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, 2011

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.    ¨  Yes    x  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

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 30, 2011, 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 15, 2012, there were 136.13 Class A Units, 10,934.585 Class B Units, 1,203.125 Class C Units and 30,000,000 Class D Units issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC’S

ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2011

TABLE OF CONTENTS

	Page
Cautionary Statement Regarding Forward-Looking Statements		ii
PART I
Item 1. Business		1
Item 1A. Risk Factors		13
Item 1B. Unresolved Staff Comments		26
Item 2. Properties		26
Item 3. Legal Proceedings		26
Item 4. Mine Safety Disclosures		26
PART II
Item  5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		27
Item 6. Selected Financial Data		27
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		42
Item 8. Financial Statements and Supplementary Data		46
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		67
Item 9A. Controls and Procedures		67
Item 9B. Other Information		67
PART III
Item 10. Directors, Executive Officers and Corporate Governance		67
Item 11. Executive Compensation		68
Item  12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		73
Item 13. Certain Relationships and Related Transactions and Director Independence		73
Item 14. Principal Accounting Fees and Services		74
PART IV
Item 15. Exhibits, Financial Statement Schedules		75
EXHIBIT INDEX

i

CAUTIONARY STATEMENT 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, 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 result 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.

ii

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 obligation to update, revise or release any revisions to any forward-looking statement 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.

iii

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, 2011, our leasehold position encompassed approximately 293,400 net (654,500 gross) acres, 1,182 net (1,222 gross) wells and 241 production platforms. As of December 31, 2011, we had estimated total proved oil, natural gas and NGL reserves of 45.2 MMBoe (40% oil) with a PV-10 value of $1,061 million based on the reserve report as of December 31, 2011 (“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, 2011. For 2011, our net daily production averaged approximately 14,559 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 71,000 net (195,000 gross) 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. As of December 31, 2011, the W&T Properties had a PV-10 value, of $248.7 million and estimated proved reserves of 9.6 MMBoe, which accounted for approximately 23% of our total PV-10 value and approximately 21% 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 5,500 net (13,300 gross) 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 64,400 net (157,200 gross) 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, 2011, the Nippon Properties had a PV-10 value of $227.8 million and estimated proved reserves of 11.4 MMBoe, which accounted for approximately 21% of our total PV-10 value and approximately 25% 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 43 net (105 gross) wells and approximately 22,200 net (45,500 gross) acres.

On May 31, 2011, we acquired certain interests in various properties across approximately 127,800 net (236,200 gross) acres (the “Merit Properties”) in the Gulf of Mexico in Texas and federal waters from certain private sellers (the “Merit Entities”). In 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, 2011, the Merit Properties had a PV-10 value of $333.0 million and estimated proved reserves of 16.9 MMBoe, which accounted for approximately 31% 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 unitholder 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:

• 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.

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• 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.

• 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.

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.

• Efficient management of our P&A activities. We consider the evaluation and execution of 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.

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, 2011, 2010 and 2009. 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.

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	At December 31,
	2011			2010			2009
Reserve Data (1):
Estimated net proved reserves:
Oil (MBbls)		18,089			10,257			3,268
Natural gas (MMcf)		150,393			68,598			20,114
NGL (MBbls)		2,034			—			—
Total estimated net proved reserves (MBoe)		45,189			21,690			6,620
Estimated net proved developed reserves:
Oil (MBbls)		10,538			7,897			2,266
Natural gas (MMcf)		83,324			55,008			15,852
NGL (MBbls)		1,291			—			—
Total estimated net proved developed reserves (MBoe)		25,716			17,065			4,908
Percent developed		57	%		79	%		74	%
Estimated net proved undeveloped reserves:
Oil (MBbls)		7,551			2,360			1,002
Natural gas (MMcf)		67,069			13,590			4,262
NGL (MBbls)		743			—			—
Total estimated net proved undeveloped reserves (MBoe)		19,472			4,625			1,712
PV-10 (in thousands) (2)	$	1,061,408		$	392,189		$	43,186
Standardized measure (in thousands) (2)		1,061,408			392,189			43,186

(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 $92.71 per Bbl for oil volumes and $4.12 per Mcf for gas volumes for the year ended December 31, 2011. The unweighted arithmetic average first-day-of-the-month prices of oil for the 12 months ended December 31, 2010 and 2009 were $75.96 per Bbl and $57.65 per Bbl, respectively. Gas prices for the years ended December 31, 2010 and 2009 were based on average adjusted product prices weighted by production for the proved reserves. The range of gas prices for 2010 was $4.24 to $4.38 per Mcf while the range was $3.62 to $3.90 per Mcf for 2009. 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 local 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 $103.99 per Bbl of oil, $4.338 per Mcf of gas and $53.28 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.

The following table sets forth the estimated future net cash flows, excluding derivatives contracts, from estimated proved reserves, PV-10 values and the expected benchmark prices used in projecting net cash flows at December 31, 2011, 2010 and 2009 (in thousands, except for the per Bbl and Mcf data).

	At December 31,
	2011		2010		2009
Estimated future net cash flows	$	1,383,192	$	495,211	$	58,178
Present value of future net revenues (1):
PV-10	$	1,061,408	$	392,189	$	43,186
Standardized measure		1,061,408		392,189		43,186
Benchmark oil price ($/Bbl)		92.71		75.96		57.65

(1) The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $4.12/Mcf for gas volumes for the year ended December 31, 2011. Gas prices for the years ended December 31, 2010 and 2009 were based on average adjusted product prices weighted by production for the proved reserves. The range of gas prices for 2010 was $4.24 to $4.38 per Mcf while the range was $3.62 to $3.90 per Mcf for 2009.

Estimated future net cash flows represent projected revenues for the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations are based on a 12 month unweighted arithmetic average of the first-day-of-the-month price for the period January through December of such year, without giving effect to derivative transactions, and are held constant throughout the life of the properties. 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.

Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. A revision of 2,225 MBoe during 2009 was mainly due to comprehensive field studies, reactivation of inactive wells and improved performance of active wells, a revision of 3,678 MBoe during 2010 was mainly due to comprehensive field studies, reactivation program and improved performance of active wells, and a revision of 1,770 MBoe during 2011 was primarily due to continued field studies, reactivation of inactive wells and improved performance of active wells.

3

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, 3-D seismic data and well test data.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process. 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, 2011, 2010 and 2009 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.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. During the fourth quarter of each fiscal year, our technical team meets regularly with representatives of NSAI to review properties and discuss methods and assumptions used in NSAI’s preparation of the year end reserves estimates. All field and reserve technical information, which is updated annually, is assessed for validity when NSAI holds technical meetings with our internal staff of petroleum engineers, operations and land personnel to discuss field performance and to validate future development plans. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of the NSAI reserve reports are reviewed with representatives of NSAI and our internal technical staff before dissemination of the information.

Our Chief Technical Officer, Mr. Arthur Garza, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. He has a B.S./M.E. in Petroleum Engineering from Texas A&M University and a M.B.A. from University of Oklahoma. Mr. Garza has over 23 years of industry experience with positions of increasing responsibility. His focus has been on the exploitation of mature oil and natural gas fields, and he also has extensive waterflood and polymer flood experience. Reserves estimates are reviewed and approved by our engineering staff with final approval by our Chief Technical Officer.

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, 2011 were 19.5 MMBoe, consisting of 8.3 MBbls of oil and NGLs and 67.1 Bcf of natural gas. Increases in proved undeveloped reserves in the past year are primarily due to continued evaluation of our existing asset base and the Merit Acquisition. In 2011, we did not drill and complete a proved undeveloped well but we expect to complete one in the first quarter of 2012. Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2011, as shown in the NSAI Report, are $285.0 million, of which 2012 and 2013 expenditures are estimated to be $49.9 million and $76.9 million, respectively. All proved undeveloped reserves are scheduled to be drilled by 2017. We are unsure what effect, if any, the moratorium issued by the federal Bureau of Ocean Energy, Management, Regulation and Enforcement (“BOEMRE”) between May and October of 2010 with respect to the drilling of wells using subsea blowout preventers (“BOPs”) or surface BOPs on a floating facility will have on our estimated proved reserves at December 31, 2011. We are also unsure what effect, if any, future amendments to the Oil Pollution Act of 1990 (“OPA”) will have on our offshore operations.

Developed and Undeveloped Acreage

The following table presents the total gross and net developed and undeveloped acreage by region as of December 31, 2011:

		654,496		654,496		654,496		654,496		654,496		654,496
	Developed Acres				Undeveloped Acres				Total
	Gross		Net		Gross		Net		Gross		Net
Offshore (1)		648,776		290,533		5,720		2,860		654,496		293,393
Total		648,776		290,533		5,720		2,860		654,496		293,393

(1) Our core areas of production in U.S. federal waters in the Gulf of Mexico are the South Pass 65, South Timbalier 317, Ship Shoal 176, Vermilion 408, South Pass 86/89, High Island A-571 and South Marsh Island 39 fields.

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2011 that will expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the applicable lease expiration dates:

		654,496 00		654,496 00		654,496 00		654,496 00		654,496 00		654,496 00
	2012				2013				2014
	Gross		Net		Gross		Net		Gross		Net
Offshore (1)		5,720		2,860		—		—		—		—
Total		5,720		2,860		—		—		—		—

(1) Our core areas of production in U.S. federal waters in the Gulf of Mexico are the South Pass 65, South Timbalier 317, Ship Shoal 176, Vermilion 408, South Pass 86/89, High Island A-571 and South Marsh Island 39 fields.

Drilling Activity

During the three years ended December 31, 2011, 2010 and 2009, 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.

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		0.28		0.28		0.28		0.28		0.28		0.28
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Development wells:
Productive oil		—		—		1		0.21		1		0.28
Productive natural gas		—		—		2		0.75		—		—
Dry		—		—		—		—		—		—
Total		—		—		3		0.96		1		0.28

		0.28		0.28		0.28		0.28		0.28		0.28
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells:
Productive oil		—		—		—		—		—		—
Productive natural gas		—		—		—		—		—		—
Dry		1		0.10		—		—		—		—
Total		1		0.10		—		—		—		—

At December 31, 2011, we did not have any wells where we serve as the operator that were in the process of drilling, completing or waiting on completion. We also recompleted 26 wells during 2011, 21 of which are currently producing. As of December 31, 2011, we were not operating any rigs on our properties. In 2012 to date, we have drilled one non-operated development well. Our rig activity during the remainder of 2012 will be dependent on oil and natural gas prices and, accordingly, our rig count may increase or decrease from year-end levels. There can be no assurance, however, that additional rigs will be available to us at an attractive cost.

Capital Expenditure Budget

We have a total capital expenditure budget of $49.9 million for 2012, excluding expenditures directly related to acquisitions, which is a 135% increase over the approximately $21.2 million of capital expenditures (excluding acquisitions) invested during 2011. Our 2012 capital expenditure budget will be used for various projects including recompletions, development and drilling. The NSAI Report included an assumption that we will spend $70.0 million in capital expenditures during 2012. The NSAI Report included the estimated non-operated capital expenditures which are not reflected in our 2012 capital expenditure budget amount above. To date, our 2012 capital budget has been funded from borrowings under our lines of credit and cash flows from operations. We believe the borrowings under our credit facility, together with cash flows from operations, should be sufficient to fund our 2012 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. Additionally, the indenture (together with the amendments and supplements thereto, the “Indenture”) governing our Notes restricts the amount of capital expenditures that we may make each year to 30% of Consolidated EBITDAX (as defined in the Indenture) for 2012 and each subsequent year. In addition, aggregate capital expenditures may not exceed $210.0 million.

Our Significant Oil and Natural Gas Properties

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 7,001 feet. As of December 31, 2011, our leasehold position encompassed approximately 293,000 net (653,800 gross) acres, 1,182 net (1,222 gross) wells and 241 production platforms. As of December 31, 2011, we operated approximately 44% of the fields and 48% of the wells in our asset portfolio.

The following describes our significant properties and interests as of December 31, 2011, which at such time accounted for approximately 45% of our total PV-10 value based on the NSAI Report, and approximately 32% of our total proved reserves, totaling 14.6 MMBoe.

• South Pass 65. We acquired the South Pass 65 field, which is located in approximately 300 feet of water in U.S. federal waters, in the Nippon Acquisition. We have a 50% net working interest in this field and Apache Corporation serves as the operator. This field currently contains 37 producing wells and, as of December 31, 2011, had estimated total proved oil and natural gas reserves of 2.1 MMBoe.

• South Timbalier 317. We acquired the South Timbalier 317 field, which is located in approximately 457 feet of water in U.S. federal waters, in the Merit Acquisition. We have a 100% net working interest in this field and serve as the operator. This field currently contains two producing wells and, as of December 31, 2011, had estimated total proved oil and natural gas reserves of 2.1 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 100% net working interest in this field and serve as the operator. This field currently contains thirteen producing wells and, as of December 31, 2011, had estimated total proved oil and natural gas reserves of 2.7 MMBoe.

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• Vermilion 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 working interest in this field and serve as the operator. This field currently contains five producing wells and, as of December 31, 2011, had estimated total proved oil and natural gas reserves of 1.5 MMBoe.

• South Pass 86/89. We acquired the South Pass 86/89 field, which is located in approximately 388 feet of water in U.S. federal waters, in the W&T Acquisition. We have a 75% net working interest in this field and are the operator of record. This field currently contains no producing wells and, as of December 31, 2011, had estimated total proved oil and natural gas reserves of 2.3 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 79% net working interest in this field and are the operator of record. This field currently contains three producing wells and, as of December 31, 2011, had estimated total proved oil and natural gas reserves of 2.6 MMBoe.

• South Marsh Island 39. We acquired the South Marsh Island 39 field, which is located in approximately 97 feet of water in U.S. federal waters, in the W&T Acquisition. We have a 50% net working interest in this field and Hunt Oil serves as the operator. This field currently contains three producing wells and, as of December 31, 2011, had estimated total proved oil and natural gas reserves of 1.4 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 2011. 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, 2011, 2010 and 2009. 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.” We do not have any fields that contain 15% or more of our total estimated proved reserves.

	Year Ended
	December 31,
	2011		2010		2009
Net sales volumes:
Oil (MBbl)		1,991		857		140
Natural gas (MMcf)		18,188		7,997		2,444
Plant products (MGal)		12,257		5,403		320
Oil equivalents (MBoe)		5,314		2,319		555
Average sales price per unit: (1)
Oil (Bbl)	$	105.17	$	80.97	$	71.59
Natural gas (Mcf)	$	4.94	$	5.44	$	4.55
Oil equivalents (Boe)	$	59.30	$	51.27	$	38.88
Costs and expenses per Boe:
Lease operating expenses	$	29.83	$	23.56	$	15.55
Depreciation, depletion, amortization, and impairment	$	11.32	$	15.61	$	28.57
General and administrative expenses	$	4.15	$	6.29	$	12.90

(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.

Net production volumes for the year ended December 31, 2011 were 5,314 MBoe, a 129% increase from net production of 2,319 MBoe for 2010. Our net production volumes increased 2,995 MBoe over 2010 net production volumes mainly due to a full year of production of the properties acquired in the Nippon Acquisition and eight months production of the properties acquired in the Merit Acquisition as well as ten months production of the properties acquired in the Maritech Acquisition. Our average oil sales prices, without the effect of realized derivatives, increased $28.00 per Bbl to $108.09 per Bbl for the year ended December 31, 2011 from $80.09 per Bbl for the year ended December 31, 2010. Giving effect to our derivative transactions in both periods, our oil prices increased $24.20 per Bbl to $105.17 per Bbl for the year ended December 31, 2011 from $80.97 per Bbl for the year ended December 31, 2010. Our lease operating expenses increased $6.27 per Boe, or 27%, to $29.83 per Boe for the year ended December 31, 2011 from $23.56 per Boe for the year ended December 31, 2010 mainly due to new offshore production.

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Net production volumes for the year ended December 31, 2010 were 2,319 MBoe, a 318% increase from net production of 555 MBoe for 2009. Our net production volumes increased 1,764 MBoe over 2009 net production volumes mainly due to a full year of production of the properties acquired in the W&T Acquisition and three months production of the properties acquired in the Nippon Acquisition. Our average oil sales prices, without the effect of realized derivatives, increased $9.66 per Bbl to $80.09 per Bbl for the year ended December 31, 2010 from $70.43 per Bbl for the year ended December 31, 2009. Giving effect to our derivative transactions in both periods, our oil prices increased $9.38 per Bbl to $80.97 per Bbl for the year ended December 31, 2010 from $71.59 per Bbl for the year ended December 31, 2009. Our lease operating expenses increased $8.01 per Boe, or 52%, to $23.56 per Boe for the year ended December 31, 2010 from $15.55 per Boe for the year ended December 31, 2009 mainly due to new offshore production.

