of the Credit Facility and to fund capital expenditures.

On December 20, 2013, we completed the sale of one field to Energy XXI GOM, LLC for approximately $10 million prior to normal adjustments. Funds were used to repay a portion of the Credit Facility and to fund 2013 capital expenditures.

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Related Party Transactions (Details Textual) (USD $)	0 Months Ended	12 Months Ended			7 Months Ended
	Aug. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Pea And Eigh [Member]	Sep. 30, 2013 Pea And Eigh [Member]	May 28, 2013 Pea And Eigh [Member]	Dec. 31, 2013 Freedom Logistics LLC [Member]	Aug. 01, 2012 Freedom Logistics LLC [Member] helicopters	Oct. 08, 2010 Freedom Logistics LLC [Member]
Related Party Transaction [Line Items]
Receivables from Black Elk Energy, LLC		$ 273,430	$ 23,430
Payment for Related Party Loan Purchase Agreement Fee	300,000
Capital lease monthly installment							35,000
Equipment purchase option under capital lease							1,500,000
Interest expense under capital lease		1,700,000	1,500,000	1,000,000	200,000
Restricted cash						600,000
Trade payables due to related parties			0		600,000
Number of helicopters as per purchase agreement									2
Guarantee of Freedom Logistics loan								0		3,200,000
Receivable from Freedom Logistics								$ 300,000

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Subsequent Events (Details) (Subsequent Event [Member], Natural Gas Derivative Contract [Member])	0 Months Ended
	Jan. 24, 2014 February 2014 - February 2014 MMBtu	Jan. 24, 2014 March 2014 - March 2014 MMBtu	Jan. 24, 2014 April 2014 - April 2014 MMBtu	Jan. 24, 2014 May 2014 - May 2014 MMBtu	Jan. 24, 2014 June 2014 - June 2014 MMBtu	Jan. 24, 2014 July 2014 - July 2014 MMBtu	Jan. 24, 2014 August 2014 - August 2014 MMBtu	Jan. 24, 2014 September 2014 - September 2014 MMBtu	Jan. 24, 2014 October 2014 - October 2014 MMBtu	Jan. 24, 2014 November 2014 - November 2014 MMBtu	Jan. 24, 2014 December 2014 - December 2014 MMBtu	Jan. 24, 2014 January 2015 - January 2015 MMBtu	Jan. 24, 2014 February 2015 - February 2015 MMBtu	Jan. 24, 2014 March 2015 - March 2015 MMBtu	Mar. 20, 2014 February 2014 - February 2014 MMBtu	Mar. 20, 2014 March 2014 - March 2014 MMBtu	Mar. 20, 2014 April 2014 - April 2014 MMBtu	Mar. 20, 2014 May 2014 - May 2014 MMBtu	Mar. 20, 2014 June 2014 - June 2014 MMBtu	Mar. 20, 2014 July 2014 - July 2014 MMBtu	Mar. 20, 2014 August 2014 - August 2014 MMBtu	Mar. 20, 2014 September 2014 - September 2014 MMBtu	Mar. 20, 2014 October 2014 - October 2014 MMBtu	Mar. 20, 2014 November 2014 - November 2014 MMBtu	Mar. 20, 2014 December 2014 - December 2014 MMBtu	Mar. 20, 2014 January 2015 - January 2015 MMBtu	Mar. 20, 2014 February 2015 - February 2015 MMBtu	Mar. 20, 2014 March 2015 - March 2015 MMBtu
Swap transactions
Contract type	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap	Swap
NYMEX Strike price	4.47	4.47	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470	4.470
Volume (Bbls & MMBtu)	271,672	342,217	287,089	282,346	231,998	245,330	223,294	207,094	202,612	186,296	219,770	203,909	178,341	177,093	271,672	342,217	287,089	282,346	231,998	245,330	223,294	207,094	202,612	186,296	219,770	203,909	178,341	177,093

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Reclassifications

Reclassifications: Certain reclassifications have been made to conform 2011 and 2012 balances to our 2013 presentation. Such reclassifications had no effect on net income or cash flow.

