Amendment No. 1 to Form S-4

Exact Name of Registrant Guarantor as Specified in Its Charter

State or Other
Jurisdiction of
Incorporation or
Formation

Primary Standard
Industrial
Classification Code
Number

IRS Employer
Identification
Number

Black Elk Energy Land Operations, LLC⁽¹⁾

And the additional registrant listed on the “Table of Additional Registrant Guarantors” herein

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. ¨

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If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

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.

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Each registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

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The information in this Prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This Prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offering is not permitted.

Terms of the New 13.75% Senior Notes due 2015 Offered in the Exchange Offer:

You should carefully consider the risk factors beginning on page 13 of this Prospectus before participating in the Exchange Offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this Prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Index to Financial Statements

In this Prospectus, references to “Black Elk,” the “Company,” “our company,” “we,” “our” and “us” refer to Black Elk Energy Offshore Operations, LLC and its wholly owned subsidiaries, Black Elk Energy Finance Corp., a Texas limited liability company and the co-issuer of the notes, and Black Elk Energy Land Operations, LLC, a Texas limited liability company and a guarantor of the notes, unless otherwise indicated or the context otherwise requires. All references to the “Issuers” refer solely to Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp., and all references to the “guarantors” refer to Black Elk Energy Land Operations, LLC and each other subsidiary of Black Elk Energy Offshore Operations, LLC that may in the future guarantee amounts outstanding on the notes on a joint and several basis.

In this Prospectus, we refer to the notes to be issued in the Exchange Offer (herein so called) as the “new notes” and we refer to the $150 million principal amount of our outstanding 13.75% Senior Secured Notes due 2015 issued on November 3, 2010 as the “old notes.” We refer to the new notes and the old notes collectively as the “notes.”

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This Prospectus is part of a registration statement on Form S-4 that we have filed with the Securities and Exchange Commission (the “SEC”). This Prospectus does not contain all of the information found in the registration statement. Before you decide to participate in this Exchange Offer, please review the full registration statement, including the information set forth under the heading the “Risk Factors” in this Prospectus, the documents described under the heading “Additional Information” in this Prospectus, the exhibits to the registration statement and any additional information you may need to make your investment decision. You should rely only on the information contained in the registration statement, including this Prospectus and the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information and if anyone provides you with different or inconsistent information, you should not rely on it. You should not assume that the information contained in this Prospectus is accurate as of any date other than its respective date as set forth on the front cover. Our business, financial condition, results of operations and prospects may have changed since that date. We will disclose any material changes in our affairs in an amendment to this Prospectus or a Prospectus supplement.

Each broker-dealer that receives new notes for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a Prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a Prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”). This Prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of the Exchange Offer, we will make this Prospectus, as it may be amended or supplemented from time to time, available to any broker-dealer for use in connection with any such resale. Please read “Plan of Distribution.”

We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation.

We are not making any representation to you regarding the legality of your participation in the Exchange Offer under applicable law. You should consult with your own legal advisors as to the legal, tax, business, financial and related aspects of participating in the Exchange Offer.

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This Prospectus contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements that relate to, among other things, our:

All statements, other than statements of historical fact included in this Prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” in this Prospectus.

Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from the anticipated future results or financial condition expressed or implied by the forward-looking statements. These risks, uncertainties and other factors include, but are not limited to:

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Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

Should one or more of the risks or uncertainties described in this Prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statement.

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All forward-looking statements, expressed or implied, included in this Prospectus 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 factor, or combination of factors, may cause actual results to be materially different from those contained in any forward-looking statement.

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PROSPECTUS SUMMARY

This summary highlights certain information about us and the Exchange Offer. Because this is a summary, it may not contain all of the information that may be important to you and your investment decision. The following summary is qualified in its entirety by reference to the more detailed information and financial statements and notes thereto included elsewhere in this Prospectus. You should read this entire Prospectus and the documents to which we refer you carefully and should consider, among other things, the matters set forth in “Risk Factors” and the other cautionary statements described in this Prospectus before making an investment decision. In addition, certain statements contained in this Prospectus include forward-looking information that involves many risks and uncertainties, including but not limited to those discussed under “Cautionary Note Regarding Forward-Looking Statements.”

The estimates of our proved reserves as of December 31, 2010 included in this Prospectus are based on the reserve report dated January 26, 2011 (the “NSAI Report”) of Netherland, Sewell & Associates, Inc., independent petroleum engineers (“NSAI”), using SEC pricing based on the average price as of the first day of each of the twelve months ended December 31, 2010. A summary of the NSAI Report is attached as an exhibit to the registration statement of which this Prospectus constitutes a part. This Prospectus also includes the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC and Financial Accounting Standards Board (“FASB”), less future development and production, expenses and discounted at 10% per annum to reflect the timing of future net revenue, which is referred to herein as the “PV-10.” Although PV-10 is a non-U.S. GAAP financial measure that excludes the effects of income taxes, because we are classified as a “partnership” for federal income tax purposes and therefore not subject to income taxes, PV-10 is equivalent to the standardized measure of discounted future net cash flows as defined under U.S. GAAP, which we refer to as the “standardized measure” as represented in our financial statements. See “Supplemental Oil and Gas Disclosures.” 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. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties.

For the definitions of certain terms used in the oil and natural gas industry, see “Glossary of Oil and Natural Gas Terms.”

The Company

Overview

We are a privately held 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 Texas 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 have made strategic decisions to deemphasize their offshore operations. In addition to our acquisition strategy, we continue to develop and 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, 2010, our leasehold position encompassed approximately 155,800 net (384,800 gross) acres, 245 net (694 gross) wells and 133 production platforms. As of December 31, 2010, we had estimated total proved oil and natural gas reserves of 21.7 MMBoe (47% oil) with a PV-10 value of $392 million based on the NSAI Report. See “Supplemental Oil and Gas Disclosures” for additional information regarding our proved reserves at December 31, 2010. For 2010, our net daily production averaged approximately 6,353 Boepd.

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Recent Developments

On May 31, 2011, we acquired from certain private sellers interests in various properties across approximately 250,126 gross (127,894 net) acres in the Gulf of Mexico for a purchase price of $39 million plus the assumption of approximately $168.4 million (based on current estimates) of undiscounted asset retirement obligations related to plugging and abandonment (“P&A”) obligations associated with the acquired properties, subject to customary effective-date adjustments and closing adjustments (the “Merit Acquisition”).

At closing, we paid $33 million in surety bonds and established 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 are required to deposit into such escrow account an aggregate principal amount equal to $60 million, which is to be paid by us in 30 equal monthly installments, payable on the first day of each month, commencing on the first day of the month following closing.

Concurrently with the execution of the purchase agreement for these interests, we paid the sellers an earnest money deposit of $6 million, which was applied against the purchase price at closing. We financed the remainder of the purchase price with existing available cash and borrowings under our credit facility, together with equity financing from our majority equity holder, Platinum Partners Value Arbitrage Fund L.P., and/or its affiliates (collectively “Platinum”). We borrowed approximately $35 million under the credit facility at closing to fund a portion of the purchase price.

The indenture, dated as of November 23, 2010, among the us, the subsidiary guarantor party thereto and The Bank of New York Mellon Trust Company, N. A., as trustee (the “Indenture”), under which the old notes were issued and the new notes will be issued, restricted our ability to finance the remainder of the purchase price and complete the acquisition. Accordingly, we conducted a consent solicitation and obtained from the holders of the old notes the consents necessary to approve certain amendments to the Indenture, to, among other things, allow us to finance the Merit Acquisition. On May 31, 2011, we entered into a supplement to the Indenture (the “First Supplemental Indenture”) with our subsidiary guarantor and the Trustee in order to effect the proposed amendments to the Indenture.

Preferred Equity Contribution

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 Preferred Units (the “Class D Units”), having such rights, preferences and privileges as set forth in our Second Amendment and Restated Operating Agreement, as amended. The Class D Units were issued in the name of Platinum’s wholly owned subsidiary, PPCA Black Elk (Equity) LLC.

Capital One Credit Facility

On December 24, 2010, we entered into an aggregate $110 million of credit facilities with Capital One, N.A., as administrative agent and a lender thereunder. The credit facility is comprised of a (i) $35 million senior secured revolver and (ii) $75 million secured letter of credit facility, which is to be used exclusively for the issuance of letters of credit in support of our P&A obligations relating to our oil and gas properties. 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.

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As of June 15, 2011, we had an aggregate amount of $72.3 million of indebtedness outstanding under our credit facility, $27.3 million of which was drawn as letters of credit and $45.0 million of borrowings under the revolver. As of June 15, 2011, $122.7 million is available for additional borrowings, including $25 million under the revolver.

Concurrent with closing of the Merit Acquisition, we entered into an amendment to the credit facility to, among other things, increase the borrowing base under the revolver based on the reserves provided by the acquired assets.

See “Description of Other Indebtedness—Capital One Credit Facility” for additional information with respect to our credit facility.

Organizational Structure and General Corporate Information

Black Elk Energy Offshore Operations, LLC, a Texas limited liability company, currently has two wholly owned subsidiaries: Black Elk Energy Finance Corp., a Texas corporation and the co-issuer of the notes, and Black Elk Energy Land Operations, LLC, a Texas limited liability company and a guarantor with respect to the notes. Neither Black Elk Energy Land Operations, LLC nor Black Elk Energy Finance Corp. has any material assets or operations. Black Elk Energy Finance Corp. was formed for the sole purpose of co-issuing certain indebtedness of Black Elk Energy Offshore Operations, LLC, including the notes.

Our principal executive offices are located at 11451 Katy Freeway, Suite 500, Houston, Texas, 77079 and the phone number at that address is (281) 598-8600. Our website address is www.blackelkenergy.com. We will make our periodic reports and other information that we will be required to file with or furnish to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information contained on or accessible through our website or about us on any other website is not incorporated by reference into this Prospectus and does not constitute a part of this Prospectus.

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The Exchange Offer

The following summary contains basic information about the Exchange Offer and is not intended to be complete. It does not contain all information that may be important to you. For a more complete understanding of the Exchange Offer, please refer to the section entitled “Exchange Offer” in this Prospectus.

On November 23, 2010 (the “Issue Date”), we completed a private placement of $150 million in aggregate principal amount of 13.75% Senior Secured Notes due 2015 (which are referred to herein as the “old notes”) in an offering exempt from the registration requirements of the Securities Act (the “Senior Notes Offering”). The old notes were issued under the Indenture, and the new notes will be issued, under the Indenture, as amended by the First Supplemental Indenture. At closing of the Senior Notes Offering, we entered into a registration rights agreement dated November 23, 2010 (the “Registration Rights Agreement”) with the placement agents with respect to the Senior Notes Offering, on behalf of the initial purchasers of the old notes, in which we agreed to file this Prospectus and the registration statement of which it forms a part with the SEC by May 23, 2011, to deliver the same to you, and to use our reasonable best efforts to cause the registration statement to become effective by August 20, 2011. We have now met those obligations.

Exchange Offer

We are offering to exchange up to $150 million of our old notes that have not been registered under the Securities Act for an equal principal amount of new notes with substantially identical terms, except that such new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest.

Expiration Date

The Exchange Offer will expire at 5:00 p.m., New York City time, on , 2011, unless we decide to extend it (such date and time, as may be extended from time to time, the “Expiration Date”).

Condition to the Exchange Offer

The Registration Rights Agreement does not require us to accept old notes for exchange if the Exchange Offer, or the making of any exchange by a holder of old notes, would violate any applicable law or interpretation of the SEC.

The Exchange Offer is not conditioned on a minimum aggregate principal amount of old notes being tendered.

Procedures for Tendering Old Notes

If you hold old notes in book-entry form through The Depository Trust Company (the “DTC”), in order to participate in the Exchange Offer you must follow the procedures established by the DTC for tendering notes held in book-entry form. These procedures, referred to as the Automated Tender Offer Program (“ATOP”), require that (i) the Exchange Agent receive, prior to the Expiration Date, a computer generated message known as an “agent’s message” that is transmitted through DTC’s automated tender offer program, and (ii) DTC confirms that:

•

DTC has received your instructions to exchange your old notes; and

•

you agree to be bound by the terms of the letter of transmittal.

For more information on tendering your old notes, please refer to the section in this Prospectus entitled “The Exchange Offer.”

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Guaranteed Delivery Procedures

None.

Withdrawal of Tenders

You may withdraw your tender of old notes at any time prior to the Expiration Date. To withdraw, you must submit a notice of withdrawal to the Exchange Agent using ATOP procedures before the Expiration Date of the Exchange Offer. Please refer to the section in this Prospectus entitled “The Exchange Offer—Withdrawal of Tenders.”

Acceptance of Old Notes and Delivery of New Notes

If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the Exchange Offer before the Expiration Date. We will return any old notes that we do not accept for exchange to you without expense promptly after the Expiration Date and acceptance of the old notes for exchange. Please refer to the section in this Prospectus entitled “The Exchange Offer—Terms of the Exchange Offer.”

Fees and Expenses

We will bear expenses related to the Exchange Offer. Please refer to the section in this Prospectus entitled “The Exchange Offer—Fees and Expenses.”

Use of Proceeds

The issuance of the new notes will not provide us with any new proceeds. We are making this Exchange Offer solely to satisfy our obligations under the Registration Rights Agreement.

Consequences of Failure to Exchange Old Notes

If you do not exchange your old notes in this Exchange Offer, you will no longer be able to require us to register the old notes under the Securities Act except in limited circumstances provided under the Registration Rights Agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

U.S. Federal Income Tax Consequences

The exchange of new notes for old notes in the Exchange Offer will not be a taxable event for U.S. federal income tax purposes. Please refer to the section in this Prospectus entitled “Certain United States Federal Income Tax Consequences.”

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Exchange Agent

We have appointed The Bank of New York Mellon Trust Company, N.A. as exchange agent for the Exchange Offer (the “Exchange Agent”). You should direct questions and requests for assistance and requests for additional copies of this Prospectus or the letter of transmittal to the Exchange Agent addressed as follows:

The Bank of New York Mellon Trust Company, N. A.

c/o Bank of New York Mellon Corporation

Corporate Trust Operations

Reorganization Unit

480 Washington Boulevard - 27th Floor

Jersey City, New Jersey 07310

Attn: William Buckley

Telephone: (212) 815-5788

Facsimile: (212) 298-1915

Eligible institutions may make requests by facsimile at (212) 298-1915 and may confirm facsimile delivery by calling (212) 815-5788.

Risk Factors

You should carefully consider the information set forth in the section in this Prospectus entitled “Risk Factors” beginning on page 13 and all other information in this Prospectus in evaluating whether or not to tender your old notes in the Exchange Offer.

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Terms of the New Notes

The following summary contains basic information about the new notes and is not intended to be complete. It does not contain all information that may be important to you. For a more complete understanding of the new notes, please refer to the section entitled “Description of Notes” in this Prospectus.

The new notes will be identical to the old notes except that the new notes are registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest. The new notes will evidence the same debt as the old notes, and the same Indenture will govern the new notes and the old notes.

Issuers

Black Elk Energy Offshore Operations, LLC and its wholly owned subsidiary, Black Elk Energy Finance Corp. Black Elk Energy Finance Corp. has no material assets and was formed for the sole purpose of co-issuing certain of Black Elk Energy Offshore Operations, LLC’s indebtedness, including the notes.

Securities Offered

$150.0 million aggregate principal amount of the 13.75% Senior Secured Notes due 2015.

Maturity Date

December 1, 2015.

Interest

We will pay interest in cash on the principal amount of the new notes at an annual rate of 13.75%. We will pay interest on the new notes semi-annually, in arrears, on each June 1 and December 1, commencing on June 1, 2011.

Guarantees

Currently, Black Elk Energy Offshore Operations, LLC has only one subsidiary, Black Elk Energy Land Operations, LLC, other than the co-issuer. The new notes will be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by Black Elk Energy Land Operations, LLC and by each of Black Elk Energy Offshore Operations, LLC’s future restricted subsidiaries that guarantees indebtedness under our credit facility. The guarantees will rank senior in right of payment to all existing and any future senior subordinated indebtedness of these subsidiaries and equal in right of payment with all existing and future senior secured indebtedness of these subsidiaries.

Collateral

The new notes and the guarantees will be secured by a security interest in the Issuers’ and the Guarantors’ assets (excluding the two escrow accounts (collectively, the “W&T Escrow Accounts”) that we established to secure our P&A obligations with respect to certain properties that we acquired from W&T Offshore, Inc. (“W&T”) in October 2009 (see “Description of Other Indebtedness—W&T Escrow Accounts”)) to the extent they constitute collateral under our credit facility, subject to certain exceptions. The W&T Escrow Accounts are currently pledged on a first lien basis to W&T and on a second lien basis to the lenders under our credit facility and our derivatives contracts counterparty. We are not able to grant additional liens on such assets without the consent of W&T, which it has no

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obligation to do. See “Risk Factors—Risks Related to the Notes—The collateral for the notes does not include the W&T Escrow Accounts that secure our P&A obligations with respect to the W&T Properties.”

Additionally, the liens securing the new notes will be subordinated and junior to the liens securing our credit facility and our derivative contracts pursuant to the terms of an intercreditor agreement to the extent of the value of the collateral securing such first lien obligations. See “Description of Notes—Collateral” and “Description of Notes—Intercreditor Agreement.”

Ranking

The new notes will be our senior secured obligations. The new notes and the guarantees will rank senior in right of payment to all of our and each guarantor’s future subordinated indebtedness and equal in right of payment with all of our and each guarantor’s existing and future senior indebtedness, including indebtedness under our credit facility and our derivatives contracts obligations. The new notes and the guarantees will be effectively subordinated, however, to indebtedness under our credit facility, our derivatives contracts obligations, and any additional permitted first lien indebtedness to the extent of the value of the collateral securing such indebtedness under our credit facility, our derivatives contracts obligations and such additional permitted first lien indebtedness.

Optional Redemption

Until December 1, 2013, 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.

On or after 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 plus accrued and unpaid interest to the date of 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.

We may also redeem some or all of the notes at any time prior to December 1, 2013 at the “make-whole” prices described in this Prospectus.

Change of Control Offer

If we experience a change in control, the holders of the notes will have the right to require us to purchase their notes at a price in cash equal to 101% of the principal thereof, plus accrued and unpaid interest, if any, to the date of repurchase.

Asset Sale Offer

Upon certain asset sales, we may have to use the proceeds to offer to repurchase notes at an offer price in cash equal to 100% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase.

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Excess Cash Flow Offer

Within 90 days after the end of each of our second and fourth fiscal quarters, commencing at the end of the fourth quarter of 2011, for which our Excess Cash Flow (as defined in the Indenture) for such prior six-month period exceeds $2.5 million, to the extent permitted by our credit facilities we will offer to purchase notes for cash in an aggregate amount equal to the Excess Cash Flow Offer Amount (as defined in the Indenture) at a price of 103% of their principal amount plus accrued and unpaid interest to the date of repurchase, with the amount to be repurchased subject to proration if the aggregate principal amount of notes tendered in the offer exceeds the Excess Cash Flow Offer Amount. See “Description of Notes—Certain Covenants—Excess Cash Flow.”

Certain Indenture Covenants

The Indenture under which the new notes will be issued contains covenants that, among other things, limit our ability to:

•

incur or guarantee additional indebtedness or issue certain preferred securities;

•

pay dividends, repurchase equity securities, redeem subordinated debt or make investments or other restricted payments;

•

issue capital stock of our subsidiaries;

•

transfer or sell assets, including capital stock of our subsidiaries;

•

incur dividend or other payment restrictions affecting certain of our subsidiaries;

•

create or incur liens;

•

change our line of business;

•

make capital expenditures;

•

enter into certain transactions with affiliates;

•

merge, consolidate or transfer substantially all of our assets; and

•

retire any of our preferred stock issued to Platinum.

These covenants are subject to a number of important limitations and exceptions. See “Description of Notes—Certain Covenants.”

Transfer Restrictions; Absence of a Public Market for the New Notes

The new notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the new notes. We do not intend to apply for a listing of the new notes on any securities exchange or any automated dealer quotation system.

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SUMMARY HISTORICAL FINANCIAL DATA

The following table presents summary historical financial information for the periods and as of the dates indicated. The summary statement of operations data for the period from Inception (January 29, 2008) through December 31, 2008 and each of the two years ended December 31, 2009 and 2010, and the balance sheet data as of December 31, 2008, 2009 and 2010 have been derived from our audited financial statements for such periods included elsewhere in this Prospectus. The summary statement of operations data for the three months ended March 31, 2010 and 2011 and balance sheet data as of March 31, 2011 are derived from our unaudited consolidated financial statements included elsewhere in this Prospectus.

The summary unaudited pro forma financial data presented in the following table as of and for the three months ended March 31, 2011 and as of and for the year ended December 31, 2010 are derived from the unaudited pro forma financial statements included elsewhere in this Prospectus. As indicated below, the pro forma financial information for the three months ended March 31, 2011 and for the year ended December 31, 2010 gives effect to the Nippon Acquisition and the Merit Acquisition as if such transactions had occurred on January 1, 2010. The pro forma financial data is not comparable to our historical financial data. A more complete explanation of the pro forma data can be found in our unaudited pro forma condensed consolidated financial statements and accompanying notes included elsewhere in this Prospectus.

The summary unaudited consolidated financial data has been prepared on a consistent basis with our audited consolidated financial statements. In the opinion of management, the summary unaudited consolidated financial data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented.

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For further information that will help you better understand this summary, you should read the information presented below in conjunction with “Selected Financial and Other Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes and other financial information included elsewhere in this Prospectus.