The following table sets forth information regarding our average net daily production for the years ended December 31, 2011 and 2010:

	Average Net Daily Production for the Year Ended December 31, 2011						Average Net Daily Production for the Year Ended December 31, 2010
	Bbls		Mcf		Boe		Bbls		Mcf		Boe
Offshore (1)		6,254		49,831		14,559		2,700		21,911		6,353

(1) Our core areas of production in U.S. federal waters in the Gulf of Mexico are the South Pass 65, South Timbalier 317, Ship Shoal 176, Vermilion 408, South Pass 86/89, High Island A-571 and South Marsh Island 39 fields.

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, 2011:

Oil Wells

Natural Gas Wells

Total Wells

Gross

Net

Gross

Net

Gross

Net

Offshore (1)

175

53

134

64

309

117

(1) Our core areas of production in the U.S. federal waters in the Gulf of Mexico are the South Pass 65, South Timbalier 317, Ship Shoal 176, Vermilion 408, South Pass 86/89, High Island A-571 and South Marsh Island 39 fields.

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.

We have been selling to our customers set forth below since our inception (January 29, 2008) 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,
Customer	2011			2010			2009
Conoco Phillips Company		7	%		14	%		18	%
Shell Trading (US) Company		51	%		52	%		46	%
Katrina Energy, LLC		0	%		0	%		28	%

Delivery Commitments

Substantially all of our production is sold pursuant to month-to-month marketing contracts that are terminable 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 “Risk Factors.”

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

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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 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.

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

In addition, 11 states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

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 or Indian oil 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 BOEMRE or other appropriate federal or state agencies.

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Transportation 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. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index ceiling slightly, effective July 2001. Following the FERC’s five-year review of the indexing methodology, the FERC issued an order in 2006 increasing the index ceiling.

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. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, 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

Historically, the transportation and sale for resale of natural gas in interstate commerce has been 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. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. 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.

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. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. 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.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

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.

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. However, with regard to our physical sales of these 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 below the discussion 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. In order to provide respondents time to implement new regulations related to Order No. 704, the FERC has extended the deadline for calendar year 2009 until September 30, 2010. The report for calendar year 2010 and subsequent years remains May 1 of the following calendar year. Currently, Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”

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.

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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. 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 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 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 new 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 beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. In order to provide respondents time to implement new regulations related to Order No. 704, the FERC has extended the deadline for calendar year 2009 until September 30, 2010. The report for calendar year 2010 and subsequent years remains May 1 of the following 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.

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 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 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

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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 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 Department of Interior, 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.

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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 several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, on July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production activities. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by April 3, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

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, 2011, 2010 and 2009. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2012 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, 2011, we had 122 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. From time to time, we utilize the services of independent contractors to perform various field and other services.

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.

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.

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Item 1A. Risk Factors

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

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 are inherently risky. 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 affect 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.

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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.

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, 2011, our estimated total asset retirement obligations, which relate to our P&A obligations, were $288.7 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;

• domestic and foreign governmental regulations;

• level of global oil and natural gas inventories;

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• 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 or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs 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 oil and gas properties. For the years ended December 31, 2011 and 2010, we recorded impairments of $13.0 million and $6.4 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.

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As of December 31, 2011, approximately 43% 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, 2011, approximately 43% of our total estimated proved reserves were classified as proved undeveloped. The future development of these undeveloped reserves into proved developed reserves is highly dependent upon our ability to fund estimated total capital development costs, as shown in the NSAI Report, of approximately $285.0 million, of which $49.9 million and $76.9 million are expected to be incurred in 2012 and 2013, respectively. We cannot be sure that these estimated costs are accurate. 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 five 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 “—British Petroleum 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;

• 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, 2011 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 and 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.

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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 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, 2011, we operated approximately 44% of the fields and 48% 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:

• 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 three years, there has been a

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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.

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 3-D seismic data;

• our ability to obtain leases or options on properties for which we have 3-D 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.

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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, 2011, Shell Trading (US) Company was our largest purchaser of oil and natural gas, accounting for approximately 52% of our revenues, with JP Morgan Ventures Energy Corporation as the next largest purchaser, accounting for approximately 8% 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, and James Hagemeier, our Vice President and Chief Financial 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 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

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

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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.

Risks Related to Our Indebtedness and Access to Capital and Financing

Our level of indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities.

As of December 31, 2011, we had an aggregate amount of $136.4 million of indebtedness outstanding under our credit facility, $112.4 million of which was drawn as letters of credit in support of our P&A obligations and $24.0 million under our revolver, and a borrowing base of $58.6 million available for additional borrowings, including $46.0 million under the revolver. We also have substantial P&A obligations and the 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”). As of December 31, 2011, our estimated total asset retirement obligations, which relate to our P&A obligations, were $288.7 million.

Additionally, we are required to make monthly contributions to the W&T Escrow Accounts, which were established to secure our P&A obligations with respect to the W&T Acquisition in October 2009, according to stipulated payment schedules for a maximum aggregate principal amount of $63.8 million. We used $20 million of the net proceeds from the November 2010 notes offering to prefund the W&T Escrow Accounts and, accordingly, one of the escrow accounts, which we refer to as the “Operated Properties Escrow Account,” is now fully funded and we have no further obligation to fund this account. However, the other escrow account, which we refer to as 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 was suspended until December 1, 2011, on which date we made an initial payment of $0.2 million to the Non-Operated Properties Escrow Account, to be followed by required payments of $0.3 million per month. Pursuant to the payment schedule, this escrow account will be fully funded by the end of 2017. Until both of the 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 properties acquired as part of the W&T Acquisition (1) from the Operated Properties Escrow Account without the consent of W&T or (2) from the Non-Operated Properties Escrow Account. W&T holds a first priority lien on the W&T Escrow Accounts, and the administrative agent under our credit facility holds a second lien for the benefit of the lenders under such facility and our derivatives counterparty.

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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, the principal amount of $13.1 million for future P&A costs that may be incurred on such properties. As of December 31, 2011, we have funded $3.6 million, leaving $9.5 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 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 June 1, 2011. As of December 31, 2011, we have funded $14.0 million, leaving $46.0 million to be funded through November 2013.

Our substantial indebtedness and other obligations could have important consequences to you. 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 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.

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 indentures governing our Notes and our credit facility do not fully prohibit us or our subsidiaries from doing so. At December 31, 2011, we and our subsidiaries collectively had approximately:

• $172.9 million of secured indebtedness, net of unamortized discounts; and

• $4.1 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.

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:

If we are unable to generate sufficient cash flow to service our debt, 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.

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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.

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:

• 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. A default, if not waived, would entitle certain of our debt holders 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.

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 through borrowings under our credit facility. 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 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.

We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our revolving credit facility because of the deterioration of the capital and credit markets and our borrowing base.

The recent credit crisis and related turmoil in the global financial systems 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 revolving credit facility to fund our capital expenditures and have relied on the capital markets to provide us with additional capital for large or exceptional transactions.

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In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (1) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (2) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Declines in commodity prices, or a continuing decline in those prices, could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. Further, the recent credit crisis 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.

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 U.S. Department of the Interior regulations and BOEMRE, Bureau of Ocean Energy Management (“BOEM”) or Bureau of Safety and Environmental Enforcement (“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.”

British Petroleum PLC’s (“BP”) 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.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in ultra deep water in the U.S. Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the U.S. Gulf of Mexico. In response to the explosion and spill, there have been many proposals by government and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. Beginning in May 2010, the U.S. Department of the Interior, initially through its federal Mineral Management Services (“MMS”) and subsequently through the BOEMRE (when the MMS was renamed BOEMRE in June 2010) implemented a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that effectively shut down deepwater drilling activities until the moratorium was lifted by Secretary of the Interior Ken Salazar in October 2010. While the moratorium was in place, the BOEMRE began issuing a series of NTLs imposing a variety of new safety and permitting requirements applicable to exploration, development and production activities in the U.S. Gulf of Mexico. For example, before being allowed to resume drilling in deepwater, operators in the Outer Continental Shelf must certify compliance with all applicable operating regulations found in 30 C.F.R. Part 250, such as rules relating to well casing and cementing, BOPs, safety certification, emergency response and worker training. Operators must also demonstrate the availability of adequate spill response and blowout containment resources. Although the drilling moratorium was lifted, this spill and its aftermath have led to delays in obtaining drilling permits that we believe will continue. While legislation has been introduced in the U.S. Congress to expedite the process for offshore permits including limitations on the timeframes for environmental and judicial review, there is no assurance that this or similar legislation will be adopted into law.

Effective October 1, 2011, BOEMRE was split into two federal bureaus, (1) the BOEM, which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies, and (2) the BSEE, which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, we are required to interact with two newly formed federal bureaus to obtain approval of our exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays as the functions of the former BOEMRE are fully divested from the former agency and implemented in the two federal bureaus.

In addition to the drilling restrictions and new safety and permitting measures already issued by the BOEMRE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the U.S. Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the U.S. Gulf of Mexico more difficult, more time consuming and more costly. For example, during the previous session of Congress, a variety of amendments to the OPA were proposed in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the Outer Continental Shelf, which includes the U.S. Gulf of Mexico where we have substantial offshore operations. OPA subjects lessees and operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising

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from a spill, including, but not limited to, 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. Legislation was proposed in the previous session of Congress to amend OPA to increase the minimum level of financial responsibility to $300 million or more and there exists the possibility that similar legislation could be introduced and adopted during the current or some future session of Congress. If OPA is 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 OCS 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. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased.

Regulatory requirements and permitting procedures imposed by the BOEMRE, BOEM or BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

Subsequent to the BP Deepwater Horizon incident in the U.S. Gulf of Mexico, the BOEMRE issued a series of NTLs and other regulatory requirements imposing new standards and permitting procedures for new wells to be drilled in federal waters of the OCS. These regulatory requirements include the following:

• The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.

• The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.

• The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.

• The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system (“SEMS”) in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills. On September 14, 2011, the BOEMRE issued proposed rules that would amend the Workplace Safety Rule by requiring the imposition of certain added safety procedures to a company’s SEMS not covered by the original rule and revising existing obligations that a company’s SEMS be audited by requiring the use of an independent third party auditor who has been pre-approved by the agency to perform the auditing task.

As a result of the issuance of these regulatory requirements, the BOEMRE has been taking much longer than in the past to review and approve permits for new wells. Moreover, as the new standards and procedures are being integrated into the existing framework of offshore regulatory programs of the BOEM and BSEE after October 1, 2011, we anticipate that there may be permitting delays in performing well workovers and recompletions in addition to plugging and abandonment activities. These new requirements and any associated permitting delays increase the costs of preparing permit applications and will increase the costs of new wells, well workovers and well recompletions, particularly for wells drilled in deeper waters on the OCS.

We are unsure what long-term effect, if any, the BOEMRE’s, BOEM’s or BSEE’s additional regulatory requirements and permitting procedures will have on our offshore operations. Accordingly, we may be subject to a variety of unforeseen adverse consequences arising directly or indirectly from the BP Deepwater Horizon incident.

The recent adoption of derivatives legislation by Congress 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.

In 2010, Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was signed into law by President Obama on July 21, 2010 and requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief for certain regulations applicable to swaps, until no later than July 16, 2012. The CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral that could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Finally, the legislation 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 legislation 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

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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 80% 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, 2011, Platinum beneficially owned approximately 80% of our outstanding voting membership interests and approximately 72% 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The information required by this Item 2. is contained in “Item 1. Business.”

Item 3. Legal Proceedings

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

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.”

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

Item 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, 2011, 2010 and 2009 and for the period from inception (January 29, 2008) through December 31, 2008, and balance sheet data at December 31, 2011, 2010, 2009 and 2008. 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.

	Year Ended December 31,									Period from Inception (January 29, 2008) through December 31,
	2011			2010			2009			2008
STATEMENTS OF OPERATIONS DATA (in thousands):
Crude oil, natural gas and plant product sales	$	314,289		$	112,566		$	20,788		$	13,024
Realized gain on derivative financial instruments		8,099			9,271			801			—
Unrealized (loss) gain on derivative financial instruments		17,556			(12,700	)		(2,756	)		—
Total revenue		339,944			109,137			18,833			13,024
Operating Expenses:
Lease operating costs, workovers and production taxes		182,789			59,555			10,043			9,995
Exploration		1,004			14			47			79
Depreciation, depletion and amortization		47,214			29,795			15,419			3,316
Impairment		12,967			6,407			446			—
General and administrative		22,029			14,588			7,164			3,377
Gain due to involuntary conversion of asset		—			—			(18,718	)		(9,526	)
Accretion		27,410			9,175			388			422
Gain on sale of asset		(142	)		—			—			—
Total operating expenses		293,271			119,534			14,789			7,663
Income (loss) from operations	$	46,673		$	(10,397	)	$	4,044		$	5,361
Operating Data:
Oil (MBbl) (1)		1,991			857			140			36
Natural gas (MMcf) (1)		18,188			7,997			2,444			1,068
Plant products (MGal) (1)		12,257			5,403			320			—
Oil:
Average price before effects of hedges ($/Bbl)	$	108.09		$	80.09		$	70.43		$	99.51
Average price after effects of hedges ($/Bbl)		105.17			80.97			71.59			99.51
Average price differentials		13.04			0.59			8.44			(0.41	)
Natural Gas:
Average price before effects of hedges ($/Mcf)	$	4.18		$	4.38		$	4.29		$	8.87
Average price after effects of hedges ($/Mcf)		4.94			5.44			4.55			8.87
Average price differentials		0.18			—			0.34			(0.02	)

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

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	As of December 31,
	2011			2010			2009			2008
BALANCE SHEET DATA (in thousands):
Cash and cash equivalents	$	17,260		$	18,879		$	6,236		$	1,647
Oil and natural gas properties, net		238,702			123,783			88,600			8,148
Total assets		546,006			306,504			114,009			26,806
Total debt, including current portion		177,041			150,753			40,133			6,851
Asset retirement obligations (net of escrow)		96,185	(1)		8,074			45,431			(4,846	)
Members’ equity (deficit)		292			(20,610	)		5,723			4,919
	Year Ended December 31,									Period from Inception (January 29, 2008) through December 31,
	2011			2010			2009			2008
OTHER FINANCIAL DATA (in thousands):
Net cash provided by (used in) operating activities	$	73,647		$	28,345		$	(528	)	$	1,479
Net cash used in investing activities		(108,641	)		(114,815	)		(27,415	)		(5,814	)
Net cash provided by (used in) financing activities		33,375			99,113			32,532			5,982
Adjusted EBITDA (2)		110,686			47,052			4,617			(405	)

(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.

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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 filing. 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 Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are an oil and gas company engaged in the acquisition, exploitation, development and production of oil and natural gas properties. We seek to acquire and exploit properties with proved developed reserves, proved developed non-producing reserves and proved undeveloped reserves. Our strategy is to acquire and economically maximize properties that are currently producing or have the potential to produce given additional attention and capital resources. We are engaged in a continual effort to monitor and reduce operating expenses by finding opportunities to safely increase efficiencies related to staffing, transportation and operational procedures. Moreover, our ability to accurately estimate and manage plugging and abandonment costs associated with potential acquisitions increases the likelihood of achieving our target returns on investment. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation. As of December 31, 2011, we held an aggregate net interest in approximately 293,400 net (654,500 gross) acres under lease and had an interest in 1,222 gross wells, 309 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 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 a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. In addition, our willingness to acquire non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.

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

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

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

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

In 2010, we completed two acquisitions which increased the geographic diversity of our portfolio. During the first quarter of 2010, we acquired properties in the Gulf of Mexico, primarily located within Texas state waters from Chroma Oil & Gas, LP. This acquisition consisted of six fields and interests in an additional 40 wells and approximately 5,500 net (13,300 gross) acres. On September 30, 2010, we acquired 27 properties across approximately 64,400 net (157,200 gross) acres in the Gulf of Mexico from Nippon Oil Exploration U.S.A. The Nippon Acquisition included 90 producing wells, 223 wellbores, 41 platforms, and 19 producing fields.

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

On May 31, 2011, we completed our purchase of certain properties from the Merit Entities. We acquired interests in various properties across approximately 127,800 net (236,200 gross) acres in the Gulf of Mexico. In connection with the Merit Acquisition, we entered into a contribution agreement with Platinum, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million of our Class D Units.

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

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From time to time, we use derivative financial instruments to economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. Our average prices that reflect both the before and after effects of our realized commodity hedging transactions for the three years ended December 31, 2011, 2010 and 2009 are shown in the table below.