Principles of Consolidation

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

Use of Estimates in Preparation of Financial Statements

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

We account for business combinations using the purchase method, in accordance with Accounting Standards Codification 810 from the Financial Accounting Standards Board (“FASB”). We use estimates to record the fair value of assets acquired and liabilities assumed.

Oil and natural gas reserves estimates, which are the basis for unit-of-production depletion and the impairment test, are based on assumptions that have inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

Cash and Cash Equivalents

Cash and Cash Equivalents: We consider all demand deposits, money market accounts and certificates of deposit purchased with an original maturity of three months or less to be cash and cash equivalents.

Revenue Recognition

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

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

We record revenues based on physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create gas imbalances that we recognize as a receivable (payable) when there are not sufficient reserves to make up the gas imbalance. A gas imbalance receivable (payable) can also be a result of imbalances acquired in conjunction with the acquisition of oil and gas properties. At December 31, 2013 and December 31, 2012, our net gas receivable imbalances were $1.2 million and $0.4 million, respectively.

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts: Trade and other receivables are recorded at their outstanding balances adjusted for an allowance for doubtful accounts. The allowance for doubtful accounts is determined by analyzing the payment history and credit worthiness of each debtor. Receivable balances are charged off when they are considered uncollectible by management. Recoveries of receivables previously charged off are recorded as income when received. At December 31, 2013 and December 31, 2012, allowance for doubtful accounts totaled $0.8 million and $0.5 million, respectively.

Oil and Natural Gas Properties

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

Depreciation, depletion and amortization (“DD&A”) of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. DD&A expense related to oil and natural gas properties for the years ended December 31, 2013, 2012 and 2011 was $41.4 million, $46.5 million and $46.6 million, respectively. As more fully described below, proved reserves are estimated annually by our independent petroleum engineer, and are subject to future revisions based on availability of additional information. DD&A is calculated each quarter based upon the latest estimated reserves data available. Asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Upon sale or retirement of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to operations.

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural gas properties by field to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices. For the years ended December 31, 2013, 2012 and 2011, we recorded an impairment charge of approximately $79.1 million, $31.0 million and $13.0 million, respectively.

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

Other Property and Equipment

Other Property and Equipment: Other property and equipment consists principally of furniture, fixtures and equipment and leasehold improvements. Other property and equipment and related accumulated depreciation and amortization are relieved upon retirement or sale and the gain or loss is included in operations. Maintenance and repairs are charged to operations. Renewals and betterments that extend the useful life of property and equipment are capitalized to the appropriate property and equipment accounts. Depreciation of other property and equipment is computed using the straight-line method based on estimated useful lives of the property and equipment. Depreciation expense of other property and equipment for the years ended December 31, 2013, 2012 and 2011 was $2.2 million, $0.8 million and $0.6 million, respectively.

In accordance with authoritative guidance on accounting for the impairment or disposal of long-lived assets, we assess the recoverability of the carrying value of our non-oil and natural gas long-lived assets when events occur that indicate an impairment in value may exist. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If this occurs, an impairment loss is recognized for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset.

Oil and Natural Gas Reserve Quantities

Oil and Natural Gas Reserve Quantities: Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our independent engineering firm prepares a reserve and economic evaluation of all our properties on a well-by-well basis utilizing information provided to it by us and information available from state agencies that collect information reported to it by the operators of our properties. As discussed below, the estimate of our proved reserves as of December 31, 2013 and 2012 have been prepared and presented in accordance with SEC rules and applicable accounting standards. These rules require companies to prepare their reserve estimates using reserve definitions and pricing based on 12-month un-weighted first-day-of-the-month average pricing.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to DD&A and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the report. The accuracy of our reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the quantities of oil, natural gas, and natural gas liquids ultimately recovered.