	Three Months Ended March 31,						Year Ended December 31,						Period from Inception (January 29, 2008) through December 31, 2008			Pro Forma Three Months Ended March 31, 2011			Pro Forma Year Ended December 31, 2010
	2011			2010			2010			2009						Pro Forma Three Months Ended March 31, 2011			Pro Forma Year Ended December 31, 2010
	(Unaudited)															(Unaudited)
STATEMENTS OF OPERATIONS DATA (in thousands):
Crude oil, natural gas and plant product sales	$	55,827		$	23,331		$	112,565		$	20,788		$	13,024		$	87,281		$	303,055
Realized (loss) gain on derivative financial instruments		(336	)		1,714			9,271			801			—			(336	)		9,271
Unrealized (loss) gain on derivative financial instruments		(30,978	)		753			(12,700	)		(2,756	)		—			(30,978	)		(12,700	)

Total revenue		24,513			25,798			109,136			18,833			13,024			55,967			299,626

Operating Expenses:
Lease operating costs, workovers and production taxes		26,252			7,335			59,555			10,042			9,995			47,980			161,408
Exploration		—			476			14			47			79			—			14
Depreciation, depletion and amortization		7,994			6,630			29,795			15,419			3,316			12,359			55,266
Impairment		—			—			6,407			446			—			—			6,406
General and administrative		4,525			2,027			14,588			7,164			3,377			5,125			18,902
Gain due to involuntary conversion of asset		—			—			—			(18,718	)		(9,526	)		—			—
Accretion		3,938			1,832			9,175			388			422			4,850			18,074

Total operating expenses		42,709			18,300			119,534			14,788			7,663			70,314			260,070

Income (loss) from operations	$	(18,196	)	$	7,498		$	(10,398	)	$	4,045		$	5,361		$	(14,347	)	$	39,556

Operating Data:
Oil (MBbl)⁽¹⁾		376			183			857			140			36			532			1,927
Natural gas (MMcf)⁽¹⁾		3,345			1,516			7,997			2,444			1,068			6,651			29,583
Plant products (Gal)		2,138			521			5,403			320			—			4,592			17,260

Oil:
Average price before effects of hedges ($/Bbl)	$	99.49		$	75.98		$	80.09		$	70.43		$	99.51			N/A			N/A
Average price after effects of hedges ($/Bbl)		93.15			77.31			80.97			71.59			99.51			N/A			N/A
Average price differentials		5.03			(2.86	)		0.59			8.44			(0.41	)		N/A			N/A

Natural Gas:
Average price before effects of hedges ($/Mcf)	$	4.52		$	5.34		$	4.38		$	4.29		$	8.87			N/A			N/A
Average price after effects of hedges ($/Mcf)		5.13			6.31			5.44			4.55			8.87			N/A			N/A
Average price differentials		0.34			0.25			—			0.34			(0.02	)		N/A			N/A


	As of March 31,					As of December 31,								Pro Forma As of March 31, 2011
	2011			2010		2010			2009		2008			Pro Forma As of March 31, 2011
	(Unaudited)													(Unaudited)
BALANCE SHEET DATA (in thousands):
Cash and cash equivalents	$	15,524		$	9,245	$	18,879		$	6,236	$	1,647		$	14,464
Oil and natural gas properties, net		131,474			94,083		123,783			88,600		8,148			255,424
Total assets		321,857			130,900		306,504			114,009		26,806			477,799
Total debt, including current portion		148,768			39,625		150,753			40,133		6,851			183,768
Asset retirement obligations (net of escrow)		19,575	⁽²⁾		45,019		8,074			45,431		(4,846	)		77,248	⁽²⁾
Members’ equity (deficit)		(46,631	)		10,984		(20,610	)		5,723		4,919			(16,631	)

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

(2)	Amount also net of restricted cash as it relates to P&A obligations.

Index to Financial Statements

SUMMARY RESERVE AND OPERATING DATA

The following table sets forth our estimates of proved reserves and future net cash flows as of December 31, 2010 calculated by adding reserve estimates from the NSAI Report. The 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.


	Reserve Category
	PDP		PDNP		PUD		Total
	(dollars in thousands)
Net Proved Reserves
Oil (MBbls)		5,239		2,658		2,360		10,257
Natural Gas (MMcf)		21,764		33,243		13,591		68,598
Future Net Revenues
Oil	$	407,346	$	201,024	$	180,015	$	788,385
Natural Gas		99,150		153,421		63,606		316,177

Total Revenues		506,496		354,445		243,621		1,104,562
Production Costs⁽¹⁾		165,817		116,211		48,537		330,565
Development & P&A Costs		179,499		45,907		53,378		278,784

Future Net Cash Flows		161,180		192,327		141,706		495,213

PV-10⁽²⁾⁽³⁾	$	155,807	$	148,543	$	87,839	$	392,189

(1)	Production taxes plus lease operating expense.

(2)

Calculated using SEC pricing based on the average price as of the first day of each of the twelve months ended December 31, 2010. For oil volumes, the average West Texas Intermediate posted price of $75.96 per barrel 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 $76.86 per Bbl of oil and $4.609 per MCF of gas. See “Supplemental Oil & Gas Disclosures” for additional information.

(3)

Because we are classified as a partnership for federal income tax purposes and therefore not subject to income taxes, PV-10 is equivalent to “Standardized Measure” as represented in our financial statements. Each of PV-10 and Standardized Measure is the present value of estimated future net revenue to be generated from the production of our proved reserves, determined in accordance with the rules and regulations of the SEC, less future development and production, expenses and discounted at 10% per annum to reflect the timing of future net revenue. Because we are currently not subject to income taxes, we make no provision for state or federal income taxes in the calculation of Standardized Measure. 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. See “Supplemental Oil and Gas Disclosures—Standardized Measure of Discounted Future Pre-Tax Net Cash Flow”

Index to Financial Statements

You should carefully consider each of the risks described below and the matters addressed under “Cautionary Statements Regarding Forward-Looking Statements,” together with all of the other information contained in this Prospectus, including our consolidated financial statements and related notes included elsewhere in this Prospectus. The risks described below are not the only risks facing us or that may materially adversely affect our business. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected and you may lose all or part of your investment.

British Petroleum PLC’s Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the 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 Gulf of Mexico. As a result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the Gulf Coast region. 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 Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE,” formerly the Minerals Management Service) of the U.S. Department of the Interior 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, BOEMRE issued a series of “Notices to Lessees and Operators” (“NTLs”) implementing additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, and imposed additional requirements with respect to 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 waters of the U.S. Gulf of Mexico 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, blowout preventers, safety certification, emergency response and worker training. Operators must also demonstrate the availability of adequate spill response and blowout containment resources. Notwithstanding the lifting of the moratorium, we anticipate that there will continue to be delays in the resumption of drilling-related activities, including delays in the issuance of drilling permits, as these various regulatory initiatives are fully implemented.

In addition, 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 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 Oil Pollution Act of 1990 (“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 (the “OCS”), which includes the U.S. Gulf of Mexico where we have substantial offshore operations. OPA subjects 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 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

Index to Financial Statements

responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, 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 session of Congress. If OPA is amended during the current session of Congress 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 recently imposed by the Bureau of Ocean Energy Management, Regulation and Enforcement 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 imposing new regulatory requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These regulatory requirements include the following:

Since the adoption of these new regulatory requirements, BOEMRE has been taking much longer than in the past to review and approve permits for new wells. The new rules 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 OCS.

We are unsure what long-term effect, if any, the BOEMRE’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 disaster.

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 March 31, 2011, our estimated total asset retirement obligations, which relate to our P&A obligations, were $137.3 million.

Index to Financial Statements

Estimating future restoration and removal costs in the 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 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 a hurricane.

In addition, the BOEMRE issued on 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 have 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—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 legal 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 likely 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 “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 will 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:

Index to Financial Statements

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.

To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in demand for oil or natural gas would have a material adverse effect on our financial condition and results of operations. Any substantial or extended decrease 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.

The geographic concentration of our properties in the Gulf of Mexico subjects us to an increased risk of loss of revenue or curtailment of production from factors affecting the Gulf of Mexico specifically.

The geographic concentration of our properties along the Texas and Louisiana Gulf Coast and adjacent waters on and beyond the Outer Continental Shelf means that some or all of our properties could be affected by the same event should the Gulf of Mexico experience:

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.

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

Index to Financial Statements

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

Successful acquisitions require an assessment of numerous factors beyond our control, including, without limitation, those relating to:

In connection with such a potential acquisition, we perform a review of the subject properties which 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 shallow state and federal waters in the Gulf of Mexico as well as deepwater Gulf of Mexico, we may pursue acquisitions or properties located in other geographic areas.

We depend to a large extent on the services of certain key management personnel, 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. Pursuant to our Second Amended and Restated Operating Agreement, Platinum, as our majority equity holder, has the ability to appoint and remove all of the members of our board of managers and, in turn, the board of managers has the right to appoint and remove our executive officers. Although we have entered into employment agreements with each of Messrs. Hoffman and Hagemeier, there can be no assurance that Platinum will not cause either individual to be removed. Additionally, our success is dependent on our ability to continue to employ and retain skilled technical personnel.

Index to Financial Statements

The loss of Mr. Hoffman or Mr. Hagemeier or other key personnel could have a material adverse effect on our business, financial condition and results of operations.

Platinum is managed by Platinum Management (NY) LLC (“PMNY”). One of PMNY’s principals is Mark Nordlicht. Mr. Nordlicht has been named, along with other defendants, in a consolidated amended class action complaint as a former director of Optionable, Inc. (“Optionable”), a brokerage firm for energy options which he founded in 2000. Mr. Nordlicht was not active in the daily business operations of Optionable, although he served on its Board of Directors from its Inception until May 1, 2007.

In late April 2007, Optionable’s largest customer, BMO Financial Group, announced that it had incurred significant natural gas-related trading losses and that it was suspending all of its trading activity through Optionable, pending the results of an ongoing external review. Following these announcements, several civil actions were filed by a class of investors in the U.S. District Court for the Southern District of New York against Optionable and, in some cases, Optionable’s current and former officers and directors, including Mr. Nordlicht. On September 15, 2008, United States District Judge Lewis A. Kaplan dismissed the consolidated amended class action complaint in which Mr. Nordlicht was named, on the grounds that the complaint failed to allege fraud. The plaintiffs have since appealed the ruling and moved for reconsideration to reopen the case, which was denied. PMNY maintains that these actions are without merit.

In April 2010, PMNY was named in two civil suits pertaining to a senior secured loan PMNY made to Banyon Investments, LLC (“Banyon”). Banyon is currently in default on these loans and the assets that Banyon was acquiring with these loans were fabricated by South Florida attorney Scott Rothstein as part of what has been reported to be a larger fraudulent scheme. PMNY has been sued by the bankruptcy trustee in the U.S. Bankruptcy Court for the Southern District of Florida for Mr. Rothstein’s now-defunct Florida law firm, who seeks to recover transfers made by Mr. Rothstein to Banyon, and from Banyon to PMNY, on the theories that those transfers were “preferences” under the Bankruptcy Code and/or were made by Mr. Rothstein to defraud others. PMNY has also been sued by a group of investors in Mr. Rothstein’s program in the Circuit Court for Broward County, Florida who claim that PMNY had a duty to protect them from Mr. Rothstein and conspired with Mr. Rothstein to defraud them. PMNY maintains that these actions are without merit.

Although these are the only matters currently pending, other actions and claims could be brought against PMNY and its affiliates in connection with the Banyon investment. Such claims could seek damages from such parties and/or disgorgement of amounts received by them.

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.

Index to Financial Statements

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 would require us to record an impairment of the book values associated with oil and gas properties.

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

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have and may continue to enter into hedging arrangements for a significant portion of our oil and natural gas production. Other than the W&T Escrow Accounts, with respect to which W&T has a first priority lien and the administrative agent under our credit facility holds a second lien for the benefit of the lender thereunder and our derivatives counterparty, the administrative agent holds a first priority lien over all of our assets for the benefit of the lenders under our credit facility and our derivatives counterparty.

Our ability to use hedging transactions to protect us from future oil and natural gas price declines will be dependent upon oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to commodity price changes. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write downs may occur if we experience substantial downward adjustments to our estimated proved reserves.

Our policy has been to hedge a significant portion of our near–term estimated oil and natural gas production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the prior few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes. 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.

Index to Financial Statements

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.

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 its business.

Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as our Company, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its 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 through requirements to post collateral which 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 and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil 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.

Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or underlying assumptions of our properties will materially affect the quantities and present value of those reserves. In addition, estimates relating to the development of proved undeveloped reserves and bringing related production online and the future cash flows and future gross revenues relating to such production are based on many assumptions that may turn out to be inaccurate, and any material inaccuracies in the estimates or underlying assumptions may cause our estimates to vary significantly from the actual results we will experience.

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

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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 Prospectus should not be regarded as a representation by us, the placement agents or any other person that the estimates will actually be achieved. You, as a prospective purchaser of the notes, are cautioned not to place undue reliance on the estimates.

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.

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:

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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.

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 in these areas in the future, our future revenues and growth may be diminished or restricted.

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.

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Drilling for oil and natural gas is a speculative activity involving many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

We engage in exploitation and development drilling activities. Any such activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of a gas or oil 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.

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:

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. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. 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.

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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.

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, 2010, we operated approximately 43% of the fields and 39% 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:

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 recent catastrophic events like the terrorist attacks on September 11, 2001 and Hurricanes Katrina, Rita, Gustav

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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 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 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.

Our operations are subject to environmental and other government laws and regulations that may expose us to significant costs and liabilities.

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 (i) addressing, among other items, land use and lease permit restrictions, bonding and other financial assurance related to drilling and production activities, spacing of wells, unitization and pooling of properties, plugging and abandonment of wells and associated infrastructure after production has ceased, operational reporting and taxation, and environmental and occupational health and safety matters, and (ii) that impose liability for, and require investigation and remediation of, releases of 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 expenses and damages, including natural resource damages, and fines, penalties and expenses for any violation or noncompliance with any of the applicable laws or regulations.

We may be required to make significant capital and operating expenditures or perform other corrective actions at our wells and properties to comply with the requirements of these environmental, health and safety laws and regulations or the terms or conditions of permits issued pursuant to such requirements, and 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:

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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:

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, 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

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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 contamination on our properties regardless of whether such 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 environmental and other impacts of our operations. In addition, 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 or neighboring property owners or operators for personal injury or property damage related to our operations or the land on 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.”

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:

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.

Climate change legislation or regulations restricting emissions of “greenhouse gases” 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 “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Accordingly, the EPA adopted two sets of rules regarding possible future regulation of greenhouse gas emissions under the CAA, one

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of which purports to require a reduction in emissions of greenhouse gases from motor vehicles and the other of which would regulate emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. On June 3, 2010, EPA published its final rule to address permitting of greenhouse gas emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The final rule tailors the PSD and Title V permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. On November 8, 2010, the EPA finalized regulations amending the reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and gas processing, transmission, storage and distribution facilities. Reporting of greenhouse gas emissions from such oil and natural gas facilities would be required on an annual basis beginning in 2012 for emissions occurring in 2011.

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 greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases 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 greenhouse gases 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 greenhouse gases 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.

Approximately 21% of our total estimated proved reserves at December 31, 2010 were classified as proved undeveloped and may ultimately prove to be less than estimated.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. At December 31, 2010, approximately 21% 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 $53.4 million, of which $10.9 million and $1.3 million are expected to be incurred in 2011 and 2012, 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. For a more detailed discussion of our current liquidity and projected liquidity immediately following this offering, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

In addition, we have one offshore federal lease located in the deep waters of the Gulf of Mexico that have yet to be drilled or developed. We are unsure what effect, if any, the BOEMRE’s regulation of the drilling of wells using subsea blowout preventers (“BOP”) or surface BOPs on a floating facility will have on these leases and our estimated proved reserves at December 31, 2010. We are also unsure what effect, if any, amendments to OPA will have on these leases and our other offshore operations. However, it is possible that due to changes in

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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 Gulf of Mexico, some of which may be unforeseeable.”

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. For the years prior to 2009, we based the estimated discounted future net revenues from our proved reserves on prices and costs in effect on the day of the estimate. In accordance with new 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 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. If oil prices decline by $10.00 per Bbl, then our PV-10 as of December 31, 2010 would decrease approximately 19%. If natural gas prices decline by $1.00 per MMBtu, then our PV-10 as of December 31, 2010 would decrease by approximately 14%.

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 will bear 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.

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, 2010, Shell Trading (US) Company was our largest purchaser of oil and natural gas, accounting for approximately 52% of our revenues, with Conoco Phillips Company as the next largest purchaser, accounting for approximately 14% 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, of 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.

If you do not properly tender your old notes, you will continue to hold unregistered old notes and your ability to transfer old notes will remain restricted and may be adversely affected.

We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes.

If you do not exchange your old notes for new notes pursuant to the Exchange Offer, the old notes you hold will continue to be subject to the existing transfer restrictions. In general, you may not offer or sell the old notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not plan to register old notes under the Securities Act unless our Registration Rights Agreement with the initial purchasers of the old notes requires us to do so. Further, if you continue to hold any old notes after the Exchange Offer is consummated, you may have trouble selling them because there will be fewer of these notes outstanding.

Our substantial indebtedness could adversely affect our financial health and prevent us from fulfilling our obligations under the notes.

As of June 15, 2011, we had an aggregate amount of $72.3 million of indebtedness outstanding under our credit facility, which we amended on May 31, 2011, $27.3 million of which was drawn as letters of credit in support of our P&A obligations and $45.0 million under our revolver, and a borrowing base of $122.7 million available for additional borrowings, including $25 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 (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”), 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. As of December 31, 2010, our estimated total asset retirement obligations, which relate to our P&A obligations, were $122.2 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 properties that we acquired from W&T in October 2009, according to stipulated payment schedules in maximum aggregate principal amount of $63.8 million. We used $20 million of the net proceeds of the Senior 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. 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 has been suspended for one year. Our funding obligations will

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re-commence on December 1, 2011, on which date we will be required to make an initial payment of $247,738 to the Non-Operated Properties Escrow Account, to be followed by payments of $340,000 per month and, 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 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 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.

Our substantial indebtedness and other obligations could have important consequences to you. For example, it could:

In addition, the terms of the Indenture governing the notes and our credit facility contain restrictive covenants that limit our ability to engage in 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.

Despite our substantial indebtedness level, we and our subsidiaries may still be able to incur significant additional amounts of debt, which could further exacerbate the risks associated with our substantial indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness, including additional notes and other secured indebtedness, in the future. Although the Indenture governing the notes and the agreement governing our credit facility contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions and, under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we now face would intensify. In addition, the Indenture governing the notes and the agreement governing our credit facility will not prevent us from incurring obligations that do not constitute indebtedness under the agreements.

Platinum owns approximately 75% 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, 2010, Platinum, a multi-strategy investment fund, beneficially owned approximately 75% of our outstanding voting membership interests and approximately 68% 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,

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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.

The collateral for the notes does not include the W&T Escrow Accounts that secure our P&A obligations with respect to the W&T Properties.

We purchased certain oil, natural gas and mineral interests and leases, along with related wells, infrastructure, equipment, information and other rights and assets from W&T in the fourth quarter of 2009. As a condition to W&T’s willingness to sell these properties to us, W&T required us to provide adequate financial assurance of our ability to pay for the costs of plugging and abandoning and/or removal of wells, platforms, facilities, pipelines and other equipment related to the W&T Properties. Accordingly, in addition to granting W&T a second lien on the acquired W&T Properties, we established the two W&T Escrow Accounts to further secure our P&A obligations with respect to those properties. W&T holds a first priority lien on the W&T Escrow Accounts with the administrative agent under our credit facility holding a second lien for the benefit of the lenders under our credit 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. As a result, the collateral for the notes does not include the W&T Escrow Accounts.

Any future pledge of collateral to secure the notes with after acquired property might be avoidable by a trustee in bankruptcy.

If we obtain additional collateral after the original Issue Date of the notes and obtain pledges on such collateral to secure the notes, there is still a risk that if we or any guarantor were to become subject to a bankruptcy proceeding after the Issue Date of the notes, any liens recorded or perfected on such additional collateral after the Issue Date of the notes would face a greater risk of being invalidated than if they had been recorded or perfected on the Issue Date. If a lien is recorded or perfected after the Issue Date, it may be treated under bankruptcy law as if it were delivered to secure previously existing debt. In bankruptcy proceedings commenced within 90 days of lien perfection, a lien given to secure previously existing debt is materially more likely to be avoided as a preferential transfer by the bankruptcy court than if delivered and promptly recorded on the Issue Date of the notes. Accordingly, if we or a guarantor were to file for bankruptcy and the liens on such additional collateral had been perfected less than 90 days before commencement of such bankruptcy proceeding, the liens on such additional collateral may be especially subject to challenge as a result of having been delivered after the Issue Date of the notes. To the extent that such challenge succeeded, you would lose the benefit of the security that such additional collateral was intended to provide.

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

Our ability to make payments on our indebtedness, including the notes, and to fund planned capital expenditures will depend on our ability to generate cash in the future. We cannot assure you that our business will generate sufficient cash flow from operations to service 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 have to undertake alternative financing plans, such as:

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

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:

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the Indenture governing the notes or in the agreement governing our credit facility, it could lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions.

Under certain circumstances a court could cancel the notes or the related guarantees and the security interests that secure the notes and any guarantees under fraudulent conveyance laws.