	Year Ended December 31,
	2011		2010		2009
Oil:
Average price before effects of hedges ($/Bbl) (1)	$	108.09	$	80.09	$	70.43
Average price after effects of hedges ($/Bbl)		105.17		80.97		71.59
Average price differentials (2)		13.04		0.59		8.44
Gas:
Average price before effects of hedges ($/Mcf) (1)	$	4.18	$	4.38	$	4.29
Average price after effects of hedges ($/Mcf)		4.94		5.44		4.55
Average price differentials (2)		0.18		0.00		0.34

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

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

The United States and other world economies suffered a severe recession lasting well into 2011 and economic conditions continue to remain uncertain. These uncertain economic conditions reduced demand for oil and natural gas, resulting in a decline in natural gas prices received for our production in 2011 and 2010. While oil prices have strengthened over the past year, both oil and natural gas prices remain unstable and we expect them to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

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

Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium

In April 2010, the Deepwater Horizon, a drilling platform operated by British Petroleum PLC in ultra deepwater in the U.S. Gulf of Mexico, sank after an apparent blowout and fire. The resulting leak caused a significant oil spill. In response to the explosion and spill, the U.S. Department of the Interior, initially through its MMS and subsequently through its BOEMRE when the MMS was renamed BOEMRE in June 2010, implemented a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that effectively shut down deepwater drilling sidetracks and bypasses of wells beginning in May 2010 until the moratorium was lifted by the Department of the Interior in October 2010.

In addition, while the moratorium was in place, the BOEMRE issued a series of NTLs or regulatory requirements imposing new standards and permitting procedures for new wells to be drilled in federal waters of the Outer Continental Shelf. These requirements include the following:

• the Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;

• the Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers;

• the Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and

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• the Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system (“SEMS”) in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

The Deepwater Horizon incident is likely to have a significant and lasting effect on the U.S. offshore energy industry, and will likely result in a number of fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards, changes in equipment requirements and the availability and cost of insurance, as well as increased politicization of the industry. On September 14, 2011, the BOEMRE issued proposed rules that would amend the Workplace Safety Rule by requiring the imposition of certain added safety procedures to a company’s SEMS not covered by the original rule and revising existing obligations that a company’s SEMS be audited by requiring the use of an independent third party auditor who has been pre-approved by the agency to perform the auditing task. As a result of the issuance of these adopted and proposed regulatory requirements, the BOEMRE has been taking much longer than in the past to review and approve permits for new wells. These new requirements also increase the cost of preparing each permit application and will increase the cost of each new well, particularly for wells drilled in deeper waters on the Outer Continental Shelf.

Moreover, because of BOEMRE’s separation into two federal bureaus, the BOEM and the BSEE, on October 1, 2011, we are now interacting with two newly formed federal bureaus to obtain approval of our exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays and increased exploratory and production costs as the functions of the former BOEMRE are fully divested from the former agency and implemented in the two federal bureaus. These delays and costs could have a significant adverse effect on our results of operations.

We are unsure what long-term effect, if any, the BOEM’s or BSEE’s additional regulatory requirements and permitting procedures will have on our offshore operations. Consequently, we may be subject to a variety of unforeseen adverse consequences arising directly or indirectly from the Deepwater Horizon incident.

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 BOEMRE. 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 BOEMRE 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 (“FRU”)—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 Safety and Environmental Management System (“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 (“API RP 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,

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• Pre-Startup review,

• Emergency response and control,

• 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 compliance with the SEMS requirements.

How We Evaluate Our Operations

We use a variety of financial and operational measures to assess our 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, 2011, 2010 and 2009:

	Year Ended December 31,
	2011		2010			2009
Average daily sales:
Oil (Boepd)		5,455		2,348			385
Natural gas (Mcfpd)		49,829		21,911			6,695
Plant products (Gal/d)		33,580		14,802			876
Oil equivalents (Boepd)		14,559		6,353			1,521
Average realized prices (1):
Oil ($/Bbl)	$	105.17	$	80.97		$	71.59
Natural gas ($/Mcf)		4.94		5.44			4.55
Plant products ($/Gallon)		1.29		1.10			1.32
Oil equivalents ($/Boe)		59.30		51.27			38.88
Costs and Expenses:
Lease operating expense ($/Boe)		29.83		23.56			15.55
Production tax expense ($/Boe)		0.16		0.28			0.96
General and administrative expense ($/Boe)		4.15		6.29			12.90
Net income (loss) (in thousands)		15,041		(23,897	)		663
Adjusted EBITDA (2) (in thousands)		110,686		47,052			4,617

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

(2) Adjusted EBITDA is defined as net income (loss) before interest expense, income taxes, depreciation and amortization, impairment, accretion, unrealized gain/loss on derivative instruments, gain on involuntary conversion of assets and gain on sale of asset. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP, and should not be considered as an alternative to net income (loss), operating income (loss) or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as a measure of our liquidity. We present Adjusted EBITDA because it is frequently used by securities analysts, investors and other interested parties in the evaluation of high-yield issuers, many of whom present Adjusted EBITDA when reporting their results. Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results or cash flows as reported under GAAP. Because of these limitations, Adjusted EBITDA should not be considered as 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,
	2011			2010			2009
Net income (loss)	$	15,041		$	(23,897	)	$	663
Adjusted EBITDA	$	110,686		$	47,052		$	4,617
Reconciliation of Net income (loss) to Adjusted EBITDA:
Net income (loss)	$	15,041		$	(23,897	)	$	663
Interest expense		25,752			12,872			3,662
Unrealized loss (gain) on derivatives instruments		(17,556	)		12,700			2,756
Accretion		27,410			9,175			388
Depreciation, depletion, amortization and impairment		60,181			36,202			15,866
Gain on involuntary conversion of assets		—			—			(18,718	)
Gain on sale of asset		(142	)		—			—
Adjusted EBITDA	$	110,686		$	47,052		$	4,617

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, realized gains and losses 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 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, 2011, 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, 2011 Compared to Year Ended December 31, 2010

The following table sets forth certain information with respect to oil and gas operations for the years ended December 31, 2011 and 2010.

	Year Ended December 31,
	2011			2010			Change			% Change
PRODUCTION:
Oil (MBbl)		1,991			857			1,134			132	%
Natural gas (MMcf)		18,188			7,997			10,191			127	%
Plant products (MGal)		12,257			5,403			6,854			127	%
Total (MBoe)		5,314			2,319			2,995			129	%
REVENUES
Oil sales	$	215,204		$	68,654		$	146,550			213	%
Natural gas sales		75,994			34,999			40,995			117	%
Plant product sales and other income		23,091			8,913			14,178			159	%
Realized gain on derivative financial instruments		8,099			9,271			(1,172	)		-13	%
Unrealized gain (loss) on derivative financial instruments		17,556			(12,700	)		30,256			238	%
		339,944			109,137			230,807			211	%
OPERATING EXPENSES
Lease operating		158,545			54,627			103,918			190	%
Production taxes		859			640			219			34	%
Workover		23,385			4,288			19,097			445	%
Exploration		1,004			14			990			7071	%
Depreciation, depletion and amortization		47,214			29,795			17,419			58	%
Impairment		12,967			6,407			6,560			102	%
General and administrative		22,029			14,588			7,441			51	%
Accretion		27,410			9,175			18,235			199	%
Gain on sale of asset		(142	)		—			(142	)		-100	%
TOTAL OPERATING EXPENSES		293,271			119,534			173,737			145	%
INCOME (LOSS) FROM OPERATIONS		46,673			(10,397	)		57,070			549	%
OTHER INCOME (EXPENSE)
Interest income		373			129			244			189	%
Miscellaneous (expense) income		(6,253	)		(757	)		(5,496	)		726	%
Interest expense		(25,752	)		(12,872	)		(12,880	)		100	%
TOTAL OTHER INCOME (EXPENSE)		(31,632	)		(13,500	)		(18,132	)		134	%
NET INCOME (LOSS)	$	15,041		$	(23,897	)	$	38,938			163	%

Production

Oil and natural gas production. Total oil, natural gas and plant product production of 5,314 MBoe increased 2,995 MBoe, or 129%, during the year ended December 31, 2011, compared to the same period in 2010. The increase in production during 2011 was primarily a result of properties acquired in the Nippon Acquisition in September 2010 (1,792 MBoe), the Maritech Acquisition in February 2011 (285 MBoe) and the Merit Acquisition in May 2011 (1,188 MBoe).

Revenues

Total revenues. Total revenues for the year ended December 31, 2011 of $339.9 million increased $230.8 million, or 211%, over the comparable period in 2010. The increase in revenues during 2011 was a result of increased production related to the properties acquired in the Nippon Acquisition ($103.0 million), the Maritech Acquisition ($22.4 million), and the Merit Acquisition ($69.2 million) as well as higher oil prices. Total revenues were also higher due to a $17.6 million unrealized gain on derivative financial instruments for the year ended December 31, 2011 compared to a $12.7 million unrealized loss for the prior year.

We entered into certain oil and natural gas commodity derivative contracts in 2011 and 2010. We realized gains on these derivative contracts in the amounts of $8.1 million and $9.3 million for the years ended December 31, 2011 and 2010, respectively. We recognized an unrealized gain (loss) of $17.6 million and ($12.7) million for the years ended December 31, 2011 and 2010, respectively. Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, increased $201.7 million for the year ended December 31, 2011 compared to the same period in 2010 as a result of increased oil, natural gas and plant products production from the acquisitions and higher oil prices.

Excluding hedges, we realized average oil prices of $108.09 per barrel and gas prices of $4.18 per Mcf for the year ended December 31, 2011. Excluding hedges, for the year ended December 31, 2010, we realized average oil prices of $80.09 per barrel and gas prices of $4.38 per Mcf. Although average prices realized from the sale of oil reflected the economic turnaround that began during 2010, economic conditions continue to remain uncertain. Oil and natural gas prices will remain unstable and we expect them to be volatile in the future.

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Operating Expenses

Lease operating costs. Our lease operating costs for the year ended December 31, 2011 increased to $158.5 million, or $29.83 per Boe, compared to $54.6 million, or $23.56 per Boe, for the same period of 2010. The increase in lease operating costs during 2011 is directly related to the increase in properties from the Nippon Acquisition, the Maritech Acquisition and the Merit Acquisition. The increase in cost per Boe during 2011 is primarily attributable to a mix of increased properties and related workover activities.

Workover costs. Our workover costs increased $19.1 million to $23.4 million for the year ended December 31, 2011 compared to $4.3 million for the same period in 2010. For the year ended December 31, 2011, High Island 571, Galveston 424 and South Timbalier 8 were the primary workover expense projects.

Exploration. 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 is deemed non-commercial.

Depreciation, depletion, amortization and impairment. DD&A expense was $47.2 million, or $8.88 per Boe, and $29.8 million, or $12.85 per Boe, for the years ended December 31, 2011 and 2010, respectively. In 2011, the increase in DD&A expense was the result of increased production associated with the properties acquired in 2011 and 2010. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded $13.0 million and $6.4 million in impairments for the years ended December 31, 2011 and 2010, respectively, as the estimated undiscounted cash flows of oil and gas properties are less than its carrying value on certain properties.

General and administrative expenses. G&A expense was $22.0 million, or $4.15 per Boe, and $14.6 million, or $6.29 per Boe, for the years ended December 31, 2011 and 2010, respectively. The increase in G&A expense is primarily due to higher costs for additional staff, contract personnel, professional services, bonding insurance and other related administrative costs attributable to our growth in 2011 and 2010.

Accretion expense. We recognized accretion expense of $27.4 million and $9.2 million for the years ended December 31, 2011 and 2010, respectively. The increase in accretion expense in 2011 was attributable to assumed asset retirement obligations related to our acquisitions in 2011 and 2010.

Miscellaneous expense. Miscellaneous expense increased $5.5 million to $6.3 million for the year ended December 31, 2011 compared to $0.8 million for the same period in 2010. The significant increase was a result of the consent solicitation fee paid under the First Supplemental Indenture to the Indenture.

Interest expense. Interest expense increased $12.9 million for the year ended December 31, 2011 compared to the same period in 2010. The increase of interest expense in 2011 compared to 2010 was a result of borrowings under our credit facility to fund the Merit P&A obligation, the issuance of the Notes in November 2010, the proceeds of which were used to fund the Nippon Acquisition and associated escrow deposits for future P&A costs, and amortization of debt issuance costs as a result of the repayment of loans with proceeds from the Notes, which was partially offset by lower fixed interest rates.

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Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The following table sets forth certain information with respect to oil and gas operations for the years ended December 31, 2010 and 2009.

	Year Ended December 31,
	2010			2009			Change			% Change
PRODUCTION:
Oil (MBbl)		857			140			717			512	%
Natural gas (MMcf)		7,997			2,444			5,553			227	%
Plant products (MGal)		5,403			320			5,083			1588	%
Total (MBoe)		2,319			555			1,764			318	%
REVENUES
Oil sales	$	68,654		$	9,887		$	58,767			594	%
Natural gas sales		34,999			10,480			24,519			234	%
Plant product sales and other income		8,913			421			8,492			2017	%
Realized (loss) gain on derivative financial instruments		9,271			801			8,470			1057	%
Unrealized (loss) gain on derivative financial instruments		(12,700	)		(2,756	)		(9,944	)		361	%
		109,137			18,833			90,304			479	%
OPERATING EXPENSES
Lease operating		54,627			8,635			45,992			533	%
Production taxes		640			534			106			20	%
Workover		4,288			874			3,414			391	%
Exploration		14			47			(33	)		-70	%
Depreciation, depletion and amortization		29,795			15,419			14,376			93	%
Impairment		6,407			446			5,961			1337	%
General and administrative		14,588			7,164			7,424			104	%
Gain due to involuntary conversion of asset		—			(18,718	)		18,718			-100	%
Accretion		9,175			388			8,787			2265	%
TOTAL OPERATING EXPENSES		119,534			14,789			104,745			708	%
(LOSS) INCOME FROM OPERATIONS		(10,397	)		4,044			(14,441	)		-357	%
OTHER INCOME (EXPENSE)
Interest income		129			281			(152	)		-54	%
Miscellaneous (expense) income		(757	)		—			(757	)		-100	%
Interest expense		(12,872	)		(3,662	)		(9,210	)		252	%
TOTAL OTHER INCOME (EXPENSE)		(13,500	)		(3,381	)		(10,119	)		299	%
NET (LOSS) INCOME	$	(23,897	)	$	663		$	(24,560	)		-3704	%

Production

Oil and natural gas production. Total oil, natural gas and plant product production of 2,319 MBoe in 2010 represented an increase of 1,764 MBoe, or 318%, compared to 2009. The increase in production in 2010 was primarily attributable to a full year of ownership of the properties acquired in the W&T Acquisition (1,305 MBoe) and three months of ownership of the properties acquired in the Nippon Acquisition (496 MBoe).

Revenues

Total revenues. Total revenues for the year ended December 31, 2010 of $109.1 million represented an increase of $90.3 million, or 479%, over the same period in 2009. The increase in revenues in 2010 was primarily attributable to a full year of ownership of the properties acquired in the W&T Acquisition ($68.8 million) and three months of ownership of the properties acquired in the Nippon Acquisition ($23.2 million).

We entered into certain oil and natural gas commodity derivative contracts in 2010 and 2009. We realized gains on these derivative contracts in the amount of $9.3 million in 2010 and $0.8 million in 2009 and recognized unrealized losses of $12.7 million and $2.8 million in 2010 and 2009, respectively. Excluding the realized and unrealized revenues from commodity hedge contracts, revenues for the periods ended December 31, 2010 and 2009 were $112.6 million and $20.8 million, respectively. Revenues, excluding hedging activity, increased $91.8 million in 2010 compared to the previous year as a result of increased oil, natural gas and plant products production attributable to the W&T and Nippon Acquisitions and higher oil prices.

Excluding hedges, we realized average oil prices of $80.09 per barrel and $70.43 per barrel and gas prices of $4.38 per Mcf and $4.29 per Mcf for the years ended December 31, 2010 and 2009, respectively. The incline in average prices realized from the sale of oil and natural gas reflected the economic turnaround that began during 2010.

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Operating Expenses

Lease operating costs. Our lease operating costs for 2010 increased to $54.6 million, or $23.56 per Boe, from $8.6 million, or $15.55 per Boe for 2009. The increase in lease operating costs is directly related to the properties acquired in the W&T and Nippon Acquisitions.

Production taxes. Our production taxes were $0.6 million and $0.5 million for the years ended December 31, 2010 and 2009, respectively. Although production and revenues increased significantly in 2010 compared to 2009, production taxes did not increase at the same rate as many of the properties acquired in the W&T and Nippon Acquisitions were located in federal waters and not subject to production taxes.

Workover costs. Our workover costs for 2010 and 2009 were $4.3 million and $0.9 million, respectively. For the year ended December 31, 2010, the primary workover expense projects were West Cameron 66, East Cameron 64, Eugene Island 107/108, High Island A-376, High Island A-571, South Pass 89, West Cameron 370, El Gordo and High Island 140. For the year ended December 31, 2009, workover expense was primarily related to the South Timbalier 8 field.

Depreciation, depletion, amortization and impairment. DD&A expense was $29.8 million and $15.4 million for the years ended December 31, 2010 and 2009, respectively. The increase in DD&A expense in 2010 is primarily related to the DD&A expenses associated with the properties acquired in the W&T and Nippon Acquisitions. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded $6.4 million and $0.4 million impairment in 2010 and 2009, respectively.

General and administrative expenses. G&A expense totaled $14.6 million and $7.2 million for the years ended December 31, 2010 and 2009, respectively. The increase in G&A expense in 2010 resulted principally from costs associated with the increase in staff and related administrative costs attributable to the W&T and Nippon Acquisitions.