Debt Issue Costs

Debt Issue Costs: Debt issue costs associated with long-term debt under revolving credit facilities and senior notes are carried at cost, net of amortization using the straight-line method over the term of the applicable long-term debt facility or the term of the notes, which approximates the effective interest method. Amortization expense for the years ended December 31, 2013, 2012 and 2011 amounted to $4.6 million, $4.8 million and $2.9 million, respectively.

Derivative Financial Instruments

Derivative Financial Instruments: We utilize certain derivative contracts to reduce our exposure to fluctuating oil and natural gas prices. The oil and natural gas reference prices of these derivative contracts are based upon futures which have a high degree of correlation with actual prices received by us. We did not designate any of our derivative contracts as qualifying cash flow hedges. Accordingly, all gains and losses from our price risk management activities are currently included in earnings. Open positions are marked-to-market and recorded as unrealized gain (loss) on derivative financial instruments. When settled, the resulting cash flows are reported as cash flows from operating activities.

Asset Retirement Obligations

Asset Retirement Obligations: Accounting guidance for asset retirement obligations requires companies to recognize a liability for the present value of all obligations associated with retirement of tangible long-lived assets and to capitalize an equal amount as part of the cost of the related oil and natural gas properties. We recognize the legal obligation of the dismantlement, restoration and abandonment costs associated with our oil and natural gas properties with our asset retirement obligations. These costs are impacted by our estimated remaining lives of the properties, as well as current market conditions associated with these activities.

Environmental Expenditures

Environmental Expenditures: We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed.

Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component is fixed or reliably determinable.

Income Taxes

Income Taxes: We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes.

We are subject to the Texas margin tax which is generally calculated as 1% of gross margin. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. During the years ended December 31, 2013, 2012 and 2011, the margin tax was immaterial to the consolidated financial statements.

Recent Accounting Pronouncements

Recent Accounting Pronouncements:

Fair Value Measurement

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.

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Unaudited financial information for each quarter

The table below sets forth unaudited financial information for each quarter of the last two years (in thousands):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2013
Total revenues	$	59,988		$	66,374		$	63,757		$	67,889
Loss (income) from operations	(8,972		)	(30,683		)	(8,881		)	44,004
Net (loss) income	(16,212		)	(39,518		)	(18,415		)	(41,228		)
Net (loss) income attributable to common unit holders	(19,355		)	(44,201		)	(23,170		)	(36,418		)
Year ended December 31, 2012
Total revenues	$	76,181		$	106,594		$	57,125		$	64,578
Income (loss) from operations	1,245			28,721			(25,153		)	(39,631		)
Net (loss) income	(5,654		)	21,517			(32,575		)	(47,256		)
Net (loss) income attributable to common unit holders	(7,454		)	19,573			(34,807		)	(49,488		)

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

We pay for certain operating and general and administrative expenses on behalf of Black Elk Energy, LLC, the parent company of Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corp. At December 31, 2013 and 2012, we had receivables from Black Elk Energy, LLC in the amount of $273,430 and $23,430, respectively.

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 12.

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.

On May 28, 2013, our consolidated subsidiary 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 a month to month lease option thereafter. The agreement also includes an option to purchase the equipment for $1.5 million. The lease arrangement is treated as an operating lease and we incurred approximately $0.2 million of rental expense for the year ended December 31, 2013. As of December 31, 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 of $0.6 million, which is included in “Accounts payable and accrued expenses”.

In October 2010, Freedom Logistics LLC (“Freedom”) was formed by Platinum, our majority equity holder, and Freedom HHC Management, LLC, the members of which are Messrs. John Hoffman (our President and Chief Executive Officer) and David Cantu (a member of our management), for the purpose of holding certain aircraft equipment, including two helicopters. On October 8, 2010, we guaranteed the loan that Freedom used to purchase two helicopters in the aggregate principal amount of $3.2 million. On August 1, 2012, Freedom entered into a purchase agreement with Gulf State Aviation, whereby Gulf State Aviation purchased certain aircraft equipment from Freedom, including the two helicopters. The proceeds of the sale were applied to the balance of the guaranteed loan when the sale was finalized in December 2012 and there was no remaining balance due on the loan as of December 31, 2012. 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.