Our issuance of the notes, the related guarantees and the liens that secure the notes and any guarantees may be subject to review under federal or state fraudulent transfer law. If we become a debtor in a case under the United States Bankruptcy Codeor encounter other financial difficulty, a court might cancel our obligations under the notes, the guarantees and/or the liens. The court might do so if it found that when we issued the notes or the debt being refinanced with the proceeds of the notes, (i) we received less than reasonably equivalent value or fair consideration and (ii) we either (1) were rendered insolvent, (2) were left with inadequate capital to conduct our business or (3) believed or reasonably should have believed that we would incur debts beyond our ability to pay. The court could also avoid the notes, the guarantees and/or the liens securing the notes without regard to factors (i) and (ii) if it found that we issued the notes and/or the guarantees with actual intent to hinder, delay or defraud our creditors.

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Similarly, if one of our guarantors becomes a debtor in a case under the United States Bankruptcy Codeor encounters other financial difficulty, a court might cancel its guarantee if it finds that when such guarantor issued its guarantee (or in some jurisdictions, when payments became due under the guarantee) or when we issued the guarantee being refinanced with the proceeds of the notes, factors (i) and (ii) above applied to such guarantor, such guarantor was a defendant in an action for money damages or had a judgment for money damages docketed against it (if, in either case, after final judgment the judgment is unsatisfied), or if it found that such guarantor issued its guarantee with actual intent to hinder, delay or defraud its creditors.

In addition, a court could avoid any payment by us or any guarantor pursuant to the notes or a guarantee or any realization on the pledge of assets securing the notes or the guarantees, and require the return of any payment or the return of any realized value to us or the guarantor, as the case may be, or to a fund for the benefit of the creditors of us or the guarantor. In addition, under the circumstances described above, a court could subordinate rather than avoid obligations under the notes, the guarantees or the pledges. If the court were to avoid any guarantee, we cannot assure you that funds would be available to pay the notes from another guarantor or from any other source.

The test for determining solvency for purposes of the foregoing will vary depending on the law of the jurisdiction being applied. In general, a court would consider an entity insolvent either if the sum of its existing debts exceeds the fair value of all of its property, or its assets’ present fair saleable value is less than the amount required to pay the probable liability on its existing debts as they become due. For this analysis, “debts” includes contingent and unliquidated debts.

The Indenture governing the notes limits the liability of each guarantor on its guarantee to the maximum amount that such guarantor can incur without risk that its guarantee will be subject to avoidance as a fraudulent transfer. We cannot assure you that this limitation will protect such guarantees and/or security arrangements from fraudulent transfer challenges or, if it does, that the remaining amount due and collectible under the guarantees and/or security arrangements would suffice, if necessary, to pay the notes in full when due. In a recent Florida bankruptcy case, this kind of provision was found to be ineffective to protect the guarantees.

If a court avoided our obligations under the notes and/or security arrangements and the obligations of all of the guarantors under their guarantees and/or security arrangements, you would cease to be our creditor or creditor of the guarantors and likely have no source from which to recover amounts due under the notes. Even if any guarantee and/or security arrangement of a guarantor is not avoided as a fraudulent transfer, a court may subordinate the guarantee and/or security arrangements to that guarantor’s other debt. In that event, the guarantees would be structurally subordinated to all of that guarantor’s other debt.

The liens on the collateral securing the notes are junior and subordinate to the liens on the collateral securing our obligations under any permitted first lien indebtedness. If there is a default, the value of the collateral may not be sufficient to repay both the holders of any permitted first lien indebtedness and the holders of the notes.

The notes are secured by second-priority liens, subject to certain permitted liens and encumbrances described in the security documents relating to the notes, granted by us on our assets that secure the obligations under any permitted first lien indebtedness on a first-priority basis.

The rights of the holders of the notes with respect to the collateral securing the notes are limited pursuant to the terms of the security documents relating to the notes, the intercreditor agreement and the Indenture governing the notes. Under the terms of those agreements, the holders of the notes have a second-priority lien, subject to certain permitted liens and encumbrances described in the security documents relating to the notes, on all of the collateral that secures the obligations under our permitted first lien indebtedness except the W&T Escrow Accounts. The second priority liens securing the notes may also secure additional notes on an equal and ratable basis. Accordingly, any proceeds received upon a realization of the collateral securing the notes will be applied first to amounts due under our permitted first lien indebtedness before any amounts will be available to pay the holders of the notes. Under the terms of the Indenture governing the notes, we are permitted to incur substantial

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additional indebtedness, all of which can be secured by the collateral on a first-priority lien basis and which will be entitled to payment out of the proceeds of any sale of such collateral before the holders of the notes are entitled to any recovery from such collateral.

The notes are secured only to the extent of the value of the assets having been granted as security for the notes, which may not be sufficient to satisfy our obligations under the notes.

No appraisals of any of the collateral were prepared by us or on behalf of us in connection with the Senior Notes Offering. The fair market value of the collateral is subject to fluctuations based on factors that include, among others, our ability to implement our business strategy, the ability to sell the collateral in an orderly sale, general economic conditions, the availability of buyers and similar factors. In addition, courts could limit recovery if they apply law of a state other than the state of New York to a proceeding and deem a portion of the interest claim usurious in violation of public policy. The amount to be received upon the sale of any collateral would be dependent on numerous factors, including, but not limited to the actual fair market value of the collateral at such time, general market and economic conditions and the timing and the manner of the sale.

To the extent that the claims of the holders of the notes exceed the value of the assets securing those notes and other liabilities, those claims will rank equally with the claims of the holders of any outstanding senior unsecured indebtedness. As a result, if the value of the assets pledged as security for the notes and other liabilities is less than the value of the claims of the holders of the notes and other liabilities, those claims may not be satisfied in full before the claims of our unsecured creditors are paid.

The rights of holders of the notes with respect to the collateral are substantially limited by the terms of the intercreditor agreement.

Under the terms of the intercreditor agreement entered into with the collateral agent for the notes and our first lien creditors pursuant to our credit facility, such first lien creditors, at any time that obligations that have the benefit of the first-priority liens on the collateral securing the notes are outstanding, any action that may be taken by the collateral agent with respect to the collateral securing the notes, including the ability to cause the commencement of enforcement proceedings against the collateral and to control the conduct of such proceedings, will be significantly restricted. Under the terms of the intercreditor agreement, the collateral agent for the notes may exercise rights and remedies with respect to the collateral only after the passage of 120 days after notification from the collateral agent for the notes to the agent under our credit facility that either (i) the obligations with respect to the notes have become due in full as a result of acceleration or otherwise (and such acceleration has not been rescinded) or (ii) any payment or insolvency event of default has occurred and is then continuing under the Indenture or the other documents executed in connection therewith. After the passage of such period, the collateral agent for the notes will only be only permitted to exercise remedies to the extent that the First Lien Collateral Agent or any other first lien creditor is not diligently pursuing an enforcement action with respect to all or a material portion of the collateral or diligently attempting to vacate any stay or prohibition against such exercise. The intercreditor agreement provides that, at any time that obligations that have the benefit of the first-priority liens on the collateral are outstanding, the collateral agent for the notes may not assert any right of marshalling that may be available under applicable law with respect to the collateral. Without this waiver of the right of marshalling, holders of indebtedness secured by first-priority liens in the collateral would likely be required to liquidate collateral on which the notes did not have a lien, if any, prior to liquidating the collateral securing the notes, thereby maximizing the proceeds of the collateral that would be available to repay obligations under the notes. As a result of this waiver, the proceeds of sales of the collateral securing the notes could be applied to repay any indebtedness secured by first-priority liens in such collateral before applying proceeds of other collateral securing indebtedness, and the holders of notes may recover less than they would have if such proceeds were applied in the order most favorable to the holders of the notes.

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There are circumstances other than repayment or discharge of the notes under which the collateral securing the notes and the subsidiary guarantees will be released automatically, without your consent or the consent of the collateral agent for the notes, and you may not realize any payment upon disposition of such collateral.

Subject to certain exceptions, in the event of any release permitted or consented to under our credit facility, the liens on the collateral securing the notes will be automatically released. See “Description of Notes—Collateral.” In addition, the liens on the collateral securing the notes may be released with consent of holders of a majority of the principal amount of outstanding notes.

Upon certain sales of the assets that comprise the collateral, we may be required to repay amounts outstanding under our credit facility prior to repayment of any other indebtedness, including the notes, with the proceeds of such collateral disposition.

As a result of the intercreditor agreement, the rights that would otherwise be available to you as a creditor will be substantially limited, especially in circumstances where we become insolvent. The terms and provisions of the intercreditor agreement could adversely affect your rights as a creditor.

The intercreditor agreement precludes the holders of the notes from initiating any insolvency proceeding, including initiating an involuntary proceeding under the U.S. federal bankruptcy laws. If, in the event of any insolvency or liquidation proceeding, the lenders under our credit facility desire to permit the use of cash collateral or to permit certain DIP financing, the collateral agent for the notes will, subject to certain exceptions, not be permitted to raise any objection to such cash collateral use or DIP financing. The intercreditor agreement limits the right of the collateral agent for the notes to seek relief from the “automatic stay” in an insolvency proceeding or to seek or accept “adequate protection” from a bankruptcy court even though such holders’ rights with respect to the collateral are being affected.

The Indenture permits certain additional notes that are permitted to be incurred under the debt incurrence covenant to be secured by an equal and ratable lien on the collateral. The value of your rights to the collateral would be reduced by any increase in the indebtedness secured by the collateral.

We are permitted to incur additional notes under the Indenture secured by liens on the collateral. The value of your rights to the collateral would be reduced by any increase in the indebtedness secured by the collateral. The value of the collateral and the amount to be received upon a sale of such collateral will depend upon many factors including, among others, the condition of the collateral and the oil and natural gas development and exploration industry, the ability to sell the collateral in an orderly sale, the condition of the international, national and local economies, the availability of buyers and similar factors. No appraisal was obtained in respect of the collateral in connection with the Senior Notes Offering and you should not rely upon the book value of the collateral as a measure of realizable value for such assets. By their nature, portions of the collateral may be illiquid and may have no readily ascertainable market value. In addition, a significant portion of the collateral includes assets that may only be usable, and thus retain value, as part of our existing operating businesses.

Accordingly, any such sale of the collateral separate from the sale of certain operating businesses may not be feasible or of significant value. To the extent that holders of other secured indebtedness or other third parties hold liens (including statutory liens), whether or not permitted by the Indenture governing the notes, such holders or other third parties may have rights and remedies with respect to the collateral securing the notes that, if exercised, could reduce the proceeds available to satisfy the obligations under the notes.

Rights of holders of the notes in the collateral may be adversely affected by bankruptcy proceedings.

The right of the collateral agent for the notes to repossess and dispose of the collateral securing the notes and the guarantees upon acceleration is likely to be significantly impaired by federal bankruptcy law if bankruptcy proceedings are commenced by or against us or our domestic restricted subsidiaries that provide security for the notes or guarantees prior to, or possibly even after, the collateral agent has repossessed and disposed of the collateral. Under the U.S. Bankruptcy Code, a secured creditor, such as the collateral agent for

Index to Financial Statements

the notes, is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from a debtor, without bankruptcy court approval. Applicable legislation in other jurisdictions may impose similar approval requirements in relation to debtors in foreign proceedings. Moreover, bankruptcy law permits the debtor to continue to retain and to use collateral, and the proceeds, products, rents, or profits of the collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security, if and at such time as the court in its discretion determines, for any diminution in the value of the collateral as a result of the stay of repossession or disposition or any use of the collateral by the debtor during the pendency of the bankruptcy case. In view of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the notes or any guarantees could be delayed following commencement of a bankruptcy case, whether or when the collateral agent would repossess or dispose of the collateral, or whether or to what extent holders of the notes would be compensated for any delay in payment or loss of value of the collateral through the requirements of “adequate protection.” Furthermore, in the event the bankruptcy court determines that the value of the collateral is not sufficient to repay all amounts due on the notes, the holders of the notes would have “undersecured claims” as to the difference. Federal bankruptcy laws do not permit the payment or accrual of interest, costs and attorneys’ fees for “undersecured claims” during the debtor’s bankruptcy case.

In the event of our bankruptcy, holders of the notes may be deemed to have an unsecured claim to the extent that our obligations in respect of the notes exceed the fair market value of the collateral securing the notes.

In any bankruptcy proceeding with respect to us or any of the guarantors, it is possible that the bankruptcy trustee, the debtor-in-possession or competing creditors will assert that the fair market value of the collateral with respect to the notes on the date of the bankruptcy filing was less than the then current principal amount of the notes. Upon a finding by the bankruptcy court that the notes are under-collateralized, the claims in the bankruptcy proceeding with respect to the notes would be bifurcated between a secured claim and an unsecured claim, and the unsecured claim would not be entitled to the benefits of security in the collateral. In such event, the secured claims of the holders of the notes would be limited to the value of the collateral.

Other consequences of a finding of under-collateralization would be, among other things, a lack of entitlement on the part of the holders of the notes to receive post-petition interest and a lack of entitlement on the part of the unsecured portion of the notes to receive other “adequate protection” under federal bankruptcy laws. In addition, if any payments of post-petition interest had been made at the time of such a finding of under- collateralization, those payments could be recharacterized by the bankruptcy court as a reduction of the principal amount of the secured claim with respect to the notes.

Any future pledge of collateral might be avoidable by a trustee in bankruptcy.

Any future pledge of, or security interest or lien granted on, collateral in favor of the collateral agent might be avoidable by the pledgor (as debtor in possession) or by its trustee in bankruptcy if certain events or circumstances exist or occur, including, among others, if the pledgor is insolvent at the time of the pledge, the pledge permits the holders of the notes to receive a greater recovery than if the pledge had not been given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge, or, in certain circumstances, a longer period.

Rights of holders of the notes in the collateral may be adversely affected by the failure to perfect security interests in certain collateral acquired in the future.

The collateral securing the notes and the guarantees includes substantially all of our and the guarantors’ tangible and intangible assets that secure our indebtedness under our credit facility, whether now owned or acquired or arising in the future. If additional subsidiaries are formed or acquired that are required to guarantee the notes pursuant to the terms of the Indenture, additional financing statements or their foreign equivalents

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would be required to be filed to perfect the security interest in the assets of such subsidiaries. Depending on the type of the assets constituting after-acquired collateral, additional action may be required to be taken by the collateral agent for the notes, or the collateral agent for our credit facility, to perfect the security interest in such assets, such as the delivery of physical collateral, the execution of account control agreements or the execution and recordation of mortgages or deeds of trust. Applicable law requires that certain property and rights acquired after the grant of a general security interest can only be perfected at the time such property and rights are acquired and identified. There can be no assurance that the trustee or the collateral agent will monitor, or that we will inform the trustee or the collateral agent of, the future acquisition of property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after- acquired collateral. The collateral agent for the notes and the collateral agent for our credit facility have no obligation to monitor the acquisition of additional property or rights that constitute collateral or the perfection of any security interests therein. Such failure may result in the loss of the security interest therein or the priority of the security interest in favor of the notes and the guarantees against third parties.

We intend to maintain insurance or otherwise insure against hazards in a manner appropriate and customary for our business. There are, however, certain losses that may be either uninsurable or not economically insurable, in whole or in part. Insurance proceeds may not compensate us fully for our losses. If there is a complete or partial loss of any of the pledged collateral, the insurance proceeds may not be sufficient to satisfy all of the secured obligations, including the notes and the subsidiary guarantees.

Moreover, the collateral agent may need to evaluate the impact of potential liabilities before determining to foreclose, to the extent it may do so under the security documents related to the notes, on collateral consisting of real property because owners and operators of real property may in some circumstances be held liable under environmental laws for the costs of remediating or preventing the release or threatened release of hazardous substances at such real property. Consequently, the collateral agent may decline to foreclose on such collateral or exercise remedies available in respect thereof if it does not receive indemnification to its satisfaction from the holders of the notes.

We are permitted to create unrestricted subsidiaries, which will not be subject to any of the covenants in the Indenture, and we may not be able to rely on the cash flow or assets of those unrestricted subsidiaries to pay our indebtedness.

Unrestricted subsidiaries will not be subject to the covenants under the Indenture governing the notes, and their assets will not be available as security for the notes. Unrestricted subsidiaries may enter into financing arrangements that limit their ability to make loans or other payments to fund payments in respect of the notes. Accordingly, we may not be able to rely on the cash flow or assets of unrestricted subsidiaries to pay any of our indebtedness, including the notes.

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the notes.

The old notes have not been registered under the Securities Act, and may not be resold by purchasers thereof unless the old notes are subsequently registered or an exemption from the registration requirements of the Securities Act is available. However, we cannot assure you that, even following registration or exchange of the old notes for new notes, that an active trading market for the old notes or the new notes will exist, and we will have no obligation to create such a market. No assurance can be given as to the liquidity of or trading market for the old notes or the new notes.

The liquidity of any trading market for the notes and the market price quoted for the notes will depend upon the number of holders of the notes, the overall market for high yield securities, our financial performance or prospects or the prospects for companies in our industry generally, the interest of securities dealers in making a market in the notes and other factors.

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If a rating agency rates the notes, it may assign a rating that is lower than the rating expected by the noteholders. Ratings agencies also may lower ratings on the notes or any of our other debt in the future. If rating agencies assign a lower-than-expected rating or reduce, or indicate that they may reduce their ratings of our debt in the future, the trading price of the notes could significantly decline.

Upon the occurrence of certain change of control events, we would be required to offer to repurchase all or any part of the notes then outstanding for cash at 101% of the principal amount. The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from our operations or other sources, including:

We cannot assure you that sufficient funds would be available at the time of any change of control to repurchase your notes. Additionally, a “change of control” is an event of default under our credit facility that would permit the lenders to accelerate the debt outstanding under such facility. Finally, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations.

The term “change of control” is limited to certain specified transactions and may not include other events that might adversely affect our financial condition. Our obligation to repurchase the notes upon a change of control would not necessarily afford holders of notes protection in the event of a highly leveraged transaction, reorganization, merger or similar transaction.

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At the closing of the Senior Notes Offering, we entered into the Registration Rights Agreement with the placement agents, on behalf of the initial purchasers, pursuant to which we agreed, for the benefit of the holders of the old notes, at our cost, to do the following:

Upon the SEC’s declaring the Exchange Offer registration statement effective, we agreed to offer the new notes in exchange for surrender of the old notes. We have met all of these obligations. We have also agreed to use our reasonable best efforts to keep the registration statement effective until the consummation of the Exchange Offer in accordance with its terms.

For each old note surrendered to us pursuant to the Exchange Offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the most recent interest payment date for the old notes, June 1, 2010. We also agreed in the Registration Rights Agreement to include in this Prospectus certain information necessary to allow a broker-dealer who holds old notes that were acquired for its own account as a result of market-making activities or other ordinary course trading activities (other than old notes acquired directly from us or one of our affiliates) to exchange such old notes pursuant to the Exchange Offer and to satisfy its prospectus delivery requirements in connection with resales of new notes received by such broker-dealer in the Exchange Offer. We agreed to use commercially reasonable efforts to maintain the effectiveness of the Exchange Offer registration statement for these purposes for a period of 180 days after the date on which the registration statement is declared effective.

The preceding agreement is needed because any broker-dealer who acquires old notes for its own account as a result of market-making activities or other trading activities is required to deliver a prospectus meeting the requirements of the Securities Act. This Prospectus covers the offer and sale of the new notes pursuant to the Exchange Offer and the resale of new notes received in the Exchange Offer by any broker-dealer who held old notes acquired for its own account as a result of market-making activities or other trading activities other than old notes acquired directly from us or one of our affiliates.

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued pursuant to the Exchange Offer would in general be freely tradable after the Exchange Offer without further registration under the Securities Act. However, any purchaser of old notes who is an “affiliate” of ours or who intends to participate in the Exchange Offer for the purpose of distributing the related new notes:

Each holder of the old notes (other than certain specified holders) who desires to exchange old notes for the new notes in the Exchange Offer will be required to make the representations described below under “—Procedures for Tendering—Your Representations to Us.”

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Subject to the terms and conditions described in this Prospectus and in the accompanying letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 5:00 p.m. New York City time on the expiration date. We will issue new notes in principal amount equal to the principal amount of old notes surrendered in the Exchange Offer. Old notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The Exchange Offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

As of the date of this Prospectus, $150 million in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the Exchange Offer.

We intend to conduct the Exchange Offer in accordance with the provisions of the Registration Rights Agreement, the applicable requirements of the Securities Act and the Exchange Act and the rules and regulations of the SEC. Old notes that the holders thereof do not tender for exchange in the Exchange Offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the Indenture relating to the notes.

We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the Registration Rights Agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

If you tender old notes in the Exchange Offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of old notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the Exchange Offer. It is important that you read the section labeled “— Fees and Expenses” for more details regarding fees and expenses incurred in the Exchange Offer.

We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the Exchange Offer.

The Exchange Offer will expire at 5:00 p.m., New York City time, on , 2011, unless, in our sole discretion, we extend it.

We expressly reserve the right, at any time or various times, to extend the period of time during which the Exchange Offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders. During any such extensions, all old notes previously tendered will remain subject to the Exchange Offer, and we may accept them for exchange.

In order to extend the Exchange Offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

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If any of the conditions described below under “—Conditions to the Exchange Offer” have not been satisfied, we reserve the right, in our sole discretion:

by giving oral or written notice of such delay, extension or termination to the Exchange Agent. Subject to the terms of the Registration Rights Agreement, we also reserve the right to amend the terms of the Exchange Offer in any manner.

Any such delay in acceptance, extension, termination or amendment will be followed promptly by oral or written notice thereof to the registered holders of old notes. If we amend the Exchange Offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we may extend the Exchange Offer. In the event of a material change in the Exchange Offer, including the waiver by us of a material condition, we will extend the Exchange Offer period if necessary so that at least five business days remain in the Exchange Offer following notice of the material change.