Accretion expense. We recognized accretion expense of $9.2 million and $0.4 million for the years ended December 31, 2010 and 2009, respectively. The increase in accretion expense in 2010 was attributable to increased asset retirement obligations assumed in the W&T Acquisition and Nippon Acquisition and timing of the acquisition as both were in the second half of the year.

Gain due to involuntary conversion of asset. In June 2008, we experienced an extensive amount of well damage caused by a blowout. We had insurance coverage of $50 million, after a deductible of $0.5 million. The total costs incurred for well control, plugging and abandonment, and re-drill costs were reimbursed by the insurance company as expenditures were incurred. No gain was recognized during the year ended December 31, 2010 compared with $18.7 million recognized in the year ended December 31, 2009.

Interest expense. We incurred $12.9 million and $3.7 million of interest expense for the years ended December 31, 2010 and 2009, respectively. The $9.2 million increase of interest expense in 2010 was a result of borrowings to fund the Nippon Acquisition and associated escrow deposits for future P&A costs and amortization of credit debt issuance costs as of result of the repayment of loans with proceeds from the Senior Notes Offering in November 2010.

Other expense. We recognized $0.8 million of other expense for the year ended December 31, 2010, as opposed to none in 2009. In 2010, as required in the W&T Acquisition, we paid $0.7 million to W&T as a 3% fee on the shortfall of funding the escrow account with respect to the Operated Properties. In November 2010, we fully funded the escrow for the Operated Properties.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from our members, proceeds from the offering of our senior notes, which closed in November 2010, borrowings under our lines of credit and cash flows from operations. We believe that our working capital requirements, contractual obligations and expected capital expenditures discussed below, as well as our other liquidity needs for the next twelve months, can be met from cash flows provided by operations and from amounts available under our revolving credit facility. Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our P&A obligations. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Senior Secured Revolving Credit Facility

On December 24, 2010, we entered into an aggregate $110 million credit facility (the “Credit Facility”) with Capital One, N.A., as administrative agent and a lender thereunder. The Credit Facility is comprised of (1) a senior secured reserve-based revolver, under which our initial borrowing base was set at $35 million and (2) a $75 million secured letter of credit facility, which is to be used exclusively for the issuance of letters of credit in support of our future P&A obligations relating to our oil and gas properties. The borrowing base under our revolving credit facility is subject to redetermination on a semi-annual basis, effective April 1 and October 1, and up to one additional time during any six-month period, as may be requested by either us or the administrative agent, acting at the direction of the majority of the lenders. The 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 revolver, and by cash collateral, in the case of the letter of credit facility. The Credit Facility has a maturity date of December 31, 2013.

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

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

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

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

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On May 31, 2011, we entered into an amendment to the Credit Facility that (1) increased the amount available for borrowing thereunder from $35 million to $70 million and (2) increased the secured letter of credit from $75 million to $125 million.

As of December 31, 2011, we were in compliance with our hedging requirement.

As of December 31, 2011, letters of credit in the aggregate amount of $112.4 million were outstanding under this facility and we had $24.0 million in borrowings under the revolver. As of March 15, 2012, $41.6 million was available for additional borrowings, including $29.0 million under the revolver.

13.75 % Senior Secured Notes

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

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

We have the right or the obligation to redeem the Notes under various conditions. If we experience a change of control, the holders of the Notes may require us to repurchase the Notes at 101% of the principal amount thereof, plus accrued unpaid interest. In addition, within 90 days after December 2011 for which excess cash flow, as defined in the Indenture, exceeds $5.0 million to the extent permitted by our Notes, we will offer to purchase the Notes at an offer price equal to 100% of the aggregate principal amount of Notes repurchased plus accrued and 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, 2011, we were in compliance with our covenants under the Indenture.

Member Contributions

On May 31, 2011, Platinum entered into a contribution agreement with us, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivable, in exchange for 30 million of our Class D Units. The Class D Units are non-voting units having an aggregate liquidation preference of $30 million and accruing dividends payable in kind at a rate per annum of 24%.

At December 31, 2011, Platinum has contributed a total of $15.1 million in cash and $14.9 million remains in financial instruments deemed by us to be a cash equivalent.

Capital Expenditure Budget

We have a total capital expenditure budget of $49.9 million (excluding expenditures directly related to any acquisitions) for 2012, which is a 135% increase over the approximately $21.2 million of capital expenditures (excluding acquisitions) during 2011. Approximately $1.7 million of our 2012 capital budget was expended in the first month of 2012 for various projects including recompletions and drilling, and the remaining $48.2 million will be used for drilling and development during the remainder of the year. The NSAI Report included an assumption that we would spend $70.0 million in capital expenditures during 2012. The NSAI Report included the estimated non-operated capital expenditures which are not reflected in our 2012 capital expenditure budget amount above.

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.

To date, our 2012 capital budget has been funded from borrowings under our lines of credit and cash flows from operations. We believe the borrowings under our Credit Facility, together with cash flows from operations, should be sufficient to fund the remainder of our 2012 capital expenditure budgets.

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. Additionally, the Indenture governing the Notes restricts the amount of capital expenditures that we may make each year to $30 million for fiscal year 2011 and 25% of Consolidated EBITDAX (as defined in the Indenture) for each subsequent year. In addition, aggregate capital expenditures may not exceed $210.0 million. The capital expenditure requirement 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, 2011 and 30% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expense for any year thereafter.

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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, 2011, 2010 and 2009 (in thousands):

	Year Ended December 31,
	2011			2010			2009
Net cash provided by (used in) operating activities	$	73,647		$	28,345		$	(528	)
Net cash used in investing activities		(108,641	)		(114,815	)		(27,415	)
Net cash provided by financing activities		33,375			99,113			32,532
Net increase in cash and equivalents	$	(1,619	)	$	12,643		$	4,589

Cash flows provided by operating activities. Cash provided by operating activities totaling $73.6 million in 2011 compared to $28.3 million during 2010. The increase in operating cash flows was principally attributable to higher net income as a result of the 2010 and 2011 acquisitions. The cash provided by operating activities in 2010 of $28.3 million, an increase of $28.9 million from the same period in 2009, was primarily related to the full year ownership of the W&T Properties and three months ownership of the Nippon Properties.

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 $108.6 million in 2011 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. The cash used in investing activities in 2010 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, 2010. Cash used in investing activities in 2009 was attributable to the acquired properties in the W&T Acquisition partially offset by insurance proceeds received due to well damage caused by a blowout.

Cash flows provided by financing activities. Cash flows provided by financing activities of $33.4 million in 2011 were attributable to borrowings 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. Cash flows provided by financing activities in 2010 were attributable to the issuance of the notes partially offset by the repayment of borrowings under our lines of credit with Platinum. Cash flows provided by financing activities during the year ended December 31, 2009 related primarily to borrowings to fund the W&T Acquisition.

W&T Escrow Accounts

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.

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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.

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, 2011, we have funded $3.6 million, leaving $9.5 million to be funded through February 2014. 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, 2011, we have funded $14.0 million, leaving $46.0 million to be funded through November 2013. 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 and we have deposited $60 million in the escrow account.

Asset Retirement Obligations

As many as four times per year we review, and, to the extent necessary, revise our asset retirement obligation estimates. During 2009, primarily as a result of the W&T Acquisition, we increased our asset retirement obligations by $46.6 million and recognized $0.4 million in accretion expense. In 2010, we increased our asset retirement obligations by $70.9 million, primarily as a result of the Nippon Acquisition, and recognized $9.2 million in accretion expense. In 2011, we increased our asset retirement obligation by $166.4 million primarily as a result of the Maritech Acquisition and Merit Acquisition and we recognized $27.4 million in accretion expense, respectively.

At December 31, 2011 and 2010, we recorded total asset retirement obligations of $288.7 million and $122.2 million, respectively, and have funded approximately $172.2 million and $114.2 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds. As of December 31, 2011, we also have an 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, 2011.

	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	$	178,154	$	4,154	$	24,000	$	150,000	$	—
Interest on debt and notes payable		82,928		21,716		42,306		18,906		—
Operating leases (1)		17,239		2,692		4,690		3,733		6,124
Total contractual obligations		278,321		28,562		70,996		172,639		6,124
Other Obligations
Asset retirement obligations (2)		288,686		15,238		190,311		41,569		41,568
Total obligations	$	567,007	$	43,800	$	261,307	$	214,208	$	47,692

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

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

Off-Balance Sheet Arrangements

In October 2010, we guaranteed a loan in the aggregate principal amount of $3.2 million for a related party which is not consolidated in our financials as the entity is not material to us (see “Item 14. Certain Relationships and Related Transactions and Director Independence”). We have no plans to enter into any off-balance sheet arrangements in the foreseeable future. At December 31, 2011, the balance of the loan was $3.0 million and has a maturity date of October 8, 2013.

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.

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At December 31, 2011, commodity derivative instruments were in place covering approximately 48% of our projected oil sales volumes and 40% of our projected natural gas sales volumes through 2012.

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 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 charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities.

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 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, 2011 and 2010, has been prepared and presented in accordance with new SEC rules and accounting standards. These new rules are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month un-weighted first-day-of-the-month average pricing. The previous rules required that reserve estimates be calculated using last-day-of-the-year 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: In accordance with authoritative guidance for derivatives and hedges, all derivative instruments are measured periodically and at year end and are recorded on the consolidated balance sheets at fair value. Derivative contracts that are designated as part of a qualifying cash flow hedge, per the requirements for cash flow hedges, are granted hedge accounting thereby allowing us to treat the effective changes in the fair value of the derivative instrument in accumulated other comprehensive income, while recording the ineffective portion as an adjustment to unrealized gain (loss). Derivative contracts that are not designated as part of a valid qualifying hedge or fail to meet the requirements of the pronouncement as a highly effective hedge, are treated by recording the changes in the fair value from period to period, through earnings. The amounts paid or received upon each monthly settlement, are recorded as derivative gain (loss) with the offset recorded to cash. These monthly settlements are included in oil and gas revenue on our consolidated statements of operations.

For the years ended December 31, 2011, 2010 and 2009, we elected not to designate any of our derivative contracts as qualifying hedges for financial reporting purposes, therefore all of the derivative instruments are categorized as standalone derivatives and are being marked-to-market with unrealized gains (losses) recorded in the consolidated statements of operations.

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Asset Retirement Obligations: Effective January 1, 2008, we adopted authoritative guidance for asset retirement obligations, using 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: In May 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance which amends fair value measurements and disclosures. The amended guidance clarifies many requirements in U.S. generally accepted accounting principles (“GAAP”) for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance is effective for interim and annual periods beginning after December 15, 2011. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.

In September 2011, the FASB issued authoritative guidance which amends intangible assets—goodwill and other. The amended guidance provides the option to first assess qualitative factors to determine whether it is more likely than not (a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount. If, after considering the totality of events and circumstances, the qualitative assessment does not indicate that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. The guidance is effective for interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.

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

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, 2011, 2010 and 2009, we received an average of $108.09, $80.09 and $70.43 per barrel of oil, respectively, and $4.18, $4.38 and $4.29 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. We expect these costs to reflect upward pressure during 2012 as a result of the improvements in oil prices in 2010 and 2011.

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, 2011, our annual revenue would increase or decrease by approximately $19.9 million for each $10.00 per barrel change in oil prices and $18.2 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging. Based on our total annual production for the year ended December 31, 2010, our revenues would have increased or decreased by approximately $8.6 million for each $10.00 per barrel change in oil prices and $8.0 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, 2011, the fair value of our commodity derivatives were included in the consolidated balance sheets for approximately $4.2 million as current assets and $2.1 million as long-term liabilities. At December 31, 2010, the fair value of our commodity derivatives was approximately $3.8 million and $11.7 million, which were recorded as current and long-term liabilities, respectively, in the consolidated balance sheets. For the years ended December 31, 2011, 2010 and 2009, we realized a net increase in oil and natural gas revenues related to hedging transactions of approximately $8.1 million, $9.3 million and $0.8 million, respectively.

42

As of December 31, 2011, we maintained the following commodity derivative contracts:

Remaining Contract Term: Oil	Contract Type	Notational Volume in Bbls/Month		NYMEX Strike Price
December 2013 - December 2013	Swap		27,750	$	96.90
January 2013 - October 2013	Swap		27,750	$	96.90
January 2012 - December 2012	Swap		27,500	$	85.90
November 2013 - November 2013	Swap		26,800	$	96.90
December 2012 - December 2012	Swap		23,000	$	96.90
January 2012 - October 2012	Swap		23,000	$	96.90
January 2012 - June 2012	Swap		22,125	$	100.80
November 2012 - November 2012	Swap		22,080	$	96.90
January 2013 - December 2013	Swap		19,750	$	85.90
January 2014 - February 2014	Swap		19,000	$	96.90
January 2012 - December 2012	Swap		17,050	$	81.22
January 2013 - June 2013	Swap		15,542	$	100.80
December 2012 - December 2012	Swap		15,140	$	100.80
January 2014 - December 2014	Swap		15,000	$	65.00
July 2012 - July 2012	Swap		12,048	$	100.80
January 2014 - May 2014	Swap		10,083	$	100.80
December 2013 - December 2013	Swap		10,041	$	100.80
August 2012 - August 2012	Swap		8,296	$	100.80
July 2013 - July 2013	Swap		7,132	$	100.80
August 2013 - August 2013	Swap		5,980	$	100.80
September 2012 - September 2012	Swap		3,998	$	100.80
September 2013 - September 2013	Swap		3,897	$	100.80
October 2013 - October 2013	Swap		3,259	$	100.80
January 2012 - December 2012	Swap		1,900	$	81.14
October 2012 - October 2012	Swap		1,884	$	100.80
January 2012 - July 2012	Swap		200	$	83.50

Remaining Contract Term: Oil	Contract Type	Notational Volume in MMBtus/Month		NYMEX Strike Price
January 2012 - May 2012	Swap		318,958	$	4.94
June 2012 - June 2012	Swap		303,880	$	4.94
January 2012 - October 2012	Swap		227,000	$	4.60
January 2013 - June 2013	Swap		200,669	$	4.94
July 2013 - July 2013	Swap		148,788	$	4.94
August 2013 - August 2013	Swap		139,212	$	4.94
January 2014 - June 2014	Swap		129,960	$	4.94
December 2013 - December 2013	Swap		119,462	$	4.94
September 2013 - September 2013	Swap		116,125	$	4.94
January 2012 - December 2012	Swap		112,000	$	5.00
July 2012 - July 2012	Swap		106,638	$	4.94
December 2012 - December 2012	Swap		106,375	$	4.94
January 2013 - October 2013	Swap		104,000	$	4.60
October 2013 - October 2013	Swap		91,166	$	4.94
August 2012 - August 2012	Swap		90,586	$	4.94
January 2014 - February 2014	Swap		82,000	$	4.60
November 2013 - November 2013	Swap		64,926	$	4.94
September 2012 - September 2012	Swap		56,141	$	4.94
January 2012 - December 2012	Swap		53,000	$	5.70
January 2013 - December 2013	Swap		47,000	$	5.00
October 2012 - October 2012	Swap		41,462	$	4.94
January 2012 - December 2012	Swap		26,838	$	5.89
January 2012 - July 2012	Swap		5,250	$	5.89
November 2012 - November 2012	Swap		2,951	$	4.94

43

Subsequent to December 31, 2011, we entered into the following derivatives:

Remaining Contract Term: Oil	Contract Type	Notational Volume in Bbls/Month		NYMEX Strike Price
March 1, 2012 - March 31, 2012	Swap		61,170	$	102.40
April 1, 2012 - April 30, 2012	Swap		51,730	$	102.40
May 1, 2012 - May 31, 2012	Swap		45,340	$	102.40
June 1, 2012 - June 30, 2012	Swap		36,000	$	102.40
July 1, 2012 - July 31, 2012	Swap		21,110	$	102.40
August 1, 2012 - August 31, 2012	Swap		22,890	$	102.40
September 1, 2012 - September 30, 2012	Swap		20,930	$	102.40
October 1, 2012 - October 31, 2012	Swap		23,170	$	102.40
November 1, 2012 - November 30, 2012	Swap		19,290	$	102.40
December 1, 2012 - December 31, 2012	Swap		24,860	$	102.40
January 1, 2013 - January 31, 2013	Swap		43,510	$	102.40
February 1, 2013 - February 28, 2013	Swap		29,030	$	102.40
March 1, 2013 - March 31, 2013	Swap		35,760	$	102.40
April 1, 2013 - April 30, 2013	Swap		28,740	$	102.40
May 1, 2013 - May 31, 2013	Swap		28,540	$	102.40
June 1, 2013 - June 30, 2013	Swap		22,800	$	102.40
July 1, 2013 - July 31, 2013	Swap		14,700	$	102.40
August 1, 2013 - August 31, 2013	Swap		14,080	$	102.40
September 1, 2013 - September 30, 2013	Swap		12,390	$	102.40
October 1, 2013 - October 31, 2013	Swap		13,710	$	102.40
November 1, 2013 - November 30, 2013	Swap		14,320	$	102.40
December 1, 2013 - December 31, 2013	Swap		19,310	$	102.40
January 1, 2014 - January 31, 2014	Swap		30,600	$	102.40
February 1, 2014 - February 28, 2014	Swap		22,010	$	102.40
March 1, 2014 - March 31, 2014	Swap		45,910	$	102.40
April 1, 2014 - April 30, 2014	Swap		41,850	$	102.40
May 1, 2014 - May 31, 2014	Swap		42,530	$	102.40
June 1, 2014 - June 30, 2014	Swap		48,860	$	102.40
July 1, 2014 - July 31, 2014	Swap		36,680	$	102.40
August 1, 2014 - August 31, 2014	Swap		35,360	$	102.40
September 1, 2014 - September 30, 2014	Swap		32,290	$	102.40
October 1, 2014 - October 31, 2014	Swap		32,920	$	102.40
November 1, 2014 - November 30, 2014	Swap		30,000	$	102.40
December 1, 2014 - December 31, 2014	Swap		41,880	$	102.40

For further discussion of our hedging activities, please see “Notes to Consolidated Financial Statements—Note 7—Derivative Instruments” included in this Form 10-K.

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 $10.5 million at December 31, 2011 and $4.2 million at December 31, 2010. Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have an interest. We also have exposure to credit risk from the sale of our oil and natural gas production, which we market to energy marketing companies and refineries, the receivables which totaled $35.9 million at December 31, 2011 and $21.6 million at December 31, 2010.

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 have not required our counterparties to provide collateral to support oil and natural gas sales receivables owed to us.

44

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility, which bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 2.75% to 3.5%, or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The applicable margin is computed based on the grid when the borrowing based utilization percentage is at its highest level. Based on the $136.4 million outstanding under the Credit Facility as of December 31, 2011, an increase of 100 basis points in the underlying interest rate would have had a $1.4 million impact on our annual interest expense. However, there is no guarantee that we will not borrow additional amounts under the Credit Facility in the future, and, in the event we borrow amounts and interest rates significantly increase, the interest that we would be required to pay would be more significant. We do not believe our variable interest rate exposure warrants entry into interest rate hedges and, therefore, we have not hedged our interest rate exposure. However, to reduce our exposure to changes in interest rates for our borrowings under the Credit Facility, we may in the future enter into interest rate risk management arrangements for a portion of our outstanding debt to alter our interest rate exposure. See “—Liquidity and Capital Resources—Senior Secured Revolving Credit Facility” for additional information on our Credit Facility.

45

Item 8. Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm	47
Consolidated Balance Sheets	48
As of December 31, 2011 and 2010
Consolidated Statements of Operations	49
Years Ended December 31, 2011, 2010 and 2009
Consolidated Statements of Members’ Equity (Deficit)	50
Years Ended December 31, 2011, 2010 and 2009
Consolidated Statements of Cash Flows	51
Years Ended December 31, 2011, 2010 and 2009
Notes to Consolidated Financial Statements	52

46

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, 2011 and 2010, and the related consolidated statements of operations, members’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

March 26, 2012

47

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31, 2011		December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,260	$	18,879
Accounts receivable, net		52,439		26,093
Due from affiliates		23		435
Prepaid expenses and other		26,637		13,123
Derivative assets		4,216		—
TOTAL CURRENT ASSETS		100,575		58,530
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $114,056 and $55,119 at December 31, 2011 and 2010, respectively		238,702		123,783
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $870 and $264 at December 31, 2011 and 2010, respectively		2,245		1,152
OTHER ASSETS
Debt issue costs, net		8,726		8,871
Asset retirement obligation escrow receivable		20,348		—
Escrow for abandonment costs		172,153		114,168
Other assets		3,257		—
TOTAL OTHER ASSETS		204,484		123,039
TOTAL ASSETS	$	546,006	$	306,504
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	76,509	$	34,111
Derivative liabilities		—		3,754
Asset retirement obligations		15,238		1,023
Current portion of debt and notes payable		4,154		2,069
TOTAL CURRENT LIABILITIES		95,901		40,957
LONG-TERM LIABILITIES
Gas imbalance payable		1,362		4,552
Derivative liabilities		2,116		11,702
Asset retirement obligations, net of current portion		273,448		121,219
Debt, net of current portion, net of unamortized discount of $1,113 and $1,316 at December 31, 2011 and 2010, respectively		172,887		148,684
TOTAL LONG-TERM LIABILITIES		449,813		286,157
TOTAL LIABILITIES		545,714		327,114
COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY (DEFICIT)		292		(20,610	)
TOTAL LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)	$	546,006	$	306,504

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

48

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2011			2010			2009
REVENUES:
Oil sales	$	215,204		$	68,654		$	9,887
Natural gas sales		75,994			34,999			10,480
Plant product sales and other revenue		23,091			8,913			421
Realized gain on derivative financial instruments		8,099			9,271			801
Unrealized gain (loss) on derivative financial instruments		17,556			(12,700	)		(2,756	)
TOTAL REVENUES		339,944			109,137			18,833
OPERATING EXPENSES:
Lease operating		158,545			54,627			8,635
Production taxes		859			640			534
Workover		23,385			4,288			874
Exploration		1,004			14			47
Depreciation, depletion and amortization		47,214			29,795			15,419
Impairment		12,967			6,407			446
General and administrative		22,029			14,588			7,164
Gain due to involuntary conversion of asset		—			—			(18,718	)
Accretion		27,410			9,175			388
Gain on sale of assets		(142	)		—			—
TOTAL OPERATING EXPENSES		293,271			119,534			14,789
INCOME (LOSS) FROM OPERATIONS		46,673			(10,397	)		4,044
OTHER INCOME (EXPENSE):
Interest income		373			129			281
Miscellaneous expense		(6,253	)		(757	)		—
Interest expense		(25,752	)		(12,872	)		(3,662	)
TOTAL OTHER EXPENSE		(31,632	)		(13,500	)		(3,381	)
NET INCOME (LOSS)		15,041			(23,897	)		663
PREFERRED UNIT DIVIDENDS		4,200			—			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	10,841		$	(23,897	)	$	663

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

49

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY (DEFICIT)

(in thousands)

	Members’ Capital			Retained Earnings (Accumulated Deficit)			Total Members’ Equity (Deficit)
Balance at December 31, 2008	$	686		$	4,233		$	4,919
Contributions		140			—			140
Net income		—			663			663
Balance at December 31, 2009		826			4,896			5,722
Distribution		(2,435	)					(2,435	)
Net loss					(23,897	)		(23,897	)
Balance at December 31, 2010		(1,609	)		(19,001	)		(20,610	)
Contributions		30,000			—			30,000
Distribution		(19,939	)		—			(19,939	)
Dividends		(4,200	)		—			(4,200	)
Net income		—			15,041			15,041
Balance at December 31, 2011	$	4,252		$	(3,960	)	$	292

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

50

BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	15,041		$	(23,897	)	$	663
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization		47,214			29,795			15,419
Impairment of oil and gas properties		12,967			6,407			446
Accretion of asset retirement obligations		27,410			9,175			388
Amortization of debt issue cost		2,915			834			745
Amortization of debt discount		203			—			—
Unrealized loss on derivative instruments		(17,556	)		12,700			2,756
Gain on sale of assets		(142	)		—			—
Gain on involuntary conversion of assets		—			—			(18,718	)
Changes in operating assets and liabilities:
Accounts receivable		(26,348	)		(15,591	)		(9,046	)
Insurance receivables		—			—			3,584
Due to/from affiliates, net		413			(413	)		224
Prepaid expenses and other assets		(13,513	)		(12,613	)		737
Accounts payable and accrued expenses		38,199			22,687			2,274
Gas imbalance		(4,748	)		468			—
Settlement of asset retirement obligations		(8,408	)		(1,207	)		—
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		73,647			28,345			(528	)
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(21,169	)		(25,397	)		(23,406	)
Acquisitions of oil and gas properties		(27,398	)		19,164			(25,726	)
Sale of oil and gas properties		150			—			—
Additions to property and equipment		(1,699	)		(868	)		(247	)
Deposits		(540	)		—			—
Insurance proceeds		—			—			18,718
Restricted cash		—			522			(22	)
Escrow deposit (payments) refunds		(57,985	)		(108,236	)		3,268
NET CASH USED IN INVESTING ACTIVITIES		(108,641	)		(114,815	)		(27,415	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long-term debt and notes payable		18,979			205,198			51,993
Payments on long-term debt and notes payable		(16,895	)		(94,578	)		(18,712	)
Borrowings on bank debt		158,457			—			—
Payments on bank debt		(134,457	)		—			—
Debt issuance costs		(2,770	)		(9,072	)		(749	)
Contributions from members		30,000			—			—
Distributions to members		(19,939	)		(2,435	)		—
NET CASH PROVIDED BY FINANCING ACTIVITIES		33,375			99,113			32,532
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(1,619	)		12,643			4,589
CASH AND CASH EQUIVALENTS - beginning of year		18,879			6,236			1,647
CASH AND CASH EQUIVALENTS - end of year	$	17,260		$	18,879		$	6,236
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	$	22,050		$	11,008		$	1,736
NON-CASH INVESTING AND FINANCING ACTIVITIES
Equity contributions	$	—		$	—		$	140
Increase in oil and gas properties for asset retirement obligations	$	147,442		$	62,911		$	46,621
Assumption of gas imbalances	$	(1,159	)	$	2,041		$	510
Increase in asset retirement obligation escrow receivable	$	20,348		$	—		$	—
Paid-in-kind dividends on preferred equity and accrued distributions to members	$	4,200		$	—		$	—

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

51

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.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Reclassifications: Certain reclassifications have been made to conform 2009 and 2010 balances to our 2011 presentation. Such reclassifications had no effect on net income or cash flow.

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

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

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

Oil and natural gas 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, natural gas and plant products revenues are recorded using the sales method whereby we recognize oil and natural gas revenue based on the amount of oil and natural gas sold to purchasers. 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 exists; (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 reasonably assured.

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. No allowance for doubtful accounts was considered necessary at December 31, 2011 and 2010.

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, 2011, 2010 and 2009 was $46.6 million, $29.6 million and $15.3 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 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, 2011, 2010 and 2009, we recorded an impairment charge of approximately $13.0 million, $6.4 million and $0.4 million, respectively.

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

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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, 2011, 2010 and 2009 was $0.6 million, $0.2 million and $0.1 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, 2011 and 2010 have been prepared and presented in accordance with SEC rules and applicable accounting standards. These rules require companies to prepare their reserve estimates using revised reserve definitions and revised 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 interest method. Amortization expense for the years ended December 31, 2011, 2010 and 2009 amounted to $2.9 million, $0.8 million and $0.7 million, respectively.

Future amortization expense is as follows:

Year Ending December 31,	(in thousands)
2012	$	3,060
2013		2,449
2014		1,760
2015		1,457
2016		—
	$	8,726

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 gains or losses. 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.

Gas Imbalances: The gas imbalance receivable (payable) occurs when we sell or utilize more than our respective share of total gas production. We record a gas imbalance receivable (payable) to the financial statements when there are not sufficient reserves to make up the gas imbalance. A gas imbalance payable can also be a result of imbalances acquired in conjunction with the acquisition of oil and gas properties. At December 31, 2011 and 2010, our net gas receivable (payable) imbalances were $1.4 million and $(4.6) million, respectively.

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

In May 2006, the state of Texas enacted a margin-based franchise tax law that replaced the existing franchise tax. This tax is commonly referred to as the Texas margin tax and is generally calculated as 1% of gross margin. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint

53

ventures are examples of the types of entities that are subject to the new tax. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax became effective for franchise tax reports due on or after January 1, 2008. During the years ended December 31, 2011, 2010 and 2009, the margin tax was immaterial to the consolidated financial statements.

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

In September 2011, the FASB issued authoritative guidance which amends intangible assets—goodwill and other. The amended guidance provides the option to first assess qualitative factors to determine whether it is more likely than not (a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount. If, after considering the totality of events and circumstances, the qualitative assessment does not indicate that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. The guidance is effective for interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.

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

NOTE 3—ACQUISITIONS

Merit Energy Corp

On May 31, 2011, we acquired the Merit Properties for a purchase price of $39 million and the assumption of $121.2 million in asset retirement obligations related to P&A obligations associated with acquired properties, subject to customary adjustments for a transaction of that type. The Merit Acquisition added interest in an estimated 236,200 gross (127,800 net) acres in the U.S. Gulf of Mexico to our portfolio.

At closing, we were required to establish an escrow account to secure the performance of our P&A obligations and other indemnity obligations with respect to P&A and/or decommissioning of the acquired wells and facilities. We paid $33 million in surety bonds at closing and are required to, 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 June 1, 2011.

Prior to closing, we paid the sellers an earnest money deposit of $6 million. The earnest money was applied against the purchase price. We financed the remainder of the purchase price and related expenditures with existing available cash and approximately $35 million in borrowings under our Credit Facility (as defined in Note 9), together with equity financing from our members.

In order to consummate this acquisition, we commenced a consent solicitation to amend the maximum capital expenditures provision of the Indenture governing our outstanding Notes. On May 31, 2011, we acquired the consents to (1) increase the amount of capital expenditures permitted by us on an annual basis, (2) enable us to obtain financial support from our majority equity holder in the amount of a $30 million investment, and (3) obligate us to make an offer to repurchase the Notes semi-annually at an offer price of 103% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest if we meet certain defined financial tests and as permitted by our credit facilities.

The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 31, 2011:

	(in thousands)
Oil and gas properties	$	149,454
Gas imbalances - receivable		1,487
Less:
Gas imbalances - payable		314
Asset retirement obligations		121,164
Cash paid	$	29,463

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

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Maritech Acquisition

On February 23, 2011, we acquired the Maritech Properties for a purchase price of $6 million before normal purchase price adjustments and the assumption of $12.8 million in asset retirement obligations related to P&A obligations associated with acquired properties. During the second quarter of 2011, we recorded an additional amount of P&A obligations of $13.0 million of which TETRA Technologies, Inc., the parent of Maritech Resources Incorporated, has guaranteed escrow accounts for certain fields in the amount of $20.3 million, which will not be refunded until the entire field is plugged and abandoned. The purchase included eight fields and added interest in an additional 108 gross wells and an estimated 46 thousand gross acres to our portfolio. Upon closing on the Maritech Acquisition in February 2011, we entered into an irrevocable letter of credit (“ILOC”) with Capital One, N.A., in the amount of $2.8 million related to P&A obligations for interests in properties acquired. In May 2011, a separate deposit account was created for collateral related to the ILOC, including an increase of $0.1 million based on evaluation by the surety company, and funds related to this ILOC were moved from restricted cash to escrow for abandonment costs.

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

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

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

Nippon Acquisition

On September 30, 2010, we acquired the Nippon Properties for a purchase price of $5 million before normal purchase price adjustments and the assumption of $57.4 million in asset retirement obligations related to P&A obligations associated with acquired properties. The Nippon Acquisition gave us an aggregate interest in 684 gross wells on 41 platforms located across 157 thousand gross acres offshore.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on September 30, 2010:

	(in thousands)
Oil and gas properties	$	35,989
Less:
Gas imbalances		2,041
Asset retirement obligations		57,416
Cash received	$	(23,468	)

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

Chroma Acquisition

On January 30, 2010, we acquired properties in the Gulf of Mexico, primarily located within Texas state waters from Chroma Oil & Gas, LP for a purchase price of $5 million before normal purchase price adjustments. The purchase included 6 fields and added interest in an additional 40 wells and an estimated 13 thousand gross acres to our portfolio.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on January 30, 2010:

	(in thousands)
Oil and gas properties	$	10,462
Less:
Asset retirement obligations		5,761
Cash paid	$	4,701

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

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W&T Acquisition

On October 29, 2009, we acquired the W&T Properties for a purchase price of approximately $25.6 million, net of acquisition costs, and the assumption of $46.6 million of non-current liabilities. The purchase included over 35 fields and 350 wells in water depths ranging up to 1,850 feet. The acquisition encompassed an estimated 195 thousand gross acres in the Gulf of Mexico. Also included in the transaction was interest in three processing plants, four separation facilities and thirteen export pipeline segments.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on October 29, 2009:

	(in thousands)
Oil and gas properties	$	71,080
Escrow for abandonment costs		1,607
Less:
Gas imbalances		510
Asset retirement obligations		46,621
Cash paid	$	25,556

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

Merit and Nippon Pro Forma Information

The following unaudited pro forma combined, condensed financial information for the years ended December 31, 2011 and 2010 was derived from our historical financial statements giving effect to the Merit Acquisition and the Nippon Acquisition as if they had occurred on January 1, 2010. These unaudited pro forma financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if we had completed the acquisitions as of January 1, 2010 or the results that will be attained in the future.