We will not be required to accept for exchange, or exchange any new notes for, any old notes if the Exchange Offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the Exchange Offer as provided in this Prospectus before accepting old notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under “—Purpose and Effect of the Exchange Offer,” “—Procedures for Tendering” and “Plan of Distribution” and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new notes under the Securities Act.

We expressly reserve the right to amend or terminate the Exchange Offer, and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the Exchange Offer specified above. We will give prompt oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

In addition, we will not accept for exchange any old notes tendered, and will not issue new notes in exchange for any such old notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this Prospectus constitutes a part or the qualification of the Indenture relating to the notes under the Trust Indenture Act of 1939.

In order to participate in the Exchange Offer, you must properly tender your old notes to the Exchange Agent as described below. It is your responsibility to properly tender your old notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

Index to Financial Statements

If you have any questions or need help in exchanging your notes, please call the Exchange Agent, whose address and phone number are set forth in “Prospectus Summary—The Exchange Offer—Exchange Agent.”

Substantially all of the old notes were issued in book-entry form and are represented by global certificates held for the account of DTC; none of the old notes are in certificated form (purchasers of old notes in the Senior Notes Offering who have yet to comply with DTC’s requirements in order to include their old notes in DTC’s book-entry system must do so to participate in the Exchange Offer). We have confirmed with DTC that these old notes may be tendered using the Automated Tender Offer Program (“ATOP”) instituted by DTC. The exchange agent will establish an account with DTC for purposes of the Exchange Offer promptly after the commencement of the Exchange Offer and DTC participants may electronically transmit their acceptance of the Exchange Offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the Exchange Offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the Exchange Agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the Expiration Date.

In all cases, we will issue new notes for old notes that we have accepted for exchange under the Exchange Offer only after the Exchange Agent timely receives, in the case of notes tendered via ATOP:

If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes tendered via ATOP will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the Exchange Offer.

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By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

Except as otherwise provided in this Prospectus, you may withdraw your tender at any time prior to 5:00 p.m., New York City time, on the Expiration Date. For a withdrawal to be effective you must comply with the appropriate procedures of DTC’s ATOP system if you tendered your notes via ATOP. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the Exchange Offer.

You may retender properly withdrawn old notes by following the procedures described under “—Procedures for Tendering” above at any time prior to 5:00 p.m., New York City time, on the Expiration Date.

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by facsimile, telephone, electronic mail or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer manager in connection with the Exchange Offer and will not make any payments to broker-dealers or others soliciting acceptances of the Exchange Offer. We will, however, pay the Exchange Agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the Exchange Offer. They include:

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We will pay all transfer taxes, if any, applicable to the exchange of old notes under the Exchange Offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the Exchange Offer.

If you do not exchange new notes for your old notes under the Exchange Offer, you will remain subject to the existing restrictions on transfer of the old notes. In general, you may not offer or sell the old notes unless the offer or sale is either registered under the Securities Act or exempt from the registration under the Securities Act and applicable state securities laws. Except as required by the Registration Rights Agreement, we do not intend to register resales of the old notes under the Securities Act.

We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the Exchange Offer.

Participation in the Exchange Offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent Exchange Offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the Exchange Offer or to file a registration statement to permit resales of any untendered old notes.

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

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The Exchange Offer is intended to satisfy our obligations under the Registration Rights Agreement. We will not receive any proceeds from the issuance of the new notes in the Exchange Offer. In consideration for issuing the new notes as contemplated by this Prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of new notes will not result in any change in outstanding indebtedness.

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The following table sets forth certain unaudited information concerning our proved oil and natural gas reserves as of December 31, 2010 based on the NSAI Report. In preparing its report, Netherland, Sewell & Associates, Inc. evaluated properties representing approximately 100% of our PV-10 value as of December 31, 2010. All of the reserves are located in the United States.

There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. See “Risk Factors—Risks Related to Our Business.” Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantity and present values of our reserves.

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The Standardized Measure is the estimated net future cash inflows from proved reserves less estimated future production and development costs, estimated P&A costs, less income taxes (which we are not subject to) and a discount factor. Production costs do not include depreciation, depletion and amortization of capitalized acquisitions, exploration and development costs. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the year-end commodity prices and any fixed and determinable future price changes provided by contractual arrangements in existence at year end. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end proved reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect.

In calculating the Standardized Measure, future net cash inflows were estimated by using future production of period-end proved reserves and assume continuation of existing economic conditions. The commodity price used for the December 31, 2010 period was $4.609 per Mcfe, which combines the prices for natural gas, oil and natural gas liquids. Prices for each commodity were not available. Future production and development costs are based on estimated costs in effect at the end of the respective period with no escalations. Estimated future net cash flows have been discounted to their present values based on a 10% annual discount rate in accordance with the applicable rules and regulations of the SEC.

The Standardized Measure does not purport, nor should it be interpreted, to present the fair market value of the oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in the future, and the risks inherent in reserve estimates. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.

The Standardized Measure of discounted future net cash flows before income taxes relating to proved oil and natural gas reserves is as follows:

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The following table presents selected financial information for the periods and as of the dates indicated.

The selected statement of operations data for the period from Inception (January 29, 2008) through December 31, 2008 and each of the two years ended December 31, 2009 and 2010, and the balance sheet data as of December 31, 2008, 2009 and 2010 have been derived from our audited financial statements for such periods included elsewhere in this Prospectus. The selected statement of operations data for the three months ended March 31, 2010 and 2011 and balance sheet data as of March 31, 2011 are derived from our unaudited consolidated financial statements included elsewhere in this Prospectus.

The selected unaudited pro forma financial data presented in the following table as of and for the three months ended March 31, 2011 and as of and for the year ended December 31, 2010 are derived from the unaudited pro forma financial statements included elsewhere in this Prospectus. As indicated below, the pro forma financial information for the three months ended March 31, 2011 and for the year ended December 31, 2010 gives effect to the Nippon Acquisition and the Merit Acquisition as if such transactions had occurred on January 1, 2010. The pro forma financial data is not comparable to our historical financial data. A more complete explanation of the pro forma data can be found in our unaudited pro forma condensed consolidated financial statements and accompanying notes included elsewhere in this Prospectus.

The selected unaudited consolidated financial data has been prepared on a consistent basis with our audited consolidated financial statements. In the opinion of management, the selected unaudited consolidated financial data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented.

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For further information that will help you better understand the data set forth below, you should read this financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes and other financial information included elsewhere in this Prospectus.

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The following unaudited pro forma financial data are derived from our consolidated financial statements and certain historical financial data in respect of various assets acquired by us. The unaudited pro forma combined balance sheet as of March 31, 2011 has been prepared assuming the Merit Acquisition had been consummated on March 31, 2011. The unaudited pro forma statement of operations for the three months ended March 31, 2011 was derived from the historical financial statements giving effect to the Merit Acquisition as if it had occurred on January 1, 2010 and the unaudited pro forma statement of operations for the year ended December 31, 2010 includes the historical financial statements giving effect to the Merit Acquisition and Nippon Acquisition as if they had occurred on January 1, 2010.

The unaudited pro forma combined financial data is not indicative of our financial position or our results of operations which would actually have occurred if the transactions described above had occurred at the dates presented or which may be obtained in the future. In addition, future results may vary significantly from the results reflected in such statements due to normal oil and natural gas production declines, changes in prices paid for oil and natural gas, future acquisitions, drilling activity and other factors.

The unaudited pro forma combined financial data include financial information received from Merit Energy and Nippon and such financial information has been accepted and incorporated as presented without independent verification of such financial information.

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The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Prospectus. 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 below, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

We are a privately held 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 economically maximize properties that are currently producing or have the potential to produce given the needed attention and capital resources. We believe that our strategy provides assets to develop and produce with minimal risk, cost or time of traditional exploration. 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.

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

We were organized by John Hoffman and James Hagemeier in the State of Texas. 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 the Indenture governing the notes, 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 has 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 have made strategic decisions to deemphasize their offshore operations. Prior to an acquisition, we perform stringent structural

Index to Financial Statements

engineering tests to determine if we believe that the reservoirs still possess potential upside. Each opportunity is presented, catalogued and high 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, West Cameron 66. In the fourth quarter of 2009, we completed a significant acquisition from W&T Offshore, Inc. (the “W&T Acquisition”), purchasing over 35 fields and 350 wells primarily located on the Gulf of Mexico Shelf encompassing an approximate 71,000 net (195,000 gross) acres.

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. This acquisition consists of six fields and added interests in an additional 40 wells and approximately 6,400 net (13,900 gross) acres to our portfolio. On September 30, 2010, we acquired 27 properties in the Gulf of Mexico from Nippon Oil Exploration U.S.A. (the “Nippon Acquisition”). The Nippon Acquisition includes 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”). The Maritech Acquisition consisted of eight fields and added interests in 43 (105 gross) wells and approximately 22,200 net (45,500 gross) acres.

As of March 2011, we held an aggregate net interest in approximately 178,000 (430,300 gross) acres under lease and had an interest in 799 gross wells, 279 of which are producing.

On May 31, 2011, we completed our previously announced purchase of certain properties from Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P., and Black Elk Energy Offshore Operations, LLC (the “Merit entities”). We acquired interests in various properties across approximately 250,126 gross (127,894 net) 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 Class D Units.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, and environmental hazards, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since our Inception, commodity prices have experienced significant fluctuations. From time to time, we use derivative financial instruments to economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. Our average prices that reflect both the before and after effects of our realized commodity derivative transactions for the periods indicated are shown in the following table.

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The United States and other world economies suffered a severe recession lasting well into 2010 and economic conditions continue to remain uncertain. These uncertain economic conditions reduced demand for oil and natural gas, resulting in a decline in oil and natural gas prices received for our production in 2009 compared with years prior to and including 2008. While oil and natural gas prices have strengthened over the past year, they remain unstable and we expect them to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

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

The primary factors affecting our production levels are capital availability, the success of our drilling program and our portfolio of well work projects. In addition, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline primarily through drilling our existing undeveloped reserves and enhancing our current asset base. Our future growth will depend on our ability to continue to add reserves in excess of production and to bring back to production or increase production on wellbores which 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.

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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.

In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, which was engaged in drilling operations for another operator, sank after an apparent blowout and fire. The resulting leak caused a significant oil spill. In May 2010, in response to the incident, the President of the United States announced a six-month moratorium on drilling in the deepwater Gulf of Mexico (“Federal Deepwater Moratorium” or the “Moratorium”). Under the Federal Deepwater Moratorium, no new drilling, including sidetracks and bypasses of wells, was allowed on wells using subsea BOPs or surface BOPs on a floating facility until November 30, 2010. This federal ban was lifted by the U.S. Secretary of the Interior on October 12, 2010. For affected operators such as us, new, more restrictive requirements have been implemented on permitting activities on the Outer Continental Shelf.

During the quarter ended September 30, 2010, the Outer Continental Shelf Safety Oversight Board, established by the U.S. Secretary of the Interior, issued its recommendations for the strengthening of permitting, inspections, enforcement and environmental stewardship. In addition, the BOEMRE developed an implementation plan for the recommendations, many of which are already underway or planned.

On September 30, 2010, the U.S. Department of the Interior announced two new rules (The Drilling Safety Rule and the Workplace Safety Rule) that are intended to improve drilling safety by strengthening requirements for safety equipment, well control systems, and blowout prevention practices on offshore oil and gas operations, and improve workplace safety.

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. These changes may result in increases in our operating and development costs, delay the issuance drilling permits as the new restrictions are fully implemented, and extend project development timelines because of the new regulatory requirements. There may be other impacts of which we are not aware at this time.

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 security. In certain circumstances, consultants are used to supplement our resource needs.

For our Gulf of Mexico operations, we have a Regional Oil Spill Plan in place with the BOEMRE. Our response team is trained annually and is tested through annual spill drills as required by the BOEMRE. In addition, we have in place a contract with Environmental Safety & Health Consulting Services, Inc. (“ES&H”), who is our designated Oil Pollution Act spill response contractor. ES&H maintains 24 hour, seven day a week manned incident command centers located in Houston, Texas and Houma, Louisiana. Our spill program is put into motion by notifying ES&H in the event 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

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North America. CGA specializes in onsite control and cleanup and is on 24 hour alert with equipment currently stored at six bases (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 retainers with an aerial dispersant company and a company that provides mechanical recovery equipment for spill responses. CGA equipment includes:

Source control support will be provided by Wild Well Control. 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 includes the following 13 mandatory elements of the American Petroleum Institute’s Recommended Practice 75 (“API RP 75”):

We are currently on track to comply with the SEMS requirements on or before the November 15, 2011 deadline.

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We use a variety of financial and operational measures to assess our overall performance. Among these measures are (1) volumes of oil and natural gas produced, (2) oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) Adjusted EBITDA (as defined in the following table). The following table contains financial and operational data for each of the three months ended March 31, 2011 and 2010, for each of the years ended December 31, 2010 and 2009 and for the period from Inception (January 29, 2008) to December 31, 2008.

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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.

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.

Depreciation, depletion and amortization. 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 ASC 360-10-15 Impairment or Disposal of Long-Lived Assets, which 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.

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-derivative contracts were based

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upon futures which 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.

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

Income tax provision. We report as a partnership for federal income tax purposes. 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 these 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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The following table sets forth our unaudited results of operations for the three months ended March 31, 2011 and 2010, for each of the years ended December 31, 2010 and 2009 and for the period from Inception (January 29, 2008) to December 31, 2008.

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Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010

Oil and natural gas production. Total oil, natural gas and plant product production of 984 MBoe increased 536 MBoe or 119% in the first quarter 2011 compared to the same period 2010. The increase in production in 2011 was primarily a result of three months of production from the properties acquired in the Nippon Acquisition and additional production acquired from Maritech.

Total revenues. Total revenues for the three months ended March 31, 2011 of $24.5 million decreased $1.3 million, or 5%, over the comparable period in 2010. The decrease in revenues was a result of a $31.0 million unrealized loss on derivative financial instruments offset by an increase in oil, natural gas and plant product sales resulting from increased production related to the properties acquired in the Nippon Acquisition and the Maritech Acquisition and higher commodity prices.

We entered into certain oil and natural gas commodity derivative contracts in 2011 and 2010. We realized losses on these derivative contracts in the amount of $0.3 million for the three months ended March 31, 2011 and gains of $1.7 million for the three months ended March 31, 2010. We recognized unrealized losses of $31.0 million for the three months ended March 31, 2011 and unrealized gains of $0.8 million for the three months ended March 31, 2010. Excluding the realized and unrealized revenues from commodity hedge contracts, revenues for the three months ended March 31, 2011 and 2010 were $55.8 million and $23.3 million, respectively. Revenues, excluding hedging activity, increased $32.5 million for the three months ended March 31, 2011 compared to the comparable 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 $99.49 per barrel and $75.98 per barrel and gas prices of $4.52 per Mcf and $5.34 per Mcf for the three months ended March 31, 2011 and 2010, respectively. The increase in average prices realized from the sale of oil and natural gas reflected the economic turnaround that began during 2010.

Lease operating costs. Our lease operating costs for the three months ended March 31, 2011 increased to $23.1 million, or $23.43 per Boe, from $6.8 million, or $15.24 per Boe over the comparable period in 2010. The increase in lease operating costs is directly related to the increase in properties from the Nippon Acquisition and the Maritech Acquisition. The increase in cost per Boe for the three months ended March 31, 2011 is primarily attributable to a mix of increased properties and the related workover activities, coupled with lower production in the first two months of the period.

Workover costs. Our workover costs for the three months ended March 31, 2011 and 2010 were $3.2 million and $0.4 million, respectively. For the three months ended March 31, 2011, the primary workover expense projects were South Pass 89, Main Pass 76, Vermilion 124, Vermilion 196, West Cameron 66 and Galveston Island 424.

Depreciation, depletion and amortization. DD&A expense was $8.0 million and $6.6 million for the three months ended March 31, 2011 and 2010, respectively. In 2011, the increase in DD&A 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

General and administrative expenses. G&A expense totaled $4.5 million and $2.0 million for the three months ended March 31, 2011 and 2010, respectively. The increase in G&A expense in 2011 resulted primarily from costs associated with the increase in staff and related administrative costs attributable to our growth in 2010.

Index to Financial Statements

Accretion expense. We recognized accretion expense of $3.9 million and $1.8 million for the three months ended March 31, 2011 and 2010, respectively. The increase in accretion expense in 2011 was attributable to increased asset retirement obligations acquired in 2011 and 2010.

Interest expense. We incurred $5.8 million and $2.2 million of interest expense for the three months ended March 31, 2011 and 2010, respectively. The $3.6 million increase of interest expense in 2011 compared to 2010 was a result of 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 plug and abandonment costs and amortization of credit 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.

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).

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 Acquisition and the Nippon Acquisition 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 increase in average prices realized from the sale of oil and natural gas reflected the economic turnaround that began during 2010.

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 Acquisition and the Nippon Acquisition.

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 Acquisition and the Nippon Acquisition 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.

Index to Financial Statements

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 Acquisition and the Nippon Acquisition. 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 Acquisition and the Nippon Acquisition.

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 acquisitions 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 Offshore, Inc. as a 3% fee on the shortfall of funding the Operated Properties Escrow Account. In November 2010, we fully funded the Operated Properties Escrow Account.

Year Ended December 31, 2009 Compared to Period from Inception (January 29, 2008) to December 31, 2008

Oil and natural gas production. Oil, natural gas and plant product production of 555 MBoe in 2009 increased 342 MBoe, or 160%. over 2008. The increase in 2009 was primarily due to higher production of 101 MBoe on South Timbalier 8 and West Cameron 66 (collectively the “Legacy Assets”) over the same period in 2008 and 241 MBoe of production attributable to the 35 fields acquired in the W&T Acquisition.

Total revenues. Total revenues for the year ended December 31, 2009 of $18.8 million represented an increase of $5.8 million, or 44.6%, as compared to total revenues of $13.0 million for the comparable period in 2008. Revenues decreased $3.6 million, or 28%, on the 2008 Legacy Assets as a result of higher production offset by lower natural gas prices, and the properties acquired in the W&T Acquisition attributed $11.4 million in revenues. Plant product revenues of $0.4 million in 2009 related to the properties acquired in the W&T Acquisition. The decline in average prices realized from the sale of oil and natural gas reflected the sharp economic decline that began during the second half of 2008 and continued through 2009. In addition, natural gas prices remained weak through 2009 due to high natural gas storage levels.

Index to Financial Statements

We entered into certain oil and natural gas commodity hedge contracts in 2009; there were no hedge contracts in place in 2008. The average realized oil price including hedge settlements was $71.59 per Bbl and the average realized natural gas price was $4.55 per Mcf for the year ended December 31, 2009. The average Henry Hub gas price was $3.94 per Btu for the year ended December 31, 2009 and $8.89 per Btu for the same period in 2008. The average WTI price was $61.98 per Bbl for the year ended December 31, 2009 and $99.92 per Bbl for the same period in 2008. Excluding the effects of the $0.8 million of realized gain on derivative financial instruments and $2.8 million unrealized loss on derivative financial instruments, we recognized $20.8 million in revenues in the year ended December 31, 2009 and $13.0 million in revenues for the period Inception (January 29, 2008) to December 31, 2008.

Lease operating costs. Our lease operating costs for 2009 increased to $8.6 million, or $15.55 per Boe, from $3.9 million in 2008, or $18.34 per Boe. The increase in lease operating costs in 2009 from the comparable period in 2008 was primarily a result of lease operating costs associated with the properties acquired in the W&T Acquisition.

Production taxes. Production taxes for 2009 increased to $0.5 million, or $0.96 per Boe, from $0.4 million or $2.05 per Boe for the same period in 2008. Although production and revenues increased significantly, production taxes did not increase at the same rate as many of the properties acquired in the W&T Acquisition were located in federal waters and not subject to production taxes.

Workover costs. Our workover costs for 2009 decreased to $0.9 million from $5.6 million in 2008. Workover activity in 2009 and 2008 was performed on the South Timbalier 88 field, but we decreased the workover activity in 2009.

Depreciation, depletion, amortization and impairment. DD&A expense for 2009 increased to $15.4 million from $3.3 million in 2008. The increase in DD&A expense was the result of increased production and the incremental depletion associated with the properties acquired in the W&T Acquisition. We recorded $0.4 million impairment with respect to one asset in 2009.

General and administrative expenses. G&A expenses of $7.2 million in 2009 increased $3.8 million, or 112%, from $3.4 million in 2008. The increase in G&A expense resulted principally from costs associated with the W&T Acquisition ($1.3 million), increased payroll and related expenses and benefits resulting from an increase in staff primarily related to the W&T Acquisition ($0.8 million), increased property taxes ($0.3 million) and increased professional fees ($0.3 million).

Accretion expense. We recognized accretion expense of $0.4 million for the year ended December 31, 2009 as compared to $0.4 million in 2008. The slight increase in accretion expense for 2009 related to the properties acquired in the W&T Acquisition and lower accretion on the South Timbalier 8 as a result of the extended life on the asset.

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, plug and abandonment, and re-drill costs were reimbursed by the insurance company as expenditures were incurred. We recognized a gain due to the involuntary conversion of asset in 2009 of $18.7 million and $9.5 million in the period from Inception (January 29, 2008) to December 31, 2008.

Interest expense. In 2009, interest expense increased $2.6 million to $3.7 million, from $1.1 million in 2008 due to changes in outstanding debt balances and the associated fixed interest rates.