	Revenue		Earnings (1)
	(in thousands)		(in thousands)
Supplemental pro forma for January 1, 2011 through December 31, 2011	$	393,146	$	16,833
Supplemental pro forma for January 1, 2010 through December 31, 2010	$	299,626	$	3,065

(1) Earnings include revenues less lease operating expenses, exploration, marketing and transportation, workover, DD&A, accretion, and general and administrative expenses.

The revenues and earnings of the Merit Acquisition and the Nippon Acquisition included in our consolidated statements of operations for the year ended December 31, 2011 are as follows:

	Revenue		Earnings (1)
	(in thousands)		(in thousands)
Merit	$	69,156	$	14,855
Nippon	$	126,242	$	56,721

(1) Earnings include revenues less lease operating expenses, exploration, marketing and transportation, workover, DD&A, accretion, and general and administrative expenses.

The revenues and earnings of the Nippon Acquisition included in our consolidated statements of operations for the year ended December 31, 2010 are as follows:

	Revenue		Earnings (1)
	(in thousands)		(in thousands)
Nippon	$	23,230	$	11,467

(1) Earnings include revenues less lease operating expenses, exploration, marketing and transportation, workover, DD&A, accretion, and general and administrative expenses.

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NOTE 4—OIL AND GAS PROPERTIES

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

	At December 31,
	2011			2010
	(in thousands)
Proved properties	$	352,758		$	178,902
Unproved properties, not subject to depletion		—			—
Total Capitalized Costs		352,758			178,902
Accumulated depletion, depreciation, amortization and impairment		(114,056	)		(55,119	)
Oil and Natural Gas Properties, net	$	238,702		$	123,783

NOTE 5—ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Below are the components of accounts payable and accrued expenses:

	At December 31,
	2011		2010
	(in thousands)
Accounts payable - trade	$	33,341	$	10,825
Accrued operating expenses		32,383		18,500
Dividends payable		4,200		—
Interest payable		1,940		2,180
Other payables		4,645		2,606
	$	76,509	$	34,111

NOTE 6—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,
	2011			2010
	(in thousands)
Beginning of year	$	122,242		$	51,363
Liabilities incurred		147,442			62,911
Liabilities settled		(8,408	)		(1,207	)
Accretion expense		27,410			9,175
End of year	$	288,686		$	122,242

NOTE 7—DERIVATIVE INSTRUMENTS

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

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

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At December 31, 2011 and 2010, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss)):

		318,958		318,958		318,958			318,958			318,958		318,958		318,958		318,958		318,958			318,958
As of December 31, 2011
	Crude Oil										Natural Gas								Total
Period	Volume (Bbls)		Contract Price ($/Bbl)		Asset (Liability)			Fair  Value Gain (Loss)			Volume (MMBtu)		Contract Price ($/MMBtu)		Asset (Liability)		Fair  Value Gain (Loss)		Asset (Liability)			Fair  Value Gain (Loss)
					(in thousands)										(in thousands)				(in thousands)
Swaps:
1/12 - 10/12		23,000	$	96.90	$	(481	)	$	(481	)		227,000	$	4.60	$	3,679	$	3,679	$	3,198		$	3,198
11/12 - 11/12		22,080		96.90		(23	)		(23	)		—		—		—		—		(23	)		(23	)
12/12 - 12/12		23,000		96.90		(18	)		(18	)		—		—		—		—		(18	)		(18	)
1/13 - 10/13		27,750		96.90		234			234			104,000		4.60		800		800		1,033			1,033
11/13 - 11/13		26,800		96.90		60			60			—		—		—		—		60			60
12/13 - 12/13		27,750		96.90		71			71			—		—		—		—		71			71
1/14 - 2/14		19,000		96.90		115			115			82,000		4.60		30		30		145			145
1/12 - 12/12		17,050		81.22		(3,598	)		(3,598	)		—		—		—		—		(3,598	)		(3,598	)
1/12 - 12/12		1,900		81.14		(400	)		(400	)		112,000		5.00		2,356		2,356		1,956			1,956
1/12 - 7/12		—		—		—			—			5,250		5.89		102		102		102			102
1/12 - 7/12		200		83.50		(22	)		(22	)		53,000		5.70		961		961		939			939
8/12 - 12/12		—		—		—			—			53,000		5.70		597		597		597			597
1/12 - 12/12		27,500		85.90		(4,232	)		(4,232	)		26,838		5.89		849		849		(3,383	)		(3,383	)
1/12 - 5/12		22,125		100.80		174			174			318,958		4.94		2,993		2,993		3,168			3,168
6/12 - 6/12		22,125		100.80		33			33			303,880		4.94		532		532		565			565
7/12 - 7/12		12,048		100.80		21			21			106,638		4.94		180		180		201			201
8/12 - 8/12		8,296		100.80		17			17			90,586		4.94		150		150		166			166
9/12 - 9/12		3,998		100.80		9			9			56,141		4.94		92		92		101			101
10/12 - 10/12		1,884		100.80		5			5			41,462		4.94		66		66		71			71
11/12 - 11/12		—		—		—			—			2,951		4.94		4		4		4			4
12/12 - 12/12		15,140		100.80		47			47			106,375		4.94		124		124		171			171
1/13 - 6/13		15,542		100.80		382			382			200,669		4.94		1,279		1,279		1,661			1,661
7/13 - 7/13		7,132		100.80		37			37			148,788		4.94		150		150		186			186
8/13 - 8/13		5,980		100.80		32			32			139,212		4.94		137		137		170			170
9/13 - 9/13		3,897		100.80		22			22			116,125		4.94		114		114		136			136
10/13 - 10/13		3,259		100.80		19			19			91,166		4.94		86		86		105			105
11/13 - 11/13		—		—		—			—			64,926		4.94		54		54		54			54
12/13 - 12/13		10,041		100.80		64			64			119,462		4.94		74		74		137			137
1/14 - 5/14		10,083		100.80		357			357			129,960		4.94		395		395		752			752
6/14 - 6/14		—		—		—			—			129,960		4.94		88		88		88			88
1/13 - 12/13		19,750		85.90		(2,330	)		(2,330	)		47,000		5.00		585		585		(1,745	)		(1,745	)
1/14 - 12/14		15,000		65.00		(4,971	)		(4,971	)		—		—		—		—		(4,971	)		(4,971	)
					$	(14,377	)	$	(14,377	)					$	16,477	$	16,477	$	2,100		$	2,100

		318,958		318,958		318,958			318,958			318,958		318,958		318,958			318,958			318,958			318,958
As of December 31, 2010
	Crude Oil										Natural Gas										Total
Period	Volume (Bbls)		Contract Price ($/Bbl)		Asset (Liability)			Fair  Value Gain (Loss)			Volume (MMBtu)		Contract Price ($/MMBtu)		Asset (Liability)			Fair  Value Gain (Loss)			Asset (Liability)			Fair  Value Gain (Loss)
					(in thousands)										(in thousands)						(in thousands)
Swaps:
1/11 - 12/11		25,400	$	81.22	$	(3,821	)	$	(3,821	)		—	$	—	$	—		$	—		$	(3,821	)	$	(3,821	)
1/12 - 12/12		17,050		81.22		(2,587	)		(2,587	)		—		—		—			—			(2,587	)		(2,587	)
1/11 - 12/11		2,600		81.14		(393	)		(393	)		6,250		5.89		100			100			(293	)		(293	)
1/12 - 12/12		1,900		81.14		(290	)		(290	)		—		—		—			—			(290	)		(290	)
1/12 - 7/12		—		—		—			—			5,250		5.89		32			32			32			32
1/11 - 12/11		200		83.50		(24	)		(24	)		78,500		5.70		1,079			1,079			1,055			1,055
1/12 - 7/12		200		83.50		(15	)		(15	)		53,000		5.70		395			395			380			380
1/11 - 12//11		41,500		85.90		(3,912	)		(3,912	)		93,569		5.89		1,500			1,500			(2,412	)		(2,412	)
1/12 - 12/12		27,500		85.90		(2,629	)		(2,629	)		26,838		5.89		261			261			(2,368	)		(2,368	)
1/11 - 12/11		—		—		—			—			321,000		5.00		1,717			1,717			1,717			1,717
1/12 - 12/12		—		—		—			—			112,000		5.00		(107	)		(107	)		(107	)		(107	)
1/13 - 12/13		19,750		85.90		(1,646	)		(1,646	)		47,000		5.00		(188	)		(188	)		(1,834	)		(1,834	)
1/14 - 12/14		15,000		65.00		(4,928	)		(4,928	)		—		—		—			—			(4,928	)		(4,928	)
					$	(20,245	)	$	(20,245	)					$	4,789		$	4,789		$	(15,456	)	$	(15,456	)

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The following tables quantify the fair values, on a gross basis, of all of our derivative contracts and identifies the balance sheet locations as of December 31, 2011 and 2010 (in thousands):

	Asset Derivatives			Liability Derivatives
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at December 31, 2011		Balance Sheet Location	Fair Value at December 31, 2011
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	12,990	Current	$	(8,774	)
	Non-current		5,203	Non-current		(7,319	)
Total derivative instruments		$	18,193		$	(16,093	)
	Asset Derivatives			Liability Derivatives
Derivatives Not Designated as Hedging Instruments under Accounting Guidance	Balance Sheet Location	Fair Value at December 31, 2010		Balance Sheet Location	Fair Value at December 31, 2010
Commodity Contracts	Derivative financial instruments			Derivative financial instruments
	Current	$	4,396	Current	$	(8,150	)
	Non-current		687	Non-current		(12,389	)
Total derivative instruments		$	5,083		$	(20,539	)

NOTE 8—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, 2011 and 2010, 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, 2011 Using Fair Value Hierarchy
	Fair Value as of December 31, 2011			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	18,193		$	—	$	18,193		$	—
	$	18,193		$	—	$	18,193		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(16,093	)	$	—	$	(16,093	)	$	—
	$	(16,093	)	$	—	$	(16,093	)	$	—

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	Fair Value Measurements at December 31, 2010 Using Fair Value Hierarchy
	Fair Value as of December 31, 2010			Level 1		Level 2			Level 3
Assets
Oil and Natural Gas Derivatives	$	5,083		$	—	$	5,083		$	—
	$	5,083		$	—	$	5,083		$	—
Liabilities
Oil and Natural Gas Derivatives	$	(20,539	)	$	—	$	(20,539	)	$	—
	$	(20,539	)	$	—	$	(20,539	)	$	—

At December 31, 2011 and 2010, management estimates that the derivative contracts had a fair value of $2.1 million and ($15.5) 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, 2011, 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, 2011 was $178.1 million.

Fair Value on a Non-Recurring Basis

As of December 31, 2011, oil and gas properties with a carrying value of $251.7 million were written down to their fair value of $238.7 million, resulting in an impairment charge, which is recognized under “Impairments” in the consolidated statements of operations, of $13.0 million for the year ended December 31, 2011. As of December 31, 2010, oil and gas properties were written down to their fair value of $123.8 million from a carrying value of $130.2 million, a $6.4 million impairment charge. 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

NOTE 9—DEBT AND NOTES PAYABLE

Our debt and notes payable are summarized as follows:

	December 31, 2011			December 31, 2010
	(in thousands)
Senior Secured Revolving Credit Facility	$	24,000		$	—
13.75% Senior Secured Notes, net of discount		148,887			148,684
First Insurance - note payable		4,154			2,016
Synergy Bank - note payable		—			53
Total debt		177,041			150,753
Less: current portion		(4,154	)		(2,069	)
Total long-term debt	$	172,887		$	148,684

Senior Secured Revolving Credit Facility

On December 24, 2010 we entered into an aggregate $110 million Credit Facility comprised of a senior secured revolving credit facility of up to $35 million and a $75 million secured letter of credit to be used exclusively for the issuance of letters of credit in support of our future P&A liabilities relating to our oil and natural gas properties. The Credit Facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 2.75% to 3.5% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The applicable margin is computed based on the grid when the borrowing based utilization percentage is at its highest level. On May 31, 2011, we entered into an amendment to the Credit Facility, which increased the revolving credit facility available thereunder from $35 million to $70 million and the secured letter of credit from $75 million to $125 million, based primarily on the reserves provided by the Merit Acquisition. At December 31, 2011, we had an aggregate amount of $136.4 million of indebtedness outstanding under our Credit Facility, $112.4 million that was drawn as a letter of credit in support of our P&A obligations and $24.0 million of borrowings under the revolver. We currently have $58.6 million available for additional borrowing.

A commitment of 0.5% per annum is computed based on the unused borrowing base and paid quarterly. For the years ended December 31, 2011 and 2010, we recognized $0.2 million and $3,403 in commitment fees which have been included in “Interest expense” in 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 the proved oil and gas reserves. The borrowing base is re-determined semi-annually on or around April 1st and October 1st of each year. We and the administrative agent may each elect to cause the borrowing base to be re-determined one time between scheduled semi-annual redetermination periods.

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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 rate coverage ratio to be less than 3.0 to 1.0, or our current ratio (in each case as defined in our revolving Credit Facility) to be less than 1.0 to 1.0. In addition, we and our subsidiaries are subject to various covenants, including those limiting distributions and other payments, making certain investments, margin, consolidating, modifying certain agreements, transactions with affiliates, the incurrence of debt, changes in control, asset sales, liens on properties, sale leaseback transactions, entering into certain leases, the allowance of gas imbalances, take or pay or other prepayments. As of December 31, 2011, we were in compliance with all covenants.

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 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, on June 1 and December 1 of each year, in arrears, commencing 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, 2011 and 2010, the recorded value of the Notes was $148.9 million and $148.7 million, respectively, which includes the unamortized discount of $1.1 million and $1.3 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. In addition, within 90 days after December 2011 for which excess cash flow, as defined, exceeds $5.0 million to the extent permitted by our Notes, we will offer to purchase the Notes at an offer price equal to 100% of the aggregate principal amount of Notes repurchased plus accrued and 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 17) to consolidated leverage to be less than 1.4 to 1.0 as of the last day of each fiscal year. In addition, we and our subsidiaries are subject to various covenants, including restricted payments, incurrence of indebtedness and issuance of preferred stock, liens, dividends and other payments, merger, consolidation or sale of assets, transactions with affiliates, designation of restricted and unrestricted subsidiaries, and a maximum limit for capital expenditures. Our capital expenditures were not to exceed $30 million for the fiscal year ending December 31, 2011 and 25% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expenses for any fiscal year after. The capital expenditure requirement 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, 2011 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, 2011, we were in compliance with all covenants.

We were obligated to file a registration statement with the SEC to exchange these Notes for new publicly tradable notes having substantially identical terms within 180 days of the November 23, 2010 issue date and use reasonable efforts to have the registration statement declared effective within 270 days after the issue date. In May 2011, we prepared a Registration Statement on Form S-4, which was filed with the SEC. We amended the Form S-4 in June 2011 and it was declared effective by the SEC on July 18, 2011. The exchange offer was commenced on or about July 20, 2011 and expired on August 19, 2011, with all of the outstanding Notes being tendered.

First Insurance—Notes Payable

In 2010, we entered into two notes to finance annual insurance premiums related to our oil and natural gas properties for an aggregate $7.3 million. The notes bear interest at annual rates of 3.25% and 3.48% compounded monthly. At December 31, 2010, the total outstanding balance was $2.0 million which was paid off in 2011. During 2011, we entered into two notes to finance annual insurance premiums related to our oil and natural gas properties for an aggregate $19.0 million. The notes bear interest at annual rates of 2.06% compounded monthly. At December 31, 2011, the total outstanding balance was $4.2 million.

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Synergy Bank—Note Payable

In September of 2008, we entered into a $200,000 note bearing an interest rate of 6.5% due in September of 2011, collateralized by our barge. The note was repaid in full at maturity on September 28, 2011.

The amounts of required principal payments based on our outstanding debt amounts as of December 31, 2011, were as follows:

Year Ending December 31,	(in thousands)
2012	$	4,154
2013		24,000
2014		—
2015		150,000
		178,154
Unamortized discount on 13.75% Senior Secured Notes		(1,113	)
Total debt	$	177,041

NOTE 10—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, 2011, 2010 and 2009 of $0.5 million, $0.3 million and $0.1 million, respectively.

NOTE 11—MEMBERS’ EQUITY

The Member Agreement (the “Agreement”) has two 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.

On May 31, 2011, Platinum entered into a contribution agreement with us, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million units of our Class D Units, having such rights, preferences and privileges as set forth in our Second Amendment and Restated Operating Agreement, as amended. The Class D Units were issued in the name of Platinum’s wholly owned subsidiary, PPCA Black Elk (Equity) LLC.

The newly issued Class D Units are non-voting units having an aggregate liquidation preference of $30 million and accruing dividends payable in kind at a rate per annum of 24%. As of December 31, 2011, we have accrued dividends in the amount of $4.2 million that are included in “Members’ Equity (Deficit)” on the consolidated balance sheets.

At December 31, 2011, Platinum has contributed a total of $15.1 million in cash and $14.9 million remains in financial instruments deemed by us to be a cash equivalent.