Index to Financial Statements

Our primary sources of liquidity to date have been capital contributions from our members, proceeds from the Senior Notes Offering, which closed in November 2010, borrowings under our line of credit with Platinum 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 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.

On December 24, 2010, we entered into an aggregate $110 million of credit facilities with Capital One, N.A., as administrative agent and a lender thereunder. The credit facility is comprised of a (1) $35 million senior secured revolver and (2) $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. 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.

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.

No borrowings were outstanding under the credit facility at March 31, 2011. As of June 15, 2011, letters of credit in the aggregate amount of $27.3 million were outstanding under this facility and we had $45.0 million in borrowings under the revolver. As of June 15, 2011, $122.7 million was available for additional borrowings, including $25 million under the revolver.

See “Description of Other Indebtedness—Capital One Credit Facility” for additional information with respect to our credit facility.

On November 23, 2010, we closed the Senior Notes Offering and issued $150 million in aggregate principal amount of 13.75% Senior Secured Notes (which are referred to herein as the “notes”) discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under our line of credit with Platinum, to fund BOEMRE collateral requirements and to prefund the W&T Escrow Accounts. We pay interest on the notes semi-annually, on June 1st and December 1st of each year, in arrears, commencing on 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 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, 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 the Indenture governing the 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.

Index to Financial Statements

On May 23, 2011, we commenced a consent solicitation that was completed on May 31, 2011 under the First Supplemental Indenture to the Indenture. The First Supplemental Indenture amended the Indenture, among other things, to: (1) increase the amount of capital expenditures permitted to be made by us on an annual basis, (2) enable us to obtain financial support from our majority equity holder by way of a $30 million investment in Class D Units that 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 it meets certain defined financial tests and as permitted by our credit facilities.

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%.

We have a total capital expenditure budget of $19.5 million for 2011 (excluding expenditures directly related to any acquisitions, including the Merit Acquisition, which closed on May 31, 2011 for a purchase price of approximately $39 million), which is a 23% decrease under the approximately $25.4 million of capital expenditures (excluding acquisitions) during 2010. Approximately $5.5 million of our 2011 capital budget was used in the first three months of 2011, and the remaining $14.0 million will be used for workover costs and drilling and development during the remainder of the year. The NSAI Report includes an assumption that we will spend $19.9 million in capital expenditures during 2011. We believe there may be opportunities to achieve the same or greater production than what is projected.

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 2011 capital budget has been funded from contributions from our members, borrowings under our line of credit with Platinum 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 2011 capital expenditure budget.

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Oil and Natural Gas Hedging” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”

Index to Financial Statements

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. 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.

The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the three months ended March 31, 2011 and 2010, for the years ended December 31, 2010 and 2009 and for the period of Inception (January 29, 2008) to December 31, 2008:

Cash flows provided by (used in) operating activities. 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 “—Quantitative and Qualitative Disclosures About Market Risk” below.

Cash flows used in investing activities. Cash used in investing activities during the first three months of 2011 was attributable to the assets purchased in the Maritech Acquisition and the funding of the future P&A obligations through escrow and restricted cash. Cash used in investing activities during the comparable period of 2010 was attributable to the assets purchased in the period and the funding of the escrow account for future P&A obligations. The increase in cash used in investing activities during the year ended December 31, 2010 as compared to 2009 was 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 increase in cash used in investing activities during the year ended December 31, 2009 as compared to 2008 was attributable to the assets purchased in the W&T Acquisition and the funding of the W&T Escrow Accounts securing our P&A obligations with respect to the acquired properties.

Cash flows provided by (used in) financing activities. Cash flows used in financing activities during the three months ended March 31, 2011 were attributable to the repayment of short term notes payable, distributions to members and debt issuance costs of the notes. Cash flows used in financing during the compared period of 2010 related primarily to the repayment of debt. The increase in cash flows provided by financing activities during the year ended December 31, 2010 as compared to 2009 was attributable to the issuance of the notes partially offset by the repayment of borrowings under our lines of credit with Platinum. The increase in cash flows provided by financing during the year ended December 31, 2009 as compared to 2008 related primarily to borrowings to fund the W&T Acquisition.

Index to Financial Statements

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, (1) establish separate escrow accounts with respect to the Operated Properties and the Non-Operated Properties, (2) 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, (3) grant a second priority security interest to W&T on the W&T Properties and (4) 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.

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 from (1) the Operated Properties Escrow Account without the consent of W&T or (2) 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.

As many as four times per year we review, and, to the extent necessary, revise our asset retirement obligation estimates, which primarily relate to our P&A obligations. During 2008, we increased our asset retirement obligations by $3.9 million and recognized accretion expense of $0.4 million. In 2009, primarily as a result of the W&T Acquisition, we increased our asset retirement obligations by $46.6 million and recognized

Index to Financial Statements

$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. For the three months ended March 31, 2011 and 2010, we increased our asset retirement obligations by $15.1 million and $7.6 million, respectively, and recognized $3.9 million and $1.8 million, respectively, in accretion expense.

At March 31, 2011 and December 31, 2010, we recorded total asset retirement obligations of $137.3 million and $122.2 million, respectively, and have funded approximately $117.8 million and $114.2 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds.

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, 2010.

In October 2010, we guaranteed a loan in the aggregate principal amount of $3.2 million for a related party (see “Certain Relationships and Related Transactions”). We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

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

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

At December 31, 2010, commodity derivative instruments were in place covering approximately 47% of our projected oil sales volumes and 38% or our projected natural gas sales volumes through 2011.

Index to Financial Statements

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

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. 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.

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 quarterly 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

Index to Financial Statements

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, 2010 and 2009, 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 FASB ASC 815, Derivatives and Hedging, as amended, 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 of FASB ASC 815-30, 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 three months ended March 31, 2011 and 2010 and for the years ended December 31, 2010 and 2009 and for the period from Inception (January 29, 2008) to December 31, 2008, 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.

Asset Retirement Obligations: Effective January 1, 2008, we adopted FASB ASC 410-20-15 Accounting for Asset Retirement Obligations (“ASC 410-20-15”), using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement obligations, and accumulated depreciation. ASC 410-20-15 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

Index to Financial Statements

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 December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting (the “Final Rule”). The Final Rule is intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves, which should help investors evaluate the relative value of oil and natural gas companies. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than year-end prices. In January 2010, the FASB issued ASU 2010-03, Extractive Activities—Oil and Gas (Topic 932) Oil and Gas Reserve Estimation and Disclosures (“ASU 2010-03”), which aligns the oil and natural gas reserve estimation and disclosure requirements of ASC 932 with the requirements in the SEC’s Final Rule, Modernization of the Oil and Gas Reporting Requirements discussed above. We adopted the Final Rule and ASU effective December 31, 2009. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.

In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820) Improving Disclosures about Fair Value Measurements, which enhances the usefulness of fair value measurements. The amended guidance requires both the disaggregation of information in certain existing disclosures, as well as the inclusion of more robust disclosures about valuation techniques and inputs to recurring and nonrecurring fair value measurements.

The amended guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disaggregation requirement for the reconciliation disclosure of Level 3 measurements, which is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. We adopted ASU 2010-06 effective December 31, 2010, and the adoption did not have a significant impact on our financial statements.

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three months ended March 31, 2011 and 2010, for the years ended December 31, 2010 and 2009 and for the period of Inception (January 29, 2008) to December 31, 2008. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

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

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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.

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 average daily production for the three months ended March 31, 2011, our quarterly revenue would have increased or decreased by approximately $3.8 million for each $10.00 per barrel change in oil prices and $3.3 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging. Based on our average daily production for the year ended December 31, 2010, our revenues would have increased or decreased by approximately $13.3 million for each $10.00 per barrel change in oil prices and $14.6 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 March 31, 2011 and December 31, 2010, the fair value of our commodity derivatives were included in the consolidated balance sheets for approximately $20.4 million and $3.8 million, respectively, as current liabilities and $26.0 million and $11.7 million, respectively, as long-term liabilities. For the three months ended March 31, 2011 and 2010 and for the years ended December 31, 2010 and 2009, we realized a net increase (decrease) in oil and natural gas revenues related to hedging transactions of approximately ($0.3) million, $1.7 million, $9.3 million and $0.8 million, respectively. No hedges were in place during the period from Inception (January 29, 2008) to December 31, 2008.

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

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Subsequent to March 31, 2011, we entered into the following commodity derivative contracts:

For further discussion of our hedging activities, please see “Notes to Consolidated Financial Statements—Note 8—Derivative Instruments” included in this Prospectus.

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through joint interest receivables, which totaled $5.5 million at March 31, 2011, $2.1 million at March 31, 2010, $4.2 million at December 31, 2010 and $0.4 million at December 31, 2009. We also have exposure to credit risk from the sale of our oil and natural gas production that we market to energy marketing companies and refineries, the receivables for which totaled $26.9 million at March 31, 2011, $8.4 million at March 31, 2010, $21.8 million at December 31, 2010 and $9.8 million at December 31, 2009. 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.

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. In this manner, we reduce credit risk. 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.

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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.

Prior to 2010, our line of credit with Platinum had a fixed interest rate, therefore, we have not historically been exposed to changes in interest rates on our debt. The notes have a fixed interest rate. In December 2010, we entered into the 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. No borrowings were outstanding under the credit facility at March 31, 2011. As of June 15, 2011, we had an aggregate amount of $72.3 million of variable interest rate indebtedness outstanding. 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 “Description of Other Indebtedness—Capital One Credit Facility” for additional information on our credit facility.

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We are a privately held 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 have made strategic decisions to deemphasize their offshore operations. In addition to our acquisition strategy, we continue to develop and 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.

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 federal waters in the Gulf of Mexico, the West Cameron 66. On October 29, 2009, the Company completed the W&T Acquisition, purchasing interests in over 35 fields and 350 wells across approximately 71,000 net (195,000 gross) acres in U.S. federal waters in the outer continental shelf of the Gulf of Mexico. The W&T Properties also include 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 P&A obligations associated with the W&T Properties, subject to customary effective-date adjustments and closing adjustments. As of December 31, 2010, the W&T Properties had a PV-10 value, of $214 million and estimated proved reserves of 10.3 MMBoe, which accounted for approximately 54% of our total PV-10 value and approximately 47% of our total proved reserves at such time, based on the NSAI Report.

In 2010, we completed two additional acquisitions, the latter of which, the Nippon Acquisition, was completed on September 30, 2010. During the first quarter of 2010, we acquired six fields and added interests in an additional 40 wells and approximately 6,400 net (13,900 gross) acres, primarily located within Texas state waters in the Gulf of Mexico. In the Nippon Acquisition, we acquired interests in 27 properties across approximately 103,130 net (195,944 gross) acres in the Gulf of Mexico. The Nippon Properties include 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, 2010, the Nippon Properties had a PV-10 value of $169.5 million and estimated proved reserves of 9.6 MMBoe, which accounted for approximately 43% of our total PV-10 value and approximately 44% of our total proved reserves at such time.

On May 31, 2011, we acquired from certain private sellers interests in various properties across approximately 250,126 gross (127,894 net) acres in the Gulf of Mexico for a purchase price of $39 million plus the assumption of approximately $168.4 million (based on current estimates) of undiscount P&A obligations associated with the acquired properties, subject to customary effective-date adjustments and closing adjustments.

At closing, we paid $33 million in surety bonds and established an escrow account to secure the performance of our P&A obligations and other indemnity obligations with respect to P&A and/or

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decommissioning of the acquired wells and facilities. We are required to deposit into such escrow account an aggregate principal amount equal to $60 million, which is to be paid by us in 30 equal monthly installments, payable on the first day of each month, commencing on the first day of the month following closing.

The indenture, dated as of November 23, 2010, among the us, the subsidiary guarantor party thereto and The Bank of New York Mellon Trust Company, N. A., as trustee (the “Indenture”), under which the old notes were issued and the new notes will be issued, restricted our ability to finance the remainder of the purchase price and complete the acquisition. Accordingly, we conducted a consent solicitation and obtained from the holders of the old notes the consents necessary to approve certain amendments to the Indenture, to, among other things, allow us to finance the Merit Acquisition. On May 31, 2011, we entered into the First Supplemental Indenture with our subsidiary guarantor and the Trustee in order to effect the proposed amendments.

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 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.

See “Description of Other Indebtedness—Capital One Credit Facility” for additional information with respect to our credit facility.

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The following table sets forth our estimated net proved reserves, future net cash flows and the present value of such future cash flows as of December 31, 2010 based on the NSAI Report. The 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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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 (437) MBoe during 2008 was mainly due to a decrease in commodity prices, a revision of 2,225 MBoe during 2009 was mainly due to reactivations of inactive wells and improved performance of active wells and a revision of 3,678 MBoe during 2010 was mainly due to continued reactivation program and improved performance of actual wells.

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. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum engineers estimated, in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers and definitions and guidelines established by the SEC, 100% of our proved reserve information as of December 31, 2010 included in this Prospectus. 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 21 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 Financial Officer and certain other members of senior management.

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.

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Proved Undeveloped Reserves. Our proved undeveloped reserves at December 31, 2010 were 4.6 MMBoe, consisting of 2.4 MMBbls of oil and 13.6 Bcf of natural gas. Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2010, as shown in the NSAI Report, is $53.4 million, of which 2011 and 2012 expenditures are estimated to be $10.9 million and $1.3 million, respectively. All proved undeveloped reserves are scheduled to be drilled by 2014. We are unsure what effect, if any, the BOEMRE’s moratorium on the drilling of wells using subsea BOPs or surface BOPs on a floating facility until November 30, 2010 will have on this lease and our estimated proved reserves at December 31, 2010. We are also unsure what effect, if any, amendments to OPA will have on our offshore operations.

We have a total capital expenditure budget of $19.5 million for 2011, excluding expenditures directly related to acquisitions, which is a 23% decrease over the approximately $25.4 million (excluding acquisitions) invested during 2010. Approximately $5.5 million of our 2011 capital budget was used in the first three months of 2011, and the remaining $14.0 million will be used for workover costs and drilling and development. The NSAI Report includes an assumption that we will spend $19.9 million in capital expenditures during 2011. We believe there may be opportunities to achieve the same or greater production than what is projected. To date, our 2011 capital budget has been funded from contributions from our members, borrowings under our lines of credit with Platinum 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 2011 capital expenditure budgets.

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Oil and Natural Gas Hedging” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”

We actively 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 First Supplemental Indenture governing the notes restricts the amount of capital expenditures that we may make each year to $60 million for fiscal year 2011 and 30% of Consolidated EBITDAX (as defined in the Indenture) for each subsequent year.

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The following table presents the total gross and net developed and undeveloped acreage by region as of December 31, 2010:

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2010 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:

While we may attempt to secure a new lease upon the expiration of certain of our acreage, there are some third-party leases that may become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. Our leases are mainly federal leases with five years of primary term.

During the two years ended December 31, 2010, we drilled development wells as set forth in the table below:

At December 31, 2010, we did not have any wells that were in the process of drilling, completing or waiting on completion. We also recompleted 16 wells during 2010, 12 of which are currently producing. As of December 31, 2010, we were not operating any rigs on our properties. In 2011 to date, we have drilled one development well. Our rig activity during the remainder of 2011 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.

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We have a geographically diverse asset portfolio, which spans the Gulf Coast energy corridor. As of December 31, 2010, our leasehold position encompassed approximately 155,800 net (384,800 gross) acres, 245 net (694 gross) wells and 133 production platforms. As of December 31, 2010, we operated approximately 43% of the fields and 39% of the wells in our asset portfolio.

The following describes our significant properties as of December 31, 2010, which at such time accounted for approximately 66% of our total PV-10 value based on the NSAI Report, and approximately 43% of our total proved reserves, totaling 9.3 MMBoe.

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 2008 and through 2009. 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.

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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, 2008, 2009 and 2010. For additional information on price calculations, see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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 3 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 $2.79 per Boe, or 18%, to $18.34 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.

Net production volumes for the year ended December 31, 2009 were 555 MBoe, a 156% increase from net production of 214 MBoe for 2008. Our net production volumes increased 341 MBoe over 2008 net production volumes mainly due to the successful drilling and completion of offshore wells in Louisiana state and federal Waters. Our average oil sales prices, without the effect of realized derivatives, decreased $29.08 per Bbl to $70.43 per Bbl for the year ended December 31, 2009 from $99.51 per Bbl for the year ended December 31, 2008. Giving effect to our derivative transactions in both periods, our oil prices decreased only $27.92 per Bbl to $71.59 per Bbl for the year ended December 31, 2009 from $99.51 per Bbl for the year ended December 31, 2008. Our lease operating expenses decreased $3.17 per Boe, or 17.3%, to $15.17 per Boe for the year ended December 31, 2009 from $18.34 per Boe for the year ended December 31, 2008 mainly due to new offshore production.

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The following table sets forth information regarding our average net daily production for the years ended December 31, 2009 and 2010:

The following table presents the total gross and net productive wells by project area and by oil or gas completion as of December 31, 2010:

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.

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 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 the Company’s oil and natural gas sales:

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.

We encounter intense 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.

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Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and natural gas business for a much longer time than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

We lease approximately 17,000 square feet of office space in Houston, Texas. This lease expires on December 1, 2020.

As of June 15, 2011, we had 89 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

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

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.

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

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Platinum is managed by PMNY. One of PMNY’s principals is Mark Nordlicht. Mr. Nordlicht has been named, along with other defendants, in a consolidated amended class action complaint as a former director of Optionable, Inc., a brokerage firm for energy options which he founded in 2000. Mr. Nordlicht was not active in the daily business operations of Optionable, although he served on its Board of Directors from its inception until May 1, 2007.

In April 2010, PMNY was named in two civil suits pertaining to a senior secured loan PMNY made to Banyon Investments, LLC. Banyon is currently in default on these loans and the assets that Banyon was acquiring with these loans were fabricated by South Florida attorney Scott Rothstein as part of what has been reported to be a larger fraudulent scheme. PMNY has been sued by the bankruptcy trustee in the U.S. Bankruptcy court for the Southern District of Florida for Mr. Rothstein’s now-defunct Florida law firm, who seeks to recover transfers made by Mr. Rothstein to Banyon, and from Banyon to PMNY, on the theories that those transfers were “preferences” under the Bankruptcy Code and/or were made by Mr. Rothstein to defraud others. PMNY has also been sued by a group of investors in Mr. Rothstein’s program in the Circuit Court for Broward County, Florida who claim that PMNY had a duty to protect them from Mr. Rothstein and conspired with Mr. Rothstein to defraud them. PMNY maintains that these actions are without merit. Although these are the only matters currently pending, other actions and claims could be brought against PMNY and its affiliates in connection with the Banyon investment. Such claims could seek damages from such parties and/or disgorgement of amounts received by them.

In the ordinary course of its business Platinum, is involved in litigation to pursue claims and defend its rights on behalf of its investors.

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 $100,000. 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 are currently awaiting a response from BOEMRE on the matter.

Our exploitation, development and production operations 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 the acquisition of permits to conduct exploitation, drilling and production operations; restrict the amounts and types of substances that may be released into the environment or the way 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 construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require

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investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; impose obligations to reclaim and abandon well sites, and impose substantial liabilities on us 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 required 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, health and safety laws and regulations 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.

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 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. However, in the last session of Congress, a variety of amendments to the Oil Pollution Act of 1990 (“OPA”) was considered by the legislative body in response to the Deepwater Horizon incident in the Gulf of Mexico, 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 during the current session of Congress. 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

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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 there were to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which could be material to our results of operations and financial position.

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 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 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 RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we generate waste as a routine part of our operations that may be subject to RCRA. Although a substantial amount of the waste generated in our operations are regulated as nonhazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of nonhazardous waste or categorize some nonhazardous waste as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

We currently lease or operate numerous offshore properties in U.S. federal waters and Louisiana and Texas state waters that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released from these offshore locations or from onshore third party locations where such substances have been taken for recycling or disposal. In addition, some

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of these offshore properties have been operated by third parties or by previous lessees or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons were not under our control. These offshore and onshore properties and the substances disposed or released on or from them may be subject to OPA, RCRA, CERCLA and analogous state laws. In the future, we could be required to conduct remediation, including remediation of groundwater, containing or impacted by previous releases or disposal of wastes (including wastes disposed or released by prior lessees or operators, or property contamination, including groundwater contamination by prior lessees or operators) or to perform restoration of properties or plugging of abandoned wells to prevent future or mitigate existing contamination.

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (the “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.

Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction and also impose various monitoring and reporting requirements. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.

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 begun adoptions and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA has adopted two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources effective January 2, 2011. On June 3, 2010, EPA published its final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s PSD and Title V permitting programs. The final rule tailors the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 8, 2010, the EPA finalized regulations amending the reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and gas processing, transmission, storage and distribution facilities. Reporting of greenhouse gas emissions from such facilities would be required on an annual basis beginning in 2012 for emissions occurring in 2011.

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In addition, Congress has, from time to time, actively considered legislation to reduce such emissions 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.

Our operations are subject to the requirements of the federal 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 continued compliance with existing requirements will not have 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 three months ended March 31, 2011 or for the years ended December 31, 2010, 2009 and 2008. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2011 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 the passage of more stringent laws and regulations in the future will not have a negative impact our business activities, financial condition or results of operations.

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

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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.

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:

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.

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

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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.

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.

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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.

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.

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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.

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The following table sets forth the names, ages and offices of our present directors, executive officers and other key employees. There are 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.

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 finalist in Ernst & Young’s 2010 Entrepreneur of the Year.

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 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.

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Doug Fehr. Doug Fehr serves as our Vice President of Facilities, a position he has held since May 2008. He brings 30 years 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 has 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 21 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 has 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 to 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.

Index to Financial Statements

Because the registration statement of which this Prospectus forms a part 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 made any determination as to whether any of its members or 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.

Index to Financial Statements

Our executive compensation program is overseen by our Chief Executive Officer, Chief Financial Officer, and Human Resource Specialist (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 Committee. The Committee then evaluates our Chief Executive Officer’s recommendations and conducts its own 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 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, 2010, and who are described in this Compensation Discussion and Analysis section, are:

The objective of our executive compensation program is to attract and retain experienced leaders in their respective fields of expertise to work as a member 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 their 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’s 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.

Index to Financial Statements

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

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 their 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. The base salary for each named executive for the 2010 fiscal year is reported in the succeeding Summary Compensation Table.

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 determines 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 employees total compensation for the year, as determined in the Committee’s discretion based on their 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

Index to Financial Statements

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.

In 2010 cash bonuses were awarded to our named executive officers on October 14, 2010 and November 30, 2010. The October bonus was awarded for the successful completion of a strategic acquisition. 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 October bonus was determined by the Committee after considering each executive’s contribution to and impact on our ability to successfully complete the acquisition as well as their overall annual compensation. We awarded a cash bonus for 2010 performance at the end of November. When setting the amount of the bonus pool for the year-end bonus the Committee considered our overall financial performance and the achievement of business goals, such as the closing of a strategic acquisition. Individual awards were set by the Committee after considering each 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 directors approved the bonus pool amount. The cash bonuses awarded to each of our named executive officers is reported in the succeeding Summary Compensation Table.

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 profits interests in Black Elk Energy, LLC, from fiscal year 2010 forward we plan only to grant profits interests to our executives through the Incentive Plan.

The Incentive Plan provides our executives with an opportunity to share in the distributions made to our investors. During 2010, 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.

Messrs. Hoffman and Hagemeier have employment agreements with us that 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

Index to Financial Statements

entitled to receive a lump-sum severance payment in an amount equal to one year’s annual base salary of the executive, plus 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 in the event of certain terminations of employment that were beyond their control. Post-termination payments allow 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 the named executive officers above 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.

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 provide Mr. Hoffman with enhanced life and disability insurance, provide Mr. Fehr with enhanced disability insurance, and provide Messrs. Hofman 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.

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.

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:

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.

Index to Financial Statements

No actions, nor updates, to policies and practices with regard to the named executive officers have been implemented after December 31, 2010.

The table below sets forth the annual compensation earned during the 2010 Fiscal Year by our “named executive officers,” as of December 31, 2010:

Index to Financial Statements

The percentages in this table represent each named executive officer’s right to indirectly receive a certain percentage of our distributable income granted in 2010 and contingent upon certain circumstances as described in the narrative below.

Narrative Description to the Summary Compensation Table and Grants of Plan-Based Awards Table for the 2010 Fiscal Year

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.

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 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 until the earlier of (i) the repayment in full of the obligations under a credit agreement, and (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 and July 13, 2012. The Employment Agreements also contain non-disparagement and confidentiality obligations.

Index to Financial Statements

The awards enumerated in the Grants of Plan-Based Awards Table reflect each named executive officer’s total interest in our distributions. These interests are held indirectly through interests in Incentive LLC (which in turn owns all of our Class C Units). Garza, Hammond and Fehr also hold interests in us indirectly through Black Elk Energy, LLC (which in turn holds some of our Class B Units), but those are not reflected in the Grants of Plan Based Awards Table because all interests held by our named executive officers in Black Elk Energy, LLC were granted prior to 2010. All interests held by our named executive officers in Incentive LLC were granted during 2010 under our Incentive Plan. 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 (and our subsidiaries’) 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.

Messrs. Hoffman and Hagemeier also hold interests in us through Incentive LLC, Black Elk Energy, LLC, and otherwise but such ownership is not compensatory in nature and therefore any distributions made to them during 2010 were not compensatory and not reported in the Grants of Plan-Based Awards Table or the Summary Compensation Table above.

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 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, and (v) material breach by executive of any material provision of the Employment Agreements which is not corrected for 30 days after 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.”

Index to Financial Statements

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, 2010, (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.

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.

Index to Financial Statements

Our membership interests are represented by Class A Units, Class B Units, Class C Units and Class D Units. As of June 15, 2011, 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 own 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, another 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 “Certain Relationships and Related Transactions.”

Our executive officers and other key employees indirectly own Class B Units through their ownership of Black Elk Energy, LLC. See “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 in which are awarded from time to time to our executive officers and other key employees. See “Executive Compensation—Components of Our Compensation—Profit Sharing” for additional information regarding the Class C Units.

The following table sets forth information regarding the beneficial ownership of our total voting membership interests, consisting of our Class A and Class B Units, as of June 15, 2011 for:

Footnote 1 to the following table provides a brief explanation of what is meant by the term “beneficial ownership.” The voting membership interests and related percentages of beneficial ownership are based on our total outstanding voting membership interests as of June 15, 2011. The amounts presented may not add due to rounding.

Index to Financial Statements

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

Index to Financial Statements

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 Prospectus), 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:

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.

Index to Financial Statements

For additional information regarding the risk associated with Platinum’s significant ownership interest is us, see “Risk Factors—Platinum owns approximately 75% of our outstanding voting membership interests, giving it influence and control in corporate transactions and other matters, which may conflict with noteholders’ interests.”

Index to Financial Statements

Since January 29, 2008, there has not been, nor is there currently proposed, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive Compensation” and the transactions described or referred to below.

On July 13, 2009, we entered into a line of credit agreement with Platinum, our majority equity holder, to borrow an amount up to a maximum borrowing base of $75.0 million to fund drilling and completion costs on wells. The line of credit carried an interest rate of 20% and the line of credit was collateralized by all of our assets. We borrowed up to $62.7 million on this line of credit during 2010. At December 31, 2010 and 2009, the balance of the loan was $0 and $40.0 million, respectively. Interest expense with respect to this line of credit for the years ended December 31, 2010 and 2009 was $8.1 million and $2.5 million, respectively. On November 23, 2010, we paid the outstanding principal and interest due to Platinum and retired the line of credit.

In September 2010, we entered into two promissory notes with affiliates of Platinum for an aggregate $22.0 million, of which $15.0 million was borrowed. These notes bore an interest rate of 24% per annum with a maturity date of March 23, 2011. The notes were secured by and had the benefits of the collateral described in the credit agreement and security instruments in the Platinum line of credit. In aggregate, the promissory notes had a prepayment penalty of $0.6 million. In September 2010, we borrowed $15 million on the notes. The promissory notes were paid in full in November 2010, including $1.2 million in interest and prepayment penalties.

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. For additional information, see “Description of Other Indebtedness—W&T Escrow Accounts” and “Description of Other Indebtedness—Other Encumbrances and Obligations.”

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.

During 2008, we entered into two loan agreements with Plainfield Specialty Holdings II, Inc., an affiliate of our majority equity holder, in the amounts of $7.0 million and $2.2 million. These notes carried interest rates of 5% plus a credit fee of 0.625% of the outstanding balance. The notes were collateralized by the oil and natural gas reserves of Black Elk Energy, LLC and the Company. Additionally, we entered into a note payable with a one of our members, Gross Capital Management, in the amount of $110,000. The note carried an interest rate of 15% plus a credit fee of 0.625% of the outstanding balance and was collateralized by our assets. The aggregate balance of the two notes was $6.7 million at December 31, 2008. Interest expense on the notes was $0.4 million and $0.9 million for the years ended December 31, 2009 and 2008, respectively. The notes were paid off and retired in July 2009.

Index to Financial Statements

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. In 2010, we loaned $1.0 million to Freedom for use in acquiring the helicopters. This amount was repaid in November 2010. At March 31, 2011 and December 31, 2010, the interest receivable from Freedom for the loan was $79,535. The interest rate was 20% and no payment has been made. The helicopters are being leased to Helicopter Services Inc. (“HSI”), a Houston-based Texas corporation that specializes in charter operations. Pursuant to the terms of the lease agreement, HSI will operate the helicopters in the ordinary course of its 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.

We pay certain expenses for certain general and administration expenses and operating 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 March 31, 2011 and December 31, 2010, 2009 and 2008, we had receivables from Black Elk Energy, LLC in the amount of $22,430, $22,430, $22,430 and $246,120, respectively.

For the three months ended March 31, 2011 and the years ended December 31, 2010, 2009 and 2008, we paid $320,516, $541,603, $10,396 and $133,176, 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 March 31, 2011 and December 31, 2010, 2009 and 2008, the outstanding amount due to Up and Running Solutions, LLC was $40,851, $119,452, $20,546 and $37,082, respectively.

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.

Index to Financial Statements

On December 24, 2010, we entered into an aggregate $110 million of credit facilities with Capital One, N.A., as administrative agent and lender. The credit facility is comprised of a (i) $35 million senior secured revolver and (ii) a $75 million secured letter of credit, which is to be used exclusively for the issuance of letters of credit in support of our P&A obligations relating to our oil and gas properties. The credit facility has a maturity date of December 31, 2013.

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 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.

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.

No borrowings were outstanding under the credit facility at March 31, 2011. As of June 15, 2011, letters of credit in the aggregate amount of $27.3 million were outstanding under this facility and we had borrowed $45 million under the revolver. As of June 15, 2011, $122.7 million is available for additional borrowings, including $25 million under the revolver.

On November 23, 2010, we issued $150.0 million of Senior Secured Notes due 2015, which are referred to in this Prospectus as the “notes.” The old notes, which carry a coupon rate of 13.75%, were sold at a discount (99.086% of par). We received net proceeds of approximately $148.7 million, after deducting estimated transaction fees and expenses. The net proceeds were used to repay all outstanding indebtedness under our prior credit facility and for funding a portion of our planned capital expenditures for development and drilling in 2011.

The old notes will mature on December 1, 2015, and interest is payable on each June 1 and December 1, commencing June 1, 2011. We have the option to redeem all or a portion of the old notes at any time on or after December 1, 2014 at a redemption price equal to par plus accrued and unpaid interest to the date of redemption.

Index to Financial Statements

We may also redeem the old notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to December 1, 2013. In addition, we may redeem up to 35% of the old notes prior to December 1, 2013 under certain circumstances with the net cash proceeds from certain equity offerings at a price equal to 110.0% of the principal amount, plus accrued and unpaid interest to the date of redemption. On or after 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, plus accrued and unpaid interest to the date of redemption.

The Indenture and the First Supplemental Indenture entered into on May 31, 2011 contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. These covenants are subject to a number of important exceptions and qualifications. We were in compliance with these covenants as of March 31, 2011.

The old notes are not subject to any sinking fund requirements. The old notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by all of our existing and future Domestic Subsidiaries (as defined in the Indenture).

In connection with the W&T Acquisition, W&T required us 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 us to, among other things, (i) establish the “Operated Properties Escrow Account” and “Non-Operated Properties Escrow Account,” (ii) make monthly contributions to each escrow account according to stipulated payments schedules until such accounts are fully funded to the 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, our majority equity holder, 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. With respect to both of the W&T Escrow Accounts, W&T has a first priority lien 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.

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. 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. Our funding obligations will re-commence on December 1, 2011, on which date we will be required to make an initial payment of $247,738 to the Non-Operated Properties Escrow Account, to be followed by payments of $340,000 per month. Pursuant to this stipulated payment schedule, the Non-Operated Properties Escrow Account will be fully funded by the end of 2017. Once our P&A obligations with respect to the W&T Properties have been satisfied, W&T’s lien on the W&T Escrow Accounts will be extinguished.

In connection with the Senior Notes Offering, W&T agreed to amend the documents relating to the W&T Acquisition 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 allowed us to grant

Index to Financial Statements

new, second liens on those assets to the benefit of the noteholders. Accordingly, the collateral securing the notes includes all of the Operated and Non-Operated Properties acquired in connection with the W&T Acquisition, except for those properties that have been previously released or relinquished. W&T retains a third lien on the Non-Operated Properties. The collateral securing the notes does not include the W&T Escrow Accounts, and we are not able to grant additional liens on such assets without the consent of W&T, which it has no obligation to do. Please see “Description of Notes-Intercreditor Agreement-Subordination of W&T Liens.”

Currently, our obligations under our credit facility and our obligations under our hedging agreements are secured by a first priority lien on substantially all of our assets, with the exception of the W&T Escrow Accounts, held by Capital One, the administrative agent under the credit facility, as collateral agent for the benefit of the lenders under such facility and our derivatives counter party, respectively. W&T has a secured second lien with respect to the W&T Properties that we acquired.

In connection with Nippon Acquisition, we currently have in place a surety bond in the amount of approximately $47.1 million in favor of Nippon and other surety bonds in the total aggregate amount of approximately $19.1 million in favor of the BOEMRE with respect to future P&A obligations relating to the Nippon Properties. With respect to our bonding obligations to Nippon, every two years, during such time as our P&A obligations with respect to the Nippon Properties remain outstanding, a new valuation is required to be done to determine our then-current liabilities. To the extent that our P&A obligations increase, we will be required to post additional surety bonds in favor of Nippon to cover the difference.

Index to Financial Statements

You can find the definitions of certain terms used in this description under the subheading “—Certain Definitions.” For purposes of this description, references to the “Co-Issuer” refer only to Black Elk Energy Finance Corp., the co-issuer of the Notes, and the terms “Company,” “us” and “we” refer only to Black Elk Energy Offshore Operations, LLC (including its permitted successors and assigns) and not to any of its subsidiaries. The Co-Issuer and the Company are referred to jointly as “Issuers.”

We will issue the new notes under the Indenture dated as of November 23, 2010 among the Issuers, the Guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent, as amended by the First Supplemental Indenture dated as of May 31, 2011. We refer to the Indenture, as amended by the First Supplemental Indenture, as the “Indenture.” The terms of the new notes will include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

The following description is a summary of the material provisions of the Indenture. It does not restate the Indenture in its entirety. We urge you to read the Indenture because it, and not this description, defines your rights as holders of the notes. Certain defined terms used in this description but not defined below under the caption “—Certain Definitions” or elsewhere in this description have the meanings assigned to them in the Indenture.

The registered holder of a note will be treated as the owner of it for all purposes. Only registered holders will have rights under the Indenture.

If the Exchange Offer contemplated by this Prospectus is consummated, holders of old notes who do not exchange those notes for new notes in the Exchange Offer will vote together with holders of new notes for all relevant purposes under the Indenture. In that regard, the Indenture requires that certain actions by the holders thereunder must be taken, and certain rights must be exercised, by specified minimum percentages of the aggregate principal amount of the outstanding securities issued under the Indenture. In determining whether holders of the requisite percentage in principal amount of notes have given any notice, consent or waiver or taken any other action permitted under the Indenture, any old notes that remain outstanding after the Exchange Offer will be aggregated with the new notes, and the holders of such old notes and the new notes will vote together as a single class for all such purposes. Accordingly, all references herein to specified percentages in aggregate principal amount of the notes outstanding shall be deemed to mean, at any time after the exchange offer for the old notes is consummated, such percentages in aggregate principal amount of the old notes and the new notes then outstanding.

Index to Financial Statements

However, pursuant to the terms of the Intercreditor Agreement (as defined herein), the Liens on the Collateral securing the notes are junior and subordinate to the Liens on the Collateral securing the Senior Credit Agreement and additional permitted first lien Indebtedness (including permitted refinancings respectively thereof) and as such the notes will be effectively subordinated, to the extent of the value of the Collateral, to all First Lien Obligations (as defined herein), including the Senior Credit Agreement and additional permitted first lien Indebtedness (including permitted refinancings respectively thereof), to the extent of the assets securing both of the First Lien Obligations and the notes. See “Risk Factors—Risks Relating to the Notes—The Liens on the collateral securing the notes will be junior and subordinate to the Liens on the Collateral securing our obligations under our Senior Credit Agreement and any other permitted additional first lien indebtedness. If there is a default, the value of the Collateral may not be sufficient to repay both the lenders under our Senior Credit Agreement and holders of other permitted additional first lien indebtedness and the holders of the notes” and “—Collateral—Intercreditor Agreement.” As of June 30, 2010, after giving pro forma effect to the offering, there would have been no borrowings outstanding under the Senior Credit Agreement.

The new notes will be fully and unconditionally guaranteed, jointly and severally, by Black Elk Energy Land Operations, LLC, which is our only Subsidiary apart from the Co-Issuer, and by each of the Company’s future Restricted Subsidiaries that guarantees Indebtedness of the Company under a credit facility.

However, pursuant to the terms of the Intercreditor Agreement, the Liens on the Collateral securing the Guarantees are junior and subordinate to the Liens on the Collateral securing the Senior Credit Agreement and additional permitted first lien Indebtedness (including permitted refinancings respectively thereof) and as such the notes will be effectively subordinated, to the extent of the value of the Collateral, to all First Lien Obligations (as defined herein), including the Senior Credit Agreement and additional permitted first lien Indebtedness (including permitted refinancings respectively thereof), to the extent of the assets securing such First Lien Obligations. See “Risk Factors—Risks Relating to the Notes—The Liens on the collateral securing the notes are junior and subordinate to the liens on the collateral securing our obligations under any permitted first lien indebtedness. If there is a default, the value of the collateral may not be sufficient to repay both the holders of permitted additional first lien indebtedness and the holders of the notes” and “—Collateral—Intercreditor Agreement.”

Currently, Black Elk Energy Land Operations, LLC is a “Restricted Subsidiary.” Under the circumstances described below under the subheading “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” we will be permitted to designate certain of our existing and future Subsidiaries as “Unrestricted Subsidiaries.” Any Unrestricted Subsidiaries would not be subject to many of the restrictive covenants in the Indenture and would not guarantee the notes.

The Issuers issued the old notes in an aggregate principal amount of $150.0 million, and they may issue up to $150.0 million in aggregate principal amount of the new notes. The Issuers may issue additional notes under

Index to Financial Statements

the Indenture from time to time in the future. Any offering of additional notes is subject to the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” The old notes, the new notes and any additional notes subsequently issued under the Indenture will be treated as a single class for all purposes under the Indenture, including without limitation, waivers, amendments, redemptions and offers to purchase. The notes may be issued in denominations of $2,000 and integral multiples of $1,000 in excess thereof and will mature on December 1, 2015.

Interest on the notes accrues at the rate of 13.75% per annum. Interest is payable semi-annually in arrears on June 1 and December 1, commencing on June 1, 2011. Interest on overdue principal and interest will accrue at a rate that is 1% higher than the applicable rate on the notes. The Issuers will make each interest payment to the holders of record on the immediately preceding May 15 and November 15.

Interest on the new notes will accrue from the latest interest payment date for the old notes, June 1, 2011. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

With respect to notes held in certificated form, if a holder has given wire transfer instructions to the Issuers, the Issuers will pay all principal, interest and premium, if any, on that holder’s notes in accordance with those instructions. All other payments on notes held in certificated form will be made at the office or agency of the paying agent and registrar in New York City, unless the Issuers elect to make interest payments by check mailed to the holders at their address set forth in the register of holders.

The Bank of New York Mellon Trust Company, N.A. currently acts as paying agent and registrar. The Company will maintain an office in New York City, initially at the office of an affiliate of the paying agent and registrar, where payment on the notes may be made. The Company may change the paying agent or registrar without prior notice to the holders of the notes, and the Company or any of its domestic Subsidiaries may act as paying agent.

A holder may transfer or exchange notes in accordance with the Indenture. The Issuers or the trustee may require a holder to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. No service charge will be imposed for any registration of transfer or exchange of notes, but the Issuers may require holders to pay all taxes due on transfer. The Issuers are not required to transfer or exchange any note selected for redemption. Also, the Issuers are not required to transfer or exchange any note for a period of 15 days prior to the mailing of a notice of redemption.

The new notes, like the old notes, will be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Company’s current and future Domestic Subsidiaries. See “—Certain Covenants—Additional Guarantees.”

The obligations of each Guarantor under its Guarantee will be limited as necessary to prevent that Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors—Risks Relating to the Notes—Under certain circumstances a court could cancel the notes or the related guarantees and the security interests that secure the notes and any guarantees under fraudulent conveyance laws.”

Index to Financial Statements

A Guarantor may not sell or otherwise dispose of all or substantially all of its properties or assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person), another Person, other than the Issuers or another Guarantor, unless:

(a) the Person acquiring the properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than the Guarantor) unconditionally assumes all the obligations of that Guarantor under the Indenture and the Guarantee, pursuant to a supplemental indenture substantially in the form specified in the Indenture, under the notes, the Indenture and that Guarantor’s Guarantee on terms set forth therein; or

(b) such sale or other disposition complies with the “Asset Sale” provisions of the Indenture.

(1) in connection with any sale or other disposition of all or substantially all of the properties or assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) the Company or a Subsidiary of the Company, if the sale or other disposition is not prohibited by the “Asset Sale” provisions of the Indenture; or

(2) in connection with any sale or other disposition of Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) the Company or a Subsidiary of the Company, if after such sale or disposition such Guarantor is no longer a Restricted Subsidiary and the sale or other disposition is not prohibited by the “Asset Sale” provisions of the Indenture; or

(3) if the Company designates any Restricted Subsidiary that is a Guarantor as an Unrestricted Subsidiary in accordance with the applicable provisions of the Indenture; or

(4) upon Legal Defeasance or Covenant Defeasance with respect to all notes as described below under the caption “—Legal Defeasance and Covenant Defeasance” or upon satisfaction and discharge of the Indenture as described below under the caption “—Satisfaction and Discharge;” or

(5) such Guarantor ceases to guarantee Indebtedness of the Company under a credit facility; or

(6) as provided by the Intercreditor Agreement, as described herein under the caption “—Collateral—Intercreditor Agreement.”

The notes and the Guarantees are secured by second priority Liens on all property and assets of the Issuers and the Guarantors to the extent they constitute Collateral for our First Lien Obligation (as defined under “—Intercreditor Agreement”), except as described herein (the “Collateral”). As of the date hereof, the Collateral includes substantially all of the assets of the Issuers and the Guarantors other than Excluded Collateral.

(1) any Capital Stock of any Foreign Subsidiary in excess of 66% of the Capital Stock of such Foreign Subsidiary or any property or assets of any Foreign Subsidiary;

(2) any permit or license or any contractual obligation entered into by either Issuer or any Guarantor (A) that prohibits or requires the consent of any Person other than the Company or any of its Affiliates as a condition to the creation by such Issuer or Guarantor of a Lien on any right, title or interest in such permit, license or contractual agreement or any Capital Stock or equivalent related thereto or (B) to the extent that any requirement of law applicable thereto prohibits the creation of a Lien thereon, but only, with respect to the prohibition in (A) and (B), to the extent, and for as long as, such prohibition is not terminated or rendered unenforceable or otherwise deemed ineffective by the Uniform Commercial Code or any other requirement of law;

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(3) fixed or capital assets owned by either Issuer or any Guarantor that are subject to a purchase money Lien or a capital lease if the contractual obligation pursuant to which such Lien is granted (or in the document providing for such capital lease) prohibits or requires the consent of any Person other than the Company or any of its Affiliates as a condition to the creation of any other Lien on such equipment;

(4) any Capital Stock of any Subsidiary of the Company to the extent (and only to the extent) that in the reasonable judgment of the Company, if such Capital Stock were not excluded from the Collateral then Rule 3-16 or Rule 3-10 of Regulation S-X under the Securities Act would require the filing of separate financial statements of such Subsidiary with the SEC (or any other governmental agency) in connection with a registration of the notes under the Securities Act;

(5) Collateral that has been released in accordance with the Intercreditor Agreement or the Indenture, subject to the provisions contained under the heading “—Intercreditor Agreement—Automatic Release of Second Priority Liens” set forth below;

(7) certain other property or assets owned by either Issuer or any Guarantor that are not secured by Liens for the benefit of any First Lien Obligations;

(such excluded assets being collectively referred in this Prospectus as the “Excluded Collateral”).

The Intercreditor Agreement among the trustee, the First Lien Collateral Agent, on behalf of the First Lien Secured Parties (including the lenders under any First Lien Agreement (as defined in the second succeeding paragraph)), the Collateral Agent, on behalf of the Second Lien Secured Parties (including the holders of the notes), the Issuers and the Guarantors, among other things, defines the rights of the trustee, the First Lien Collateral Agent and the First Lien Secured Parties and the Collateral Agent and the Second Lien Secured Parties with respect to the Collateral.

W&T has entered into an intercreditor agreement with the First Lien Collateral Agent and the Collateral Agent, and the Liens of W&T on the W&T Properties that are “Non-Operated Properties,” as defined in the W&T Purchase and Sale Agreement (the “W&T Non-Operated Properties”), securing our plugging and abandonment liabilities in connection with the W&T Properties are contractually junior in priority to those of each of the Liens of the First Lien Secured Parties securing the First Lien Obligations and the Liens of the Second Lien Secured Parties securing the Second Lien Obligations. The Liens of W&T on the W&T Properties that are “Operated Properties,” as defined in the W&T Purchase and Sale Agreement (the “W&T Operated Properties”), were released. The rights and obligations of W&T under the intercreditor agreement relative to the First Lien Secured Parties and the Second Lien Secured Parties are customary for a junior lienholder.

First Lien Obligations; Notes Effectively Subordinated to First Lien Obligations

The Intercreditor Agreement provides that all Indebtedness under any First Lien Agreement together with all other First Lien Obligations will be secured by First Priority Liens on the Collateral, which Liens will be contractually senior to the Liens thereon that secure the notes and the Guarantees and the other Second Lien Obligations (as defined in the next paragraph). As a result, the Second Lien Obligations will be effectively subordinated to the First Lien Obligations to the extent of the value of the Collateral.

“First Lien Obligations” means, collectively, (i) all principal of and interest and premium (if any) on all loans made pursuant to a First Lien Agreement and any other Indebtedness incurred pursuant to a credit facility to the extent that such Indebtedness is secured equally and ratably with the other First Lien Obligations by the

Index to Financial Statements

Liens on the Collateral, (ii) all reimbursement obligations (if any) and interest thereon with respect to any letter of credit or similar instruments issued pursuant to a First Lien Agreement, (iii) all Hedging Obligations of the Company or any Guarantor, and (iv) all fees, expenses and other amounts payable from time to time pursuant to the First Lien Debt Documents.

“First Lien Agreement” means (i) the Senior Credit Agreement and any other agreement evidencing First Lien Obligations and (ii) any other credit agreement, loan agreement, note agreement, promissory note, Indenture or other agreement or instrument evidencing or governing the terms of any indebtedness or other financial accommodation that (x) has been incurred to extend, replace, refinance or refund in whole or in part the indebtedness and other obligations outstanding under the Senior Credit Agreement or any other agreement or instrument referred to in this clause (ii) and (y) is consistent with the provisions set forth under the heading “—Restrictions on Amendments”.

“Second Lien Obligations” means, collectively, (i) all principal of and interest and premium (if any) on all notes and (ii) all fees, expenses and other amounts payable from time to time pursuant to the Indenture and related documents. For the purposes of this section “—Intercreditor Agreement,” the term “Indenture” means (i) the Indenture and (ii) any other credit agreement, loan agreement, note agreement, promissory note, Indenture or other agreement or instrument evidencing or governing the terms of any indebtedness or other financial accommodation that (x) has been incurred to extend, replace, refinance or refund in whole or in part any indebtedness or other obligations outstanding under the Indenture or any other agreement or instrument referred to in clause (i) or this clause (ii) and (y) is consistent with the provisions set forth under the heading “—Restrictions on Amendments”.

The Intercreditor Agreement provides that the subordination of Liens securing the Second Lien Obligations described herein affects only the relative priority of those Liens, and does not subordinate the Second Lien Obligations in right of payment to the First Lien Obligations. Nothing in the Intercreditor Agreement will affect the entitlement of any Second Lien Secured Party to receive and retain required payments of interest, principal, and other amounts in respect of the Second Lien Obligations unless the receipt is expressly prohibited by, or results from the Second Lien Secured Party’s breach of, the Intercreditor Agreement.

The Intercreditor Agreement provides that, notwithstanding the date, manner or order of grant, attachment or perfection of any Lien securing Second Lien Obligations, including the notes or the Guarantees (a “Second Priority Lien”) or any Lien on Collateral securing the First Lien Obligations (a “First Priority Lien”), and notwithstanding any provision of the Uniform Commercial Code of any applicable jurisdiction or any other applicable law or the provisions of any Debt Document or any other circumstance whatsoever, each Agent (i.e., the First Lien Collateral Agent and the Collateral Agent), for itself and on behalf of the Secured Parties on whose behalf it acts in such capacity therefor, will agree that, so long as the First Lien Obligations have not been discharged as set forth in the Intercreditor Agreement (such discharge, the “Discharge of First Lien Obligations”), (a) any First Priority Liens then or thereafter held by or for the benefit of any First Lien Secured Party will be senior in right, priority, operation, effect and all other respects to any and all Second Priority Liens and (b) any Second Priority Liens then or thereafter held by or for the benefit of any Second Lien Secured Party will be junior and subordinate in right, priority, perfection, operation, effect and all other respects to any and all First Priority Liens, and the First Priority Liens will be and remain senior in right, priority, perfection, operation, effect and all other respects to any Second Priority Liens for all purposes.

Notwithstanding the foregoing, (x) the First Lien Obligations will only be contractually senior to the Second Lien Obligations up to but not in excess of the Maximum First Lien Obligations, (y) the Second Lien Obligations will be contractually senior to any excess of the First Lien Obligations over the Maximum First Lien Obligations,

Index to Financial Statements

but only up to the Maximum Second Lien Obligations. “Maximum First Lien Obligations” will have the same meaning as First Lien Obligations, however the aggregate principal amount of First Lien Obligations (including reimbursement obligations for letters of credit) will be capped, as of any date of determination, at an amount equal to (a) the amount of Indebtedness permitted to be incurred pursuant to clause (1) of the definition of “Permitted Debt,” plus (b) 15% of the amount in clause (a) (the “Maximum First Lien Principal Amount”). “Maximum Second Lien Obligations” will have the same meaning as Second Lien Obligations, however, the aggregate principal amount of the Second Lien Obligations will be capped, as of any date of determination, at an amount equal to (a) $150.0 million, minus (b) the sum of all principal payments on the notes constituting Second Lien Obligations (including voluntary and mandatory prepayments) after the date of the Intercreditor Agreement.

The Intercreditor Agreement provides that (a) each Agent, for itself and on behalf of the Secured Parties on whose behalf it acts in such capacity therefor, will agree that it will not, and will waive any right to, contest or support any other Person in contesting, in any proceeding (including any insolvency or liquidation proceeding), the priority, validity, extent, perfection or enforceability of any Second Priority Lien or any First Priority Lien, as the case may be; provided that nothing in the Intercreditor Agreement will be construed to prevent or impair the rights of any Agent or any other Secured Party to enforce the Intercreditor Agreement to the extent provided thereby and (b) if either Issuer or any Guarantor creates any additional Liens upon any property to secure (i) any First Lien Obligations, it must substantially concurrently grant a Lien upon such property as security for the notes or the Guarantee of such Guarantor, as the case may be, and (ii) the notes or any Guarantee, it must substantially concurrently grant a Lien upon such property as security for the First Lien Obligations.

The Intercreditor Agreement provides that the First Lien Collateral Agent and the other First Lien Secured Creditors will, at all times prior to the payment in full in cash of the First Lien Obligations, have the exclusive right to enforce rights and exercise remedies (including any right of setoff) with respect to the Collateral (including making determinations regarding the release, disposition or restrictions with respect to the Collateral), or to commence or seek to commence any action or proceeding with respect to such rights or remedies (including any foreclosure action or proceeding or any insolvency or liquidation proceeding), in each case, without any consultation with or the consent of the Collateral Agent or any other Second Lien Secured Party, and no Second Lien Secured Party will have any such right; provided, however, that after a period of 120 days following notice from the Collateral Agent to the First Lien Collateral Agent that either (x) the Second Lien Obligations have become due in full as a result of acceleration or otherwise (and such acceleration has not been rescinded) or (y) any payment or insolvency event of default has occurred and is then continuing under the Indenture or the other documents executed in connection therewith, and in each case so long as the First Lien Collateral Agent is not diligently pursuing an enforcement action with respect to all or a material portion of the collateral or diligently attempting to vacate any stay or prohibition against such exercise (the “Standstill Period”), the Second Lien Secured Parties may enforce or exercise any rights or remedies permitted by the Intercreditor Agreement with respect to any Collateral.

No Second Lien Secured Party may contest, protest, object to or take any action to hinder, and each waives any and all claims with respect to, any enforcement action by a First Lien Secured Party in compliance with the Intercreditor Agreement and applicable law.

(1) file a proof of claim or statement of interest, vote on a plan of reorganization (including a vote to accept or reject a plan of reorganization (including a vote to accept or reject a plan of partial or complete liquidation, reorganization, arrangement, composition or extension)), and make other filings, arguments, and motions, with respect to the Second Lien Obligations and the Collateral in any insolvency proceeding commenced by or against any grantor, in each case in accordance with the Intercreditor Agreement,

Index to Financial Statements

(2) take action to create, perfect, preserve or protect its Lien on the Collateral, so long as such actions are not adverse to the priority status in accordance with the Intercreditor Agreement of Liens on the Collateral securing the First Lien Obligations or the First Lien Secured Parties’ rights to exercise remedies,

(3) file necessary pleadings in opposition to a claim objecting to or otherwise seeking disallowance of a Second Lien Obligation or a Lien securing the Second Lien Obligations,

(4) join (but not exercise any control over) a judicial foreclosure or Lien enforcement proceeding with respect to the Collateral initiated by the any First Lien Secured Party, to the extent that such action could not reasonably be expected to interfere materially with the enforcement actions of the First Lien Secured Parties, but no Second Lien Secured Party may receive any proceeds thereof unless expressly permitted in the Intercreditor Agreement, and

(5) bid for or purchase Collateral at any public, private or judicial foreclosure upon such Collateral initiated by any First Lien Secured Party or any sale of Collateral during an insolvency proceeding; provided that such bid may not include a “credit bid” in respect of any Second Lien Obligations unless the proceeds of such bid are otherwise sufficient to cause the Discharge of the First Lien Obligations up to the Maximum First Lien Obligations.

The Intercreditor Agreement provides that, if an event of default under the First Lien Debt Documents has occurred and is continuing, and as a result of such event of default under the First Lien Debt Documents (i) the First Lien Obligations have been accelerated or (ii) any insolvency or liquidation proceeding has been commenced (or is then occurring) with respect to any of us or any borrower under a First Lien Agreement (each, a “Trigger Event”), then the holders of the notes shall have the right and option to purchase the entire aggregate amount (but not less than the entire aggregate amount) of outstanding First Lien Obligations (including unfunded and unterminated commitments) at a price equal to par value of the outstanding principal amount thereof, plus all accrued and unpaid interest, fees and other amounts of First Lien Obligations, together with cash collateral for all outstanding letters of credit in an amount equal to 105% of the undrawn and available amount of such letters of credit outstanding under the applicable First Lien Agreement and a payment for all then outstanding Hedging Obligations at a price equal to the sum of any unpaid amounts then due in respect of such Hedging Obligations; provided that in no event will the calculation of the amount of such outstanding First Lien Obligations include any premiums (other than breakage costs). Such sale shall be without warranty or representation or recourse other than as provided in standard Loan Syndication Trading Association documentation for par trades. To exercise the option following any Trigger Event, the Collateral Agent, upon receipt of indemnification pursuant to the Indenture, together with a written direction from the holders of at least 15% in aggregate principal amount of notes outstanding, shall deliver a written notice prepared by and on behalf of such holders to the First Lien Collateral Agent, which notice must be given within 60 days after the occurrence of any such Trigger Event and shall be deemed an irrevocable exercise of its option to purchase the First Lien Obligations. Upon delivery of such notice, the holders shall be obligated to purchase (on a pro rata basis), and the First Lien Creditors shall be obligated to sell, the entire aggregate amount of outstanding First Lien Obligations for the purchase price described above within 15 days after delivery of such notice. In no event shall the Trustee be obligated to monitor any such Trigger Event nor shall the Second Lien Notes Trustee have any responsibility to execute, or liability in connection with the execution of such purchase.

The Intercreditor Agreement provides that if, in connection with (i) any disposition of any Collateral permitted under the terms of the First Lien Debt Documents or (ii) the enforcement or exercise of any rights or remedies with respect to the Collateral, including any disposition of Collateral or (iii) during an insolvency proceeding, in connection with the entry of an order by the bankruptcy court authorizing such disposition, the First Lien Collateral Agent, for itself and on behalf of the other First Lien Secured Parties, (x) releases any of the

Index to Financial Statements

First Priority Liens, or (y) releases any Guarantor from its obligations under its guarantee of the First Lien Obligations (in each case, a “Release”), other than any such Release granted following the Discharge of First Lien Obligations and termination of commitments under the First Lien Debt Documents, then the Second Priority Liens on such Collateral, and the obligations of such Guarantor under its Guarantee, will be automatically, unconditionally and simultaneously released, and the Collateral Agent and the other Second Lien Secured Parties will promptly execute and deliver such release documents as the First Lien Collateral Agent may reasonably request to effectively confirm such Release and as may be otherwise reasonably required to consummate such Release and any related transactions; provided that, (x) in the case of a disposition of Collateral in accordance with clause (i) above (or a Release of a Guarantor from its Guarantee in connection therewith), the Second Priority Liens may not be so Released and such Guarantor may not be so Released if such disposition or such Release of such Guarantor from its Guarantee is not permitted under the terms of the Indenture Documents and (y) in the case of a disposition of Collateral in accordance with clauses (ii) or (iii) above, the Second Priority Liens may not be so Released if the proceeds of such disposition are not applied to repay the First Lien Obligations and permanently reduce any commitments thereunder by a corresponding amount.

The Intercreditor Agreement provides that any Collateral or proceeds thereof received by any Secured Party in connection with any disposition of, or collection on such Collateral upon the enforcement or exercise of any right or remedy (including any right of setoff) will be applied as follows:

first, to the payment of costs and expenses of the applicable Secured Party in connection with such enforcement or exercise;

second, to the payment in full in cash of the First Lien Obligations, but only up to the Maximum First Lien Obligations;

third, after payment of the First Lien Obligations in accordance with clause second above, to the payment in full in cash of the Second Lien Obligations, but only up to the Maximum Second Lien Obligations;

fourth, after the payment of the Second Lien Obligations in accordance with clause third above, to the payment in full in cash of any other outstanding First Lien Obligations;

fifth, after the payment in full in cash of any other outstanding First Lien Obligations, to the payment in full in cash of any other outstanding Second Lien Obligations; and

sixth, after the Discharge of First Lien Obligations has occurred and all Second Lien Obligations have been paid in full in cash, any surplus Collateral or proceeds then remaining will be returned to the Company, the applicable Guarantor or to whomsoever may be lawfully entitled to receive the same or as a court of competent jurisdiction may direct.

The Intercreditor Agreement provides that so long as the Discharge of First Lien Obligations has not occurred, any Collateral or any proceeds thereof received by the Collateral Agent or any other Second Lien Secured Party in violation of the Intercreditor Agreement with respect to the Collateral, or otherwise, will be segregated and held in trust and either retained or forthwith transferred or paid over to the First Lien Collateral Agent for the benefit of the First Lien Secured Parties in the same form as received, together with any necessary endorsements, for application in accordance with the provisions set forth under the heading “—Waterfall” above or as a court of competent jurisdiction may otherwise direct.

Index to Financial Statements

(a) Until the Discharge of First Lien Obligations has occurred, the Collateral Agent, for itself and on behalf of the other Second Lien Secured Parties, will agree that, in the event of any insolvency or liquidation proceeding, the Second Lien Secured Parties:

(i) will not oppose or object to the use of any Collateral constituting cash collateral under Section 363 of the United States Bankruptcy Code or any other provision of any other bankruptcy law, unless the First Lien Secured Parties, or a representative authorized by the First Lien Secured Parties, shall oppose or object to such use of cash collateral;

(ii) will not oppose or object to (or join with any third party in opposing or objecting to) any post-petition financing provided to the Company or any Guarantors, whether provided by the First Lien Secured Parties or any other Person, under Section 364 of the Bankruptcy Code, or any comparable provision of any other bankruptcy law (a “DIP Financing”), or the Liens securing any DIP Financing (“DIP Financing Liens”), unless (a) the First Lien Secured Parties, or a representative authorized by the First Lien Secured Parties (including, without limitation, the First Lien Collateral Agent), shall then oppose or object to such DIP Financing or such DIP Financing Liens or (b) such DIP Financing Liens are not senior to, or do not rank pari passu with, the First Priority Liens and, to the extent that such DIP Financing Liens are senior to, or rank pari passu with, the First Priority Liens, the Collateral Agent will, for itself and on behalf of the other Second Lien Secured Parties, subordinate the Second Priority Liens to the First Priority Liens and the DIP Financing Liens;

(iii) except to the extent permitted by paragraph (b) or (c) below, in connection with the use of cash collateral as described in clause (i) above or a DIP Financing or otherwise, will not request adequate protection or any other relief in connection with such use of cash collateral, DIP Financing or DIP Financing Liens; and

(iv) will not oppose any sale or disposition of any assets of the Company or any Guarantor that is supported by the First Lien Secured Creditors, and the Collateral Agent and each other Second Lien Secured Creditor will be deemed to have consented under Section 363 of the Bankruptcy Code (and otherwise) to any sale supported by the First Lien Secured Creditors and to have released their Liens in such assets.

(b) The Collateral Agent, for itself and on behalf of the other Second Lien Secured Parties, will agree that no Second Lien Secured Party may object to, contest, or support any other Person in objecting to or contesting, (i) any request by the First Lien Collateral Agent or any other First Lien Secured Party for adequate protection in respect of any First Lien Obligations or (ii) any objection, based on a claim of a lack of adequate protection in respect of any First Lien Obligation, by the First Lien Collateral Agent or any other First Lien Secured Party to any motion, relief, action or proceeding.

(c) The First Lien Secured Parties will not raise any objection to a request by the Second Lien Secured Parties for (i) adequate protection payments in the form of the Second Lien Secured Parties retaining a Lien on the Collateral (including proceeds thereof arising after the commencement of such proceeding) with the same priority in relation to the First Lien Secured Parties as existed prior to the commencement of the insolvency or liquidation proceedings as contemplated by clause (b) above, (ii) the Second Lien Secured Parties receiving a replacement Lien on post-petition assets with the same priority relative to the First Priority Liens as existed immediately prior to the commencement of the insolvency or liquidation proceeding, and (iii) a superpriority claim junior in all respects to the superpriority claims granted to the First Lien Secured Parties; provided that, (A) all such Liens, if granted, will be subordinate to all Liens securing the First Lien Obligations (including, without limitation, the first lien adequate protection liens and any “carve-out” agreed to by the First Lien Collateral Agent) and any Liens securing DIP Financing) on the same basis as the other Liens securing the Second Lien Obligations are so subordinated under the Intercreditor Agreement and (B) all such superpriority claims, if granted, are junior in all respects to the superpriority claims granted to the First Lien Secured Parties

Index to Financial Statements

on account of any of the First Lien Obligations or granted with respect to the DIP Financing or use of cash collateral on the same basis as the other Liens securing the Second Lien Obligations are so subordinated under the Intercreditor Agreement and the Second Lien Secured Parties shall have irrevocably agreed that any such junior superpriority claims may be paid under any plan of reorganization in any combination of cash, debt, equity or other property having a value on the effective date of such plan equal to the allowed amount of such junior superpriority claims. The Collateral Agent and any other Second Lien Secured Party will agree in the Intercreditor Agreement to limit their rights to seek any allowance payment in any insolvency or liquidation proceeding of Second Lien Obligations consisting of adequate protection payments and, in any event, to turn over to the holders of the First Lien Obligations any post-petition interest or other payments that the holders of the notes receive in accordance with the provisions set forth above under “—Intercreditor Agreement—Payment Over” if the First Lien Obligations are not fully paid at the conclusion of the bankruptcy.

(d) Notwithstanding the foregoing, if, in connection with any insolvency or liquidation proceeding, (A) any First Lien Secured Party seeks or requests adequate protection in the form of a Lien on additional collateral, the Collateral Agent may, for itself and on behalf of the other Second Lien Secured Parties, seek or request adequate protection in the form of a Lien on such additional collateral, which Lien will be subordinated to the First Priority Liens and DIP Financing Liens on the same basis as the other Second Priority Liens are subordinated to the First Priority Liens under any such Intercreditor Agreement or (B) any Second Lien Secured Party is granted adequate protection in the form of a Lien on additional collateral, the First Lien Collateral Agent will, for itself and on behalf of the other First Lien Secured Parties, be granted adequate protection in the form of a Lien on such additional collateral that is senior to such Second Priority Liens as security for the First Lien Obligations.

Prior to the expiration of the Standstill Period, the Collateral Agent, for itself and on behalf of the other Second Lien Secured Parties, has agreed that, so long as the Discharge of First Lien Obligations has not occurred, no Second Lien Secured Party may, without the prior written consent of the First Lien Collateral Agent, seek or request relief from or modification of the automatic stay or any other stay in any insolvency or liquidation proceeding or take any action in derogation thereof, in each case in respect of any part of the Collateral or any Second Priority Lien.

The Collateral Agent, for itself and on behalf of the other Second Lien Secured Parties, has agreed that no Second Lien Secured Party may oppose or seek to challenge any claim by the First Lien Collateral Agent or any other First Lien Secured Party for allowance in any insolvency or liquidation proceeding of First Lien Obligations consisting of post-petition interest, fees or expenses to the extent of the value of the First Priority Liens (it being understood and agreed that such value will be determined without regard to the existence of the Second Priority Liens on the Collateral). The First Lien Collateral Agent, for itself and on behalf of the other First Lien Secured Parties, has agreed that the Collateral Agent or any other Second Lien Secured Party may make a claim for allowance in any insolvency or liquidation proceeding of Second Lien Obligations consisting of post-petition interest, fees or expenses to the extent of the value of the Second Priority Liens; provided, however, that (i) if the First Lien Secured Parties shall have made any such claim, such claim (A) shall also have been approved or (B) will be approved contemporaneous with the approval of any such claim by any Second Lien Secured Party and (ii) each First Lien Secured Party may oppose or seek to challenge any such claim.

Each of the First Lien Collateral Agent, on behalf of the First Lien Secured Parties, and the Collateral Agent, on behalf of the Second Lien Secured Parties, has agreed that, without the written consent of the other, it will not seek to vote with the other as a single class in connection with any plan of reorganization in any insolvency or liquidation proceeding. The Second Lien Secured Parties may vote on any plan of reorganization

Index to Financial Statements

(including, without limitation, the right to vote to accept or reject any plan of partial or complete liquidation, reorganization, arrangement, composition or extension) to the extent not inconsistent with the terms of the Intercreditor Agreement.

In the Intercreditor Agreement, the Collateral Agent has agreed that no payment or distribution to any First Lien Secured Party pursuant to the provisions of the Intercreditor Agreement will entitle any Second Lien Secured Party to exercise any rights of subrogation in respect thereof until the Discharge of the First Lien Obligations shall have occurred.

The Intercreditor Agreement provides that, subject to the terms and provisions of the Intercreditor Agreement, the Collateral Agent and the other Second Lien Secured Parties may, in accordance with the Second Lien Debt Documents and applicable law, enforce rights and exercise remedies against any of the Issuers and the Guarantors as unsecured creditors (other than initiating or joining in an involuntary case or proceeding under the Bankruptcy Code with respect to any of the Issuers or the Guarantors) prior to the end of the Standstill Period. Notwithstanding the above, in the event that any Second Lien Secured Party becomes a judgment Lien creditor in respect of Collateral as a result of its enforcement of its rights as an unsecured creditor, such judgment Lien shall be subject to the terms of the Intercreditor Agreement for all purposes (including in relation to the First Priority Liens and the First Lien Obligations) to the same extent as all other Liens securing the Second Lien Obligations subject to the Intercreditor Agreement.

The Issuers, the Guarantors and the Collateral Agent have entered into one or more Collateral Agreements and other documents granting, in favor of the Collateral Agent for the benefit of the Collateral Agent and the holders of the Second Lien Obligations, Second Priority Liens on the Collateral securing the Second Lien Obligations, subject to certain exceptions and subject to Permitted Liens. The Intercreditor Agreement provides, subject to limitations (if any) set forth therein, that, in the event the First Lien Collateral Agent or the other First Lien Secured Parties and the relevant grantors enter into any amendment, waiver or consent (in each case consistent with the provisions set forth below under the heading “—Restrictions on Amendments”) in respect of any of the documents evidencing or giving rise to Liens securing the First Lien Obligations for the purpose of adding to, or deleting from, or waiving or consenting to any departures from any provisions of, any such document or changing in any manner the rights of the First Lien Collateral Agent, the other First Lien Secured Parties, the Company or any other grantor thereunder, then such amendment, waiver or consent shall apply automatically to any comparable provision of the Indenture and the comparable Collateral Agreements evidencing or giving rise to Liens securing the Second Lien Obligations without the consent of the trustee, the Collateral Agent, the holders of notes or the other Second Priority Secured Parties and without any action by any of the foregoing, provided, that no such amendment will (A) remove or release any Collateral subject to a Second Priority Lien, except to the extent that (x) the release is permitted or required under the provisions set forth under the heading “—Insolvency and Liquidation Proceedings” and (y) there is a corresponding release of Collateral from the First Priority Lien, (B) materially and adversely affect the rights of the Second Lien Secured Creditors without the consent of the Collateral Agent, unless it also affects the First Lien Secured Creditors in a like or similar manner, (C) permit other Liens on the Collateral, not permitted under the terms of the Second Lien Collateral Agreements or (D) impose duties on the Collateral Agent, without its consent. Notice of such amendment, waiver or consent shall be given to the Collateral Agent no later than 30 days after its effectiveness, provided that the failure to give such notice shall not affect the effectiveness and validity thereof.

Index to Financial Statements

The Issuers and the Guarantors are entitled to releases of assets included in the Collateral from the Liens securing the notes and the Guarantees under the following circumstances:

(1) if any Subsidiary that is a Guarantor is released from its Guarantee pursuant to the terms of the Indenture, that Subsidiary’s assets will also be released from the Liens securing the notes;

(2) as described under “—Amendment, Supplement and Waiver,” with consent of holders of at least 70% in aggregate principal amount of the outstanding notes;

(3) if required in accordance with the terms of the Intercreditor Agreement, as described under “—Intercreditor Agreement” above;

(5) if the Issuers exercise their legal defeasance option or covenant defeasance option as described below under “—Legal Defeasance and Covenant Defeasance”; and

(6) upon satisfaction and discharge of the Indenture or payment in full of the principal of, and premium and accrued and unpaid interest on, the notes and all other Obligations that are then due and payable as provided below under the caption “—Satisfaction and Discharge.”

The Intercreditor Agreement provides, unless a similar amendment, supplement or modification to the applicable First Lien Debt Document has been, or is concurrently being, made, without the prior written consent of the First Lien Collateral Agent, the Indenture may not be amended, supplemented, modified, increased, restated, refinanced or replaced to the extent such amendment, supplement, modification, restatement, refinancing or replacement, or the terms of any new Indenture, would (i) contravene the provisions of the Intercreditor Agreement, (ii) increase the interest rate on the notes issued thereunder to a rate higher than 15.75% per annum, or impose any fee, original issue discount or similar payment in connection therewith that, together with all such fees, original issue discounts or similar payments imposed from the Issue Date, would exceed two percent (2.0%) of the amount of the notes, other than the initial fees or original issue discount payable in connection with the initial issuance of the notes; (iii) change (to earlier dates) any dates upon which payments of principal or interest are due thereon; (iv) change any representation, warranty, covenant, default or event of default thereunder in a manner materially adverse to the Company or any of its subsidiaries; (v) change the redemption, prepayment or defeasance provisions thereof in a manner which would be materially adverse to the First Lien Secured Parties; (vi) add Collateral (unless such Collateral is also provided to the First Lien Collateral Agent), or (vii) increase the obligations thereunder of the Company or any of its subsidiaries or confer any additional rights on the Second Lien Secured Parties which would be materially adverse to the First Lien Secured Parties.

The Intercreditor Agreement provides, unless a similar amendment, supplement or modification to the applicable Second Lien Debt Document has been, or is concurrently being, made, without the prior written consent of the Collateral Agent, the First Lien Debt Documents may not be amended, supplemented, modified, increased, restated, refinanced or replaced to the extent such amendment, supplement, modification, restatement, refinancing or replacement, or the terms of any new First Lien Debt Documents, would (i) contravene the provisions of the Intercreditor Agreement, (ii) increase the outstanding aggregate principal amount of the loans (and reimbursement obligations) under the First Lien Debt Documents plus, if any, any undrawn portion of any commitment under the First Lien Credit Agreement in excess of the Maximum First Lien Principal Amount, (iii) increase any applicable margin or similar component of interest or yield on the loans thereunder by more than 200 basis points per annum, or impose any (or increase any) fee, original issue discount or similar payment in connection therewith that, together with all such fees, original issue discounts or similar payments imposed from the Issue Date, would have a similar effect; (iv) extend the stated maturity of the loans thereunder beyond the stated maturity of the notes; (v) change any representation, warranty, covenant, default or event of default thereunder in a manner materially adverse to the Company or any of its subsidiaries; (vi) change the redemption,

Index to Financial Statements

prepayment or defeasance provisions thereof in a manner which would be materially adverse to the Second Lien Secured Parties; (vii) add Collateral (unless such Collateral is also provided to the Collateral Agent), or (viii) increase the obligations thereunder of the Company or any of its subsidiaries or confer any additional rights on the First Lien Secured Parties which would be materially adverse to the Second Lien Secured Parties; provided that, other than with respect to clause (i) above, the foregoing will not apply to the initial entry into of a new revolving credit facility, but will apply to amendments made thereto.

The ability of the Collateral Agent and the holders to realize upon the Collateral may be subject to certain bankruptcy law limitations in the event of a bankruptcy. See “Risk Factors—Risks Relating to the Notes—The rights of holders of the notes with respect to the collateral are substantially limited by the terms of the intercreditor agreement.” The ability of the Collateral Agent and the holders to foreclose on the Collateral may be subject to lack of perfection, the consent of third parties, prior Liens and practical problems associated with the realization of the Collateral Agent’s Lien on the Collateral.

Additionally, the Collateral Agent may need to evaluate the impact of the potential liabilities before determining to foreclose on Collateral consisting of real property (if any) because a secured creditor that holds a Lien on real property may be held liable under environmental laws for the costs of remediating or preventing release or threatened releases of hazardous substances at such real property. Consequently, the Collateral Agent may decline to foreclose on such Collateral or exercise remedies available if it does not receive indemnification to its satisfaction from the holders.

On or after December 1, 2013, the Issuers may redeem all or a part of the notes at any time or from time to time upon not less than 30 nor more than 60 days’ prior notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest, if any, on the notes to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), if redeemed during the 12-month period beginning on December 1 of the years set forth below:

In addition, at any time on or prior to December 1, 2013, the Issuers may on any one or more occasions redeem up to 35% of the aggregate principal amount of the notes issued under the Indenture, upon not less than 30 nor more than 60 days’ prior notice, at a redemption price of 110.0% of the principal amount, plus accrued and unpaid interest, if any, on the notes to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), with the net cash proceeds of one or more Equity Offerings by the Company, provided that:

(1) at least 65% of the aggregate principal amount of notes issued under the Indenture (including additional notes) remains outstanding immediately after the occurrence of such redemption (excluding notes held by the Company and its Subsidiaries); and

(2) the redemption occurs within 90 days of the date of the closing of such Equity Offering.

In addition, at any time prior to December 1, 2013, the notes may be redeemed in whole or in part at the option of the Issuers upon not less than 30 nor more than 60 days’ prior notice at a redemption price equal to 100% of the principal amount thereof plus the Applicable Premium as of, and accrued and unpaid interest, if any, to the date of redemption (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

Index to Financial Statements

“Applicable Premium” means, as determined by the Company, with respect to a note at any redemption date, the greater of (x) 1.0% of the principal amount of such note and (y) the excess of (A) the present value at such time of (1) redemption price of such note as of December 1, 2013 (without regard to accrued and unpaid interest) plus (2) all required interest payments due on such note through December 1, 2013, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the principal amount of such note.

“Treasury Rate” means, with respect to the notes as of any redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the period from the redemption date to December 1, 2013; provided, however, that if the period from the redemption date to December 1, 2013 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to December 1, 2013 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

Except as provided above, the notes will not be redeemable at the Issuers’ option prior to their final maturity.

If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption as follows:

(1) if the relevant notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which the notes are listed; or

(2) if the relevant notes are not listed on any national securities exchange, on a pro rata basis.

No notes of $2,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the Indenture. Notices of redemption may not be conditional, except that any redemption described in the second paragraph under “—Optional Redemption” above may, at the Issuers’ discretion, be conditioned upon completion of the related Equity Offering.

If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of them called for redemption.

Except as set forth below under “—Repurchase at the Option of Holders,” the Issuers are not required to make mandatory redemption or sinking fund payments with respect to the notes or to repurchase the notes at the option of the holders. The Company and its Subsidiaries may acquire notes by means other than a redemption or required repurchase, whether by tender offer, open market purchases, negotiated transactions or otherwise, in accordance with applicable securities laws, so long as such acquisition does not otherwise violate the terms of the Indenture. However, future agreements of the Company may limit the ability of the Company or its Subsidiaries to purchase notes prior to maturity.

Index to Financial Statements

If a Change of Control occurs, each holder of notes will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000) of that holder’s notes pursuant to a Change of Control Offer on the terms set forth in the Indenture. In the Change of Control Offer, the Company will offer a Change of Control Payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest, if any, on the notes repurchased, to the date of settlement (the “Change of Control Purchase Date”), subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the Change of Control Purchase Date. Within 30 days following any Change of Control, the Company will mail a notice to each holder and the trustee describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes as of the Change of Control Purchase Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the Indenture and described in such notice.

The Company will comply with the requirements of Rule 14e-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the Indenture by virtue of such conflict.

On or before the Change of Control Purchase Date, the Company will, to the extent lawful, accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer. Promptly after such acceptance, on the Change of Control Purchase Date, the Company will:

(i) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

(ii) deliver or cause to be delivered to the trustee the notes properly accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by the Company.

On the Change of Control Purchase Date, the paying agent will mail to each holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), and the trustee will promptly authenticate and mail (or cause to be transferred by book-entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each new note will be in a principal amount of $2,000 or an integral multiple of $1,000. The Company will publicly announce the results of the Change of Control Offer as soon as practicable after the Change of Control Payment Date.

The occurrence of a Change of Control may result in a default under the Company’s existing or future Credit Facilities and may cause a default under other Indebtedness of the Company and its Subsidiaries, and give the lenders thereunder the right to require the Company to repay obligations outstanding thereunder. Moreover, the exercise by holders of their right to require the Company to repurchase the notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. The Company’s ability to repurchase notes following a Change of Control also may be limited by the Company’s then existing financial resources. Prior to complying with any of the provisions of this “Change of Control” covenant, but in any event no later than the Change of Control Purchase Date, the Company will, to the extent necessary, either repay all outstanding Credit Facilities or obtain any requisite consents under all agreements governing outstanding Credit Facilities to permit the repurchase of notes required by this covenant.

Index to Financial Statements

The provisions described above that require the Company to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the Indenture are applicable.

The Company will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Company and purchases all notes properly tendered and not withdrawn under the Change of Control Offer.

A Change of Control Offer may be made in advance of a Change of Control, and conditioned upon the occurrence of the Change of Control, if a definitive agreement is in place for the Change of Control at the time of making the Change of Control Offer.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of the Company and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Company to repurchase the notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Company and its Subsidiaries taken as a whole to another Person or group may be uncertain.

The Company will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1) the Company (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the fair market value (measured as of the date of the definitive agreement with respect to such Asset Sale) of the assets or Equity Interests issued or sold or otherwise disposed of; and

(2) at least 75% of the consideration received by the Company or such Restricted Subsidiary from all Asset Sales since the Issue Date, in the aggregate, is in the form of cash or Additional Assets (the fair market value of which shall be measured as of the date of the definitive agreement with respect to such Additional Assets).

For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities, as shown on the Company’s or such Restricted Subsidiary’s most recent consolidated balance sheet, of the Company or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms expressly subordinated to the notes or any Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases the Company or such Restricted Subsidiary from further liability; and

(b) any securities, notes or other obligations received by the Company or any such Restricted Subsidiary from such transferee that are converted within 90 days by the Company or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion.

Within 360 days after the receipt of any Net Proceeds from an Asset Sale, the Company or any such Restricted Subsidiary may apply those Net Proceeds at its option to any combination of the following:

(i) to repay or repurchase Indebtedness and other Obligations under a credit facility, any other First Lien Obligations (provided that, if the Indebtedness so repaid is revolving credit Indebtedness, to correspondingly reduce commitments with respect thereto) and Indebtedness and other Obligations arising under or pursuant to the notes;

Index to Financial Statements

(ii) to acquire all or substantially all of the properties or assets of one or more other Persons primarily engaged in the Oil and Gas Business, and, for this purpose, a division or line of business of a Person shall be treated as a separate Person so long as such properties and assets are acquired by the Company or a Restricted Subsidiary;

(iii) to acquire a majority of the Voting Stock of one or more other Persons primarily engaged in the Oil and Gas Business, if after giving effect to any such acquisition of Voting Stock, such Person is or becomes a Restricted Subsidiary; and

(iv) to make one or more capital expenditures or to acquire other long-term assets that are not classified as current assets under GAAP and that are used or useful in the Oil and Gas Business.

In the case of clauses (ii) through (iv) of the preceding paragraph, the Company (or the applicable Restricted Subsidiary, as the case may be) will be deemed to have complied with its obligations under the preceding paragraphs if it enters into a binding commitment to acquire such assets or Voting Stock or make such capital expenditure prior to 360 days after the receipt of the applicable Net Proceeds; provided that such binding commitment will be subject only to customary conditions and such acquisition or expenditure is completed within 180 days following the expiration of the aforementioned 360-day period. If the acquisition or expenditure contemplated by such binding commitment is not consummated on or before such 180th day, and the Company (or the applicable Restricted Subsidiary, as the case may be) has not applied the applicable Net Proceeds for another purpose permitted by the preceding paragraph on or before such 180th day, such commitment shall be deemed not to have been a permitted application of Net Proceeds.

Pending the final application of any Net Proceeds, the Company or any such Restricted Subsidiary may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the Indenture.

Any Net Proceeds from Asset Sales that are not applied or invested as provided in the third preceding paragraph will constitute “Excess Proceeds.” On the 361st day after the Asset Sale (or, at the Company’s option, any earlier date), if the aggregate amount of Excess Proceeds then exceeds $5.0 million, the Company will make an Asset Sale Offer to all holders of notes, and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the Indenture with respect to offers to purchase or redeem with the proceeds of sales of assets, to purchase the maximum principal amount of notes and such other pari passu Indebtedness that may be purchased out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of principal amount plus accrued and unpaid interest, if any, to the date of settlement, subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of settlement, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, the Company or any of its Restricted Subsidiaries may use those Excess Proceeds for any purpose not otherwise prohibited by the Indenture. If the aggregate principal amount of notes and other pari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such other pari passu Indebtedness to be purchased on a pro rata basis. Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the Indenture by virtue of such conflict.

Index to Financial Statements

Within 90 days after the end of each second and fourth fiscal quarter of the Company, commencing at the end of the fourth quarter of 2011, for which the Excess Cash Flow for such prior six month period exceeds $2.5 million, to the extent permitted by its Credit Facilities the Company will offer to purchase notes for cash in an aggregate amount equal to the Excess Cash Flow Offer Amount (the “Excess Cash Flow Offer”) at an offer price equal to 103% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest, if any, to the date of purchase (the “Excess Cash Flow Offer Payment”). If the aggregate principal amount of notes tendered into such Excess Cash Flow Offer exceeds the Excess Cash Flow Offer Amount, the trustee will select the notes to be purchased on a pro rata basis, by lot or by such other method as the trustee deems fair and appropriate.

Within 90 days following the end of each fiscal quarter referred to in the preceding paragraph with respect to which an Excess Cash Flow Offer is made, the Company will mail a notice to each holder and the trustee offering to repurchase notes as of the date specified in the notice (the “Excess Cash Flow Offer