NOTE 12—GAIN ON INVOLUNTARY CONVERSION

In June 2008, there was an extensive amount of well damage caused by a blowout. We had insurance coverage of $50 million, after a deductible of $500,000. The total costs incurred for well control, plug and abandonment, and re-drill costs were reimbursed by the insurance company as expenditures were incurred.

We accounted for the insurance proceeds in accordance with accounting guidance for gains and losses, conversions of nonmonetary assets to monetary assets, which requires that the difference between the cost of a nonmonetary asset that is involuntarily converted and the amount of monetary assets received is recognized in income as a gain or loss. Gain contingencies are not recognized until the period in which all contingencies are resolved or cash proceeds are received. The insurance recovery for the replacement cost of property damage in excess of book value is considered to be a gain contingency. As a result of the damages caused by the blowout and hurricane, we have recognized a gain from involuntary conversions for the period ended December 31, 2009 of $18.7 million after applying the insurance deductibles. No gains were recognized for the periods ended December 31, 2011 or 2010.

NOTE 13—RELATED PARTY TRANSACTIONS

We paid 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, 2011 and 2010, the amount due from the related party was $22,430 and $22,430, respectively.

We had loan agreements with our members, Plainfield Specialty Holdings II, Inc. and Gross Capital Management, which were paid off and retired in July 2009. Interest expense of $0.4 million was recorded for the year ended December 31, 2009.

We had two notes payable to affiliates of our member, Platinum, which were paid in full in November 2010. Interest expense and prepayment penalties totaling $1.2 million were recorded for the year ended December 31, 2010.

We had a line of credit with a member, Platinum, which was paid in full on November 23, 2010. Interest expense for the periods ended December 31, 2010 and 2009 was $8.1 million and $2.5 million, respectively.

During 2011, we entered into a contribution agreement with Platinum. See Note 11.

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During 2010, we loaned $1.0 million to Freedom Logistics LLC which was subsequently repaid in November 2010. At December 31, 2011, the interest receivable from the related party for the loan was $79,535. In October 2010, we guaranteed a loan in the aggregate principal amount of $3.2 million for the related party. As of December 31, 2011 and 2010, the balance of the loan was $3.0 and $3.2 million, respectively.

In April 2011, we entered into an arrangement with Freedom Well Services (“FWS”) to fund the purchase of start-up and equipment as a prepayment for services rendered with the expectation that the prepayment will be reimbursed as the business continues to grow and generate cash flows. As of December 31, 2011, we have advanced $6.6 million to FWS which is included in “Prepaid expenses and other” on our balance sheet.

For periods ended December 31, 2011, 2010 and 2009, we paid $1.0 million, $0.5 million and $10,396, respectively, to Up and Running Solutions, LLC, for IT consulting services. Up and Running Solutions, LLC is owned by the wife of an employee, David Cantu (a member of our management). At December 31, 2011 and 2010, the outstanding amount due to Up and Running Solutions, LLC was $72,222 and $0.1 million, respectively.

NOTE 14—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,
Customer	2011			2010			2009
Conoco Phillips Company		7	%		14	%		18	%
Shell Trading (US) Company		51	%		52	%		46	%
Katrina Energy, LLC		—			—			28	%

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 15—COMMITMENTS AND CONTINGENCIES

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

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

We lease office space and certain equipment under non-cancellable operating lease agreements that expire on various dates through 2020. On April 29, 2011, we entered into an amendment to the current office lease agreement for expansion to an additional floor with rental space of approximately 11,000 square feet. The move occurred in June 2011. The termination date of the agreement is December 31, 2020.

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Approximate future minimum lease payments for operating leases at December 31, 2011 were as follows:

Year Ending December 31,	(in thousands)
2012	$	2,692
2013		2,530
2014		2,160
2015		1,944
2016		1,789
Thereafter		6,124
	$	17,239

Rent expense of approximately $1.0 million, $0.5 million and $0.3 million was incurred under operating leases in the years ended December 31, 2011, 2010 and 2009, respectively.

Pursuant to the purchase agreement for the W&T Acquisition, we are required to fund the W&T Escrow Accounts, relating to the operating and non-operating properties that were acquired, respectively, in maximum aggregate principal amount of $63.8 million ($32.6 million operated and $31.2 million non-operated) for future P&A costs that may be incurred on such properties. 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 $32.6 million and the payment schedule for the Non-Operated Properties Escrow Account was amended and commenced on December 2011. As of December 31, 2011, we funded the non-operating escrow account in the amount of $9.3 million, leaving $21.9 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 has a first lien on the entirety of the W&T Escrow Accounts, and BP Corporation North America Inc. and Platinum are pari passu second lien holders. Once P&A obligations with respect to the interest in properties acquired from the W&T Acquisition have been fully satisfied, the lien on the W&T Escrow Accounts will be automatically extinguished. W&T also has a second priority lien with respect to the interest in properties acquired from the W&T Acquisition (with Platinum and BNP Paribas sharing a first priority lien), which lien will be released once the W&T Escrow Accounts have been fully funded.

Pursuant to the purchase agreement for the Maritech Acquisition, we are required to fund the Maritech Escrow Account relating to the properties that were acquired, the principal amount of $13.1 million for future P&A costs that may be incurred on such properties. As of December 31, 2011, we have funded $3.6 million, leaving $9.5 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 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, 2011, we have funded $14.0 million, leaving $46.0 million to be funded through November 2013.

NOTE 16—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, 2011 and 2010, 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, 2011 and 2010, we have not accrued interest or penalties related to uncertain tax positions.

Our tax years for fiscal years ended December 31, 2011, 2010, and 2009 are subject to examination in the United States and relevant state jurisdictions.

NOTE 17—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, 2011, 2010 and 2009:

	Year Ending December 31,
	2011		2010			2009
	(in thousands)
Oil and Gas Activities:
Exploration costs	$	1,004	$	14		$	47
Development costs		21,169		25,397			23,406
Acquisition costs		27,398		(19,164	)		25,726
Costs incurred	$	49,571	$	6,247		$	49,179

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 (MBbls)			Natural Gas (MMcf)			Total (MBOE)
Proved reserves at December 31, 2009		3,268			20,114			6,620
Purchases of minerals in place		4,600			37,021			10,770
Extensions and discoveries		1,067			11,242			2,941
Revisions of previous estimates		2,308			8,218			3,678
Production		(986	)		(7,997	)		(2,319	)
Proved reserves at December 31, 2010		10,257			68,598			21,690
Purchases of minerals in place		7,288			63,406			17,856
Extensions and discoveries		3,889			31,790			9,187
Revisions of previous estimates		972			4,787			1,770
Sales of reserves		—			—			—
Production		(2,283	)		(18,188	)		(5,314	)
Proved reserves at December 31, 2011		20,123			150,393			45,189
Proved developed reserves at December 31, 2011		11,829			83,324			25,716

None of our proved undeveloped reserves have been booked longer than five years.

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 (“SEC PV-10”).

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,
	2011		2010		2009
	(in thousands)
Future cash inflows	$	2,641,791	$	1,104,561	$	262,035
Future cost:
Production		714,076		318,974		77,828
Development		544,523		278,785		124,414
Future income taxes		—		11,591		1,615
Future net cash flows		1,383,192		495,211		58,178
10% annual discount for estimated timing of cash flows		321,784		103,022		14,992
Standardized measure of discounted future net cash flows	$	1,061,408	$	392,189	$	43,186

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

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Beginning of year:	$	392,189		$	43,186		$	15,424
Purchase of minerals in place		612,048			304,368			81,070
Extensions and discoveries and improved recovery, net of future production and development cost		314,920			83,105			—
Accretion of discount		34,238			1,903			838
Net change in sales prices net of production costs		112,923			27,605			1,922
Changes in estimated future development costs		(359,942	)		(123,154	)		(90,918	)
Previously estimated future development costs incurred		17,198			1,136			4,275
Revisions of quantity estimates		60,822			103,940			45,545
Sales, net of production costs		(131,500	)		(53,011	)		(10,746	)
Timing differences and other		8,512			3,111			(4,224	)
Net increase (decrease)		669,219			349,003			27,762
End of year	$	1,061,408		$	392,189		$	43,186

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.

NOTE 18—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, 2011
Total revenues	$	24,513		$	98,849	$	141,348		$	75,234
Loss (income) from operations		(18,196	)		39,888		58,352			(33,371	)
Net (loss) income		(24,119	)		28,046		51,114			(40,000	)
Net income (loss) attributable to commons unit holders		(24,119	)		28,046		49,314			(42,400	)
Year ended December 31, 2010
Total revenues	$	25,798		$	30,726	$	20,790		$	31,823
Loss (income) from operations		7,498			8,450		(3,155	)		(23,190	)
Net (loss) income		5,261			6,427		(6,042	)		(29,543	)
Net income (loss) attributable to commons unit holders		5,261			6,427		(6,042	)		(29,543	)

NOTE 19—SUBSEQUENT EVENTS

On February 23, 2012, we entered into the following swap transactions:

Remaining Contract Term: Oil	Contract Type		Notational Volume in Bbls/Month		NYMEX Strike Price
March 1, 2012 - March 31, 2012		Swap		61,170	$	102.40
April 1, 2012 - April 30, 2012		Swap		51,730	$	102.40
May 1, 2012 - May 31, 2012		Swap		45,340	$	102.40
June 1, 2012 - June 30, 2012		Swap		36,000	$	102.40
July 1, 2012 - July 31, 2012		Swap		21,110	$	102.40
August 1, 2012 - August 31, 2012		Swap		22,890	$	102.40
September 1, 2012 - September 30, 2012		Swap		20,930	$	102.40
October 1, 2012 - October 31, 2012		Swap		23,170	$	102.40
November 1, 2012 - November 30, 2012		Swap		19,290	$	102.40
December 1, 2012 - December 31, 2012		Swap		24,860	$	102.40
January 1, 2013 - January 31, 2013		Swap		43,510	$	102.40
February 1, 2013 - February 28, 2013		Swap		29,030	$	102.40
March 1, 2013 - March 31, 2013		Swap		35,760	$	102.40
April 1, 2013 - April 30, 2013		Swap		28,740	$	102.40
May 1, 2013 - May 31, 2013		Swap		28,540	$	102.40
June 1, 2013 - June 30, 2013		Swap		22,800	$	102.40
July 1, 2013 - July 31, 2013		Swap		14,700	$	102.40
August 1, 2013 - August 31, 2013		Swap		14,080	$	102.40
September 1, 2013 - September 30, 2013		Swap		12,390	$	102.40
October 1, 2013 - October 31, 2013		Swap		13,710	$	102.40
November 1, 2013 - November 30, 2013		Swap		14,320	$	102.40
December 1, 2013 - December 31, 2013		Swap		19,310	$	102.40
January 1, 2014 - January 31, 2014		Swap		30,600	$	102.40
February 1, 2014 - February 28, 2014		Swap		22,010	$	102.40
March 1, 2014 - March 31, 2014		Swap		45,910	$	102.40
April 1, 2014 - April 30, 2014		Swap		41,850	$	102.40
May 1, 2014 - May 31, 2014		Swap		42,530	$	102.40
June 1, 2014 - June 30, 2014		Swap		48,860	$	102.40
July 1, 2014 - July 31, 2014		Swap		36,680	$	102.40
August 1, 2014 - August 31, 2014		Swap		35,360	$	102.40
September 1, 2014 - September 30, 2014		Swap		32,290	$	102.40
October 1, 2014 - October 31, 2014		Swap		32,920	$	102.40
November 1, 2014 - November 30, 2014		Swap		30,000	$	102.40
December 1, 2014 - December 31, 2014		Swap		41,880	$	102.40

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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

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2011.

Changes in Internal Controls over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Internal Control over Financial Reporting

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by rules of the SEC for new registrants filing under to Section 15(d) of the Exchange Act.

Item 9B. Other Information.

None.

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 as of December 31, 2011. 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	53	President, Chief Executive Officer and Manager
James Hagemeier	43	Vice President, Chief Financial Officer and Manager
Doug Fehr	57	Vice President, Facilities
Arthur Garza	45	Chief Technical Officer
Carl Hammond	55	Chief Well Officer
Daniel Small	42	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, 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 Shelf 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 recently honored as a winner of Ernst & Young Entrepreneur of the Year Gulf Coast Area Award in 2011.

James Hagemeier. As one of our founders, James Hagemeier has served as our Vice President and Chief Financial 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. He is a licensed Texas CPA with more than 17 years of experience in various treasury, accounting and management roles with emphasis in M&A and raising and restructuring debt and equity. Prior to joining us, Mr. Hagemeier was the Chief Financial Officer for Perfect Commerce, a procurement and sourcing solutions company, from 2001

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through January 2008, where he raised roughly $50 million in debt and equity to fund the company’s operations and acquisition strategy. During his term at Perfect Commerce, the company used proceeds from the capital raised to purchase three entities which resulted in over 400% in net profit increases. Mr. Hagemeier has also served in leadership positions with Metals USA, Inc. and Schlumberger, Inc. where he was instrumental in establishing the financial controls, treasury and accounting processes. Further, Mr. Hagemeier was awarded the Best CFO for Best Growth Manager from the Houston Business Journal in 2011.

Doug Fehr. Doug Fehr serves as our Vice President of Facilities, a position he has held since May 2008. He brings 30 years of experience with specialties in facilities engineering, construction, project management, compliance, operations and safety. Prior to joining us, Mr. Fehr was employed at BP America Inc., a leading producer of oil and natural gas in the United States, as Technical Director from July 2006 to December 2007, where he was responsible for all aspects of operating a major pipeline system and marine terminal in Turkey. Prior to his position as Technical Director, he was the director for the Sangachal Terminal, the largest BP asset in Azerbaijan. Mr. Fehr has also managed BP’s field development of the deepwater NaKika semi-submersible, the King & Kings Peak subsea field development. He was Project General Manager for the Gulf of Suez Petroleum Company, a joint venture owned in equal shares by BP and The Egyptian General Petroleum Company, in Cairo, Egypt from September 2003 to July 2006 and Facilities Manager for the Gulf of Mexico from July 2000 to September 2003. In addition, he managed a special environmental compliance project for BP as they enhanced their ISO14001 certification process.

Arthur Garza. Arthur Garza serves as our Chief Technical Officer, a position he has held since October 2009. Mr. Garza has over 23 years of industry experience focused on exploitation of mature O&G fields. Prior to joining us, Mr. Garza held leadership positions at Hilcorp Energy Company, a privately-held exploration and production company, from July 2004 to September 2009 as GOM/Terrebonne Bay Senior Reservoir Engineer & Rockies Asset Team Manager. Mr. Garza’s extensive Gulf of Mexico experience while at Devon Energy Corporation, an independent natural gas and oil exploration and production company, from June 2002 to June 2004, Texaco Inc. from June 1994 to October 2001 and Mobil Oil Corporation from May 1992 to May 1994, span inland Louisiana, through shelf/flextrend (Green Canyon) and deepwater (Shasta, Nansen/Boomvang, Zia, Merganser). Mr. Garza’s career at Texaco included executive rotations through Strategic Planning, Power & Gasification and Project Finance. Mr. Garza participated in Texaco Reservoir Management Training Program and was a Qualified Reserves Estimator. Mr. Garza also has extensive waterflood and polymer flood experience. Mr. Garza holds a B.S./M.E. Petroleum Engineering from Texas A&M University and M.B.A. from University of Oklahoma.

Carl Hammond. Carl Hammond serves as our Chief Well Officer, a position he has held since November 2007. He is a current and active member of American Association of Drilling Engineers and Society of Petroleum Engineers and serves on committees for both professional organizations. Prior to joining us, Mr. Hammond consulted as a well-work specialist from 1995 to 2007. Mr. Hammond has over 30 years of experience and comprehensive knowledge of varied aspects of the petroleum industry, and his expertise extends to drilling, slickline, e-line, coil tubing, snubbing, well testing, fracture and acid stimulation, surface production equipment and pipeline installation. Mr. Hammond has held command over petroleum operations both on land and offshore, within state and federal waters. Having worked as a consultant for many years, Mr. Hammond understands all aspects of the industry, strategically planning efficient and proficient operational procedures, wellwork operations, and ensuring the proper personnel is on-hand for the respective projects. Mr. Hammond has supervised operations from the prospect phase through well abandonment and understands the full lifeline of an oil and natural gas field.

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 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 or before the named executive officer’s employment anniversary date each fiscal year, with such changes becoming effective as of the first day of the following month.

The named executive officers for our fiscal year ending December 31, 2011, and who are described in this Compensation Discussion and Analysis section, are:

• John Hoffman—President and Chief Executive Officer

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• James Hagemeier—Vice President and Chief Financial Officer

• Arthur Garza—Chief Technical Officer

• Carl Hammond—Chief Well Officer

• Doug Fehr—Vice President, Facilities

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 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.

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 his 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 for each named executive for the 2011 fiscal year is reported in the succeeding Summary Compensation Table. In 2011, Arthur Garza received a salary increase. All other officers were at their maximum annual compensation in 2011.

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. Bonuses can be paid based on any considerations the Committee deems appropriate, including, but not limited to, our growth and success, which may be measured at any point during the year through production levels, reserve growth, the achievement of strategic business goals, and financial metrics such as EBITDA. We do not set or communicate to our employees predetermined goals or metrics for the payment of our bonuses. 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 total amount of money set aside for the bonus pool 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 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. Currently, Mr. Garza is the only named executive officer whose offer letter includes a target bonus. Mr. Garza’s target bonus is 25% of his annual salary. Bonuses are prorated based on length of employment, to the extent applicable.

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 insure that our named executive officers’ bonus compensation is both reasonable and competitive, based on the Committee members’ experience in the industry.

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In 2011, cash bonuses were awarded to our named executive officers on July 29, 2011 and December 22, 2011. The July bonus was awarded for the successful completion of a strategic acquisition and for record production levels. The amount of the bonus pool was set by the Committee after considering the value added to us by the acquisition and the increased efforts of our executive team. The amount of each named executive officer’s July bonus was determined by the Committee after considering each executive’s contribution to a successful first half of the year. We awarded a cash bonus for 2011 performance at the end of December although Messrs. Hoffman and Hagemeier elected not to take a bonus as we did not achieve our financial targets. When setting the amount of the bonus pool for the year-end bonus, the Committee considered such election to forego any year-end bonus, our overall financial performance, and the achievement of business goals. Individual awards were set by the Committee after considering each of the remaining three named executive officer’s individual contribution to our success over the last year as well as the amount of their target bonus, to the extent applicable. Our Board of Managers approved the bonus pool amount. The cash bonuses awarded to each of our named executive officers is reported in the succeeding Summary Compensation Table.

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. During 2011, interests in these distributions were awarded through the Incentive Plan to each of our named executive officers. 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.

Severance and Change in Control Benefits

Messrs. Hoffman and Hagemeier have employment agreements with us that contain severance provisions and change in control payment provisions. Upon termination of Messrs. Hoffman or Hagemeier’s employment (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, 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.

We believe that severance protection provisions create important retention tools, as post-termination payments allow Messrs. Hoffman and Hagemeier 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 the best 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 Messrs. Hoffman and Hagemeier 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.

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, provide Mr. Fehr with enhanced disability insurance, and provide Messrs. Hoffman and Hagemeier with 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, we pay for the provision of tax preparation services for Messrs. Hoffman and Hagemeier.

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.

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• 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.

Actions taken after the 2011 Fiscal Year

No actions, nor updates, to policies and practices with regard to the named executive officers have been implemented after December 31, 2011.

Summary Compensation Table

The table below sets forth the annual compensation earned during the 2011 Fiscal Year by our “named executive officers,” as of December 31, 2011:

Name and Principal Position	Year	Salary ($)  (1)		Bonus ($)  (2)		Non-Equity Incentive Plan Compensation ($) (3)		All Other Compensation ($) (4)		Total ($)
John Hoffman, CEO	2011		300,000		270,000		1,722,232		82,327		2,374,559
James Hagemeier, CFO	2011		250,000		150,000		911,431		32,060		1,343,491
Arthur Garza, CTO	2011		250,000		120,000		272,959		24,469		667,428
Carl Hammond, CWO	2011		200,000		50,000		183,925		21,500		455,425
Doug Fehr, VPF	2011		250,000		63,000		200,938		37,060		550,998

(1) The amounts in this column reflect the base salary actually paid to each named executive officer during fiscal year 2011.

(2) The amounts in this column reflect the total amount of bonus compensation received by each named executive officer during fiscal year 2011. The amount of the bonuses paid to Messrs. Hoffman, Hagemeier, Garza, Hammond and Fehr on July 29, 2011 was $270,000, $150,000, $70,000, $30,000 and $32,000, respectively. The amount of the bonuses paid to Messrs. Garza, Hammond and Fehr on December 22, 2011 was $50,000, $20,000 and $31,000, respectively. Messrs. Hoffman and Hagemeier did not receive a bonus on December 22, 2011.

(3) The amounts in this column represent tax distributions received by each of the named executive officers for fiscal year 2011 with regard to forfeitable interests in Incentive LLC and Black Elk Energy, LLC, described in detail in the narrative 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 208, 112, 175, 100, and 125 units in Incentive LLC that Messrs. Hoffman, Hagemeier, Garza, Hammond and Fehr were granted during 2010, respectively and 170, 72, 10, 40, and 40 units in Black Elk Energy, LLC that Messrs. Hoffman, Hagemeier, Garza, Hammond and Fehr were granted prior to 2010, respectively. Messrs. Hoffman and Hagemeier also hold interests in us through Management Incentive Units 09 for 45 and 24 units, respectively, and Black Elk Management, LLC for 782 and 421 units, respectively. 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) kidnap/ransom insurance, (c) supplemental life and disability insurance, and (d) tax preparation. With respect to Mr. Hagemeier 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) kidnap/ransom insurance, and (c) tax preparation. With respect to Mr. Garza the amount in this column represents our contribution to his individual account under our 401(k) plan. With respect to Mr. Hammond the amount in this column represents our contribution to his individual account under our 401(k) plan. With respect to Mr. Fehr 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 and (b) supplemental disability insurance.

Grants of Plan-Based Awards for the 2011 Fiscal Year

We did not grant any plan-based awards to our executive officers during the 2011 fiscal year.

Narrative Description to the Summary Compensation Table for the 2011 Fiscal Year

Offer Letters

We entered into offer letters with Messrs. Garza (in 2009), Hammond (in 2007), and Fehr (in 2008) (the “Offer Letters”). The Offer Letters provide the following minimum levels of base salary for Messrs. Garza, Hammond, and Fehr respectively: $235,000; $150,000; and $250,000. The Offer Letters also provide that each named executive officer will be eligible to participate in our benefits programs generally. Mr. Garza’s offer letter includes a target annual bonus equal to 25% of his annual salary, but we have the discretion to pay or not pay any amount of bonus each year to each named executive officer. Messrs. Garza and Fehr’s offer letters also provide for approximate levels of interests in us that would be granted to them under programs preceding the Incentive Plan. Mr. Garza’s offer letter provides for four weeks of vacation each year. The Offer Letters do not provide for any specified term of employment.

Employment Agreements

We entered into our current employment agreements with Messrs. Hoffman and Hagemeier in 2009 (collectively, the “Employment Agreements”). The Employment Agreements provide for a three-year term, with no automatic renewal, and a base salary for Mr. Hoffman of $300,000 and for Mr. Hagemeier of $250,000. The Employment Agreements generally provide that each of the executives can participate in any welfare, benefit, or incentive plan generally available to our other executive officers. Both Messrs. Hoffman and Hagemeier are entitled to four weeks of vacation per year. The Employment Agreements also provide severance payments to the executives under certain circumstances, discussed in detail below in the section entitled “Potential Payments Upon Termination or a Change in Control.” The Employment Agreements also contain provisions assigning our business opportunities and any intellectual property developed by the executives while working for us to us. The Employment Agreements contain a non-compete obligation that applies throughout the executives’ 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. Messrs. Hoffman and Hagemeier also agree 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 Employment Agreements also contain non-disparagement and confidentiality obligations.

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Profit Sharing

The distributions enumerated in 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 Messrs. Hoffman and Hagemeier, 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 Black Elk Energy, 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

The Offer Letters with Messrs. Garza, Hammond and Fehr do not contain any severance provisions. We also do not have any formal severance policy or a change in control plan. There is no payment guaranteed to Messrs. Garza, Hammond and Fehr in the event of their termination of employment or a change in control. As such, they are not reflected in the table below.

The Employment Agreements with Messrs. Hoffman and Hagemeier contain severance provisions and change in control payment provisions. Upon termination of Messrs. Hoffman and Hagemeier’s employment (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, then the executive will be entitled to receive a lump-sum severance payment in an amount equal to one year’s annual base salary and company 401(k) contribution, plus continued medical, dental, vision, life and disability insurance coverage for one year.

The Employment Agreements provide 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 Employment Agreements which is not corrected within 30 days following written notice.

The Employment Agreements provide 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 payments that would have been due to Messrs. Hoffman and Hagemeier if their employment had been terminated on December 31, 2011, (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	$	95,835	$	395,835
James Hagemeier, CFO		250,000		47,197		297,197

(1) The numbers in this column represent each executive’s base salary in effect as of December 31, 2011.

(2) The numbers in this column represent a lump sum payment in an amount equal to our 401(k) contribution for a year ($32,850 for Mr. Hoffman and $27,500 for Mr. Hagemeier) as well as the value of medical, dental, vision, life and disability insurance coverage for one year ($62,985 for Mr. Hoffman and $19,697 for Mr. Hagemeier). 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 2011. Mr. Hoffman’s benefit cost is higher than Mr. Hagemeier’s because Mr. Hoffman receives additional life and disability insurance in excess of what Mr. Hagemeier receives.

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.

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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 D Units. As of March 15, 2012, there were 136.13 Class A Units, 10,934.585 Class B Units, 1,203.125 Class C Units and 30,000,000 Class D Units issued and outstanding. The Class A and Class B Units have voting rights; the Class C Units and Class D 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 D Units. All of our issued and outstanding Class A Units and Class D Units are owned by PPVA Black Elk (Equity) LLC, a wholly owned subsidiary of Platinum Partners Value Arbitrage Fund, L.P. Both PPVA Black Elk (Equity) LLC and PPVA Black Elk (Investor) LLC, an additional wholly owned subsidiary of Platinum Partners Value Arbitrage Fund, L.P., also own Class B 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 and Chief Financial Officer also indirectly own Class B Units through their ownership of Black Elk Management, LLC.

All of our issued and outstanding Class C Units are held by Black Elk Employee Incentive, LLC, profits interests which 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.

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 80% 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 May 31, 2011, Platinum entered into a contribution agreement with us, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million of our Class D Units, having such rights, preferences and privileges as set forth in our Second Amendment and Restated Operating Agreement, as amended. The Class D Units were issued in the name of Platinum’s wholly owned subsidiary, PPCA Black Elk (Equity) LLC.

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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”.

Freedom Logistics LLC

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 Messers. John Hoffman (our President and Chief Executive Officer), James Hagemeier (our Chief Financial Officer) and David Cantu (a member of our management), to hold two helicopters. We guaranteed the purchase of the two helicopters by Freedom in the aggregate principal amount of $3.2 million of which $3.0 million and $2.9 million was outstanding at December 31, 2011 and February 29, 2012, respectively. In 2010, Freedom had a master flight service agreement with Helicopter Services Inc. (“HSI”), a Houston-based Texas corporation which was terminated in 2011. Freedom then entered into a master flight service agreement with All American Aviation, LLC. (“AA Aviation”) which is located in Spring, Texas during 2011. Both HSI and AA Aviation specialize in charter operations. Pursuant to the terms of the respective lease agreements, HSI operated and AA Aviation will operate the helicopters in the ordinary course of business and we have first priority on the use of such operations. The entry into this arrangement and related matters, including the guarantee of the purchase of the helicopters and the loan, was approved by our full Board of Managers.

Freedom Well Services, LLC

In April 2011, Freedom Well Services, (“FWS”) was formed by us, certain members of our management, Freedom Well Services Employee Incentive, LLC and Platinum, our majority equity holder, to provide well P&A services, slick line and electronic line operations and platform decommissioning and removal consulting services. Although we did not contribute capital for start-up costs, we funded the purchase of start-up and equipment as a prepayment for services rendered with the expectation that the prepayment will be reimbursed as the business continues to grow and generate cash flows. The entry into this arrangement and related matters was approved by our full Board of Managers. As of December 31, 2011 and February 29, 2012, we have advanced $6.6 million and $7.6 million, respectively, to FWS which is included in “Prepaid expenses and other” on our balance sheet.

Black Elk Energy Expenses

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, 2011 and February 29, 2012, we had receivables from Black Elk Energy, LLC in the amount of $22,430.

For the years ended December 31, 2011, 2010 and 2009, we paid $1.0 million, $0.5 million and $10,396, respectively, to Up and Running Solutions, LLC, for IT consulting services. Up and Running Solutions, LLC is owned by the wife of an employee, David Cantu (a member of our management). At December 31, 2011 and February 29, 2012, the outstanding amount due to the related party was $72,222 and ($29,460), respectively.

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.

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, 2011 and 2010. 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:

	Year Ended December 31,
	2011		2010
Audit Fees (1)	$	399,999	$	598,803
Audit-Related Fees (2)		—		—
Tax Fees (3)		—		—
All Other Fees (4)		—		—
	$	399,999	$	598,803

(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, other SEC filings, and our bond offering in 2010.

(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.

UHY LLP personnel work under direct control of UHY LLP partners and are leased from wholly-owned subsidiaries of UHY Advisors, Inc. in an alternative practice structure.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

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

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

(2) 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.

(3) 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).
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	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. 333174226)).
4.6	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).

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4.7	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)).
4.8	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)).
4.9	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)).
4.10	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)).
4.11	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).
4.12	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)).
4.13	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)).
4.14	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)).
4.15	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)).
4.16	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)).
4.17	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)).
4.18	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)).
4.19	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)).

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4.20	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)).
4.21	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)).
4.22	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)).
4.23	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)).
4.24	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)).
4.25	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)).
4.26	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)).
4.27	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)).
4.28	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)).
10.1	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	Purchase and Sale Agreement between Nippon Oil Exploration USA Limited and Black Elk Energy Offshore Operations, LLC, dated as of August 5, 2010 (incorporated by reference to Exhibit 10.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.5	Amendment to Purchase and Sale Agreement, entered into as of September 30, 2010, by and between Nippon Oil Exploration USA Limited and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.6	Purchase and Sale Agreement, executed on March 17, 2011, by and between 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., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333174226)).
10.7	Amendment to Purchase and Sale Agreement, executed on March 30, 2011, by and between 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., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).

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10.8	Second Amendment to Purchase and Sale Agreement, executed on May 18, 2011, by and between 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., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.6 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).
10.9	Third Amendment to Purchase and Sale Agreement, executed on May 31, 2011, by and between 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., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.7 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011)).
†*10.10	Employment Agreement, dated as of July 13, 2009, by and between Black Elk Energy Offshore Operations, LLC and John G. Hoffman.
†*10.11	Employment Agreement, dated as of July 13, 2009, by and between Black Elk Energy Offshore Operations, LLC and James F. Hagemeier.
10.12	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)).
10.13	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)).
†*10.14	Amended and Restated Company Agreement of Black Elk Employee Incentive, LLC, dated as of August 20, 2010.
*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 and Associates, Inc.
*31.1	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*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-Q. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

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SIGNATURES

Pursuant to the requirements of 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/ James Hagemeier
	James Hagemeier
	Vice President, Chief Financial Officer and Manager

March 26, 2012

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         John Hoffman	President, Chief Executive Officer and Manager (Principal Executive Officer)	March 26, 2012
/s/    James Hagemeier         James Hagemeier	Vice President, Chief Financial Officer and Manager (Principal Financial Officer and Principal Accounting Officer)	March 26, 2012
/s/    Daniel Small         Daniel Small	Manager	March 26, 2012

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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).
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	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. 333174226)).
4.6	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).
4.7	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)).
4.8	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)).
4.9	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)).

4.10	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)).
4.11	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).
4.12	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)).
4.13	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)).
4.14	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)).
4.15	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)).
4.16	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)).
4.17	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)).
4.18	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)).
4.19	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)).
4.20	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)).
4.21	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)).
4.22	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)).

4.23	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)).
4.24	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)).
4.25	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)).
4.26	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)).
4.27	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)).
4.28	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)).
10.1	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	Purchase and Sale Agreement between Nippon Oil Exploration USA Limited and Black Elk Energy Offshore Operations, LLC, dated as of August 5, 2010 (incorporated by reference to Exhibit 10.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.5	Amendment to Purchase and Sale Agreement, entered into as of September 30, 2010, by and between Nippon Oil Exploration USA Limited and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)).
10.6	Purchase and Sale Agreement, executed on March 17, 2011, by and between 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., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333174226)).
10.7	Amendment to Purchase and Sale Agreement, executed on March 30, 2011, by and between 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., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).
10.8	Second Amendment to Purchase and Sale Agreement, executed on May 18, 2011, by and between 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., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.6 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011).
10.9	Third Amendment to Purchase and Sale Agreement, executed on May 31, 2011, by and between 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., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.7 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011)).

†*10.10	Employment Agreement, dated as of July 13, 2009, by and between Black Elk Energy Offshore Operations, LLC and John G. Hoffman.
†*10.11	Employment Agreement, dated as of July 13, 2009, by and between Black Elk Energy Offshore Operations, LLC and James F. Hagemeier.
10.12	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)).
10.13	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)).
†*10.14	Amended and Restated Company Agreement of Black Elk Employee Incentive, LLC, dated as of August 20, 2010.
*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 and Associates, Inc.
*31.1	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*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-Q. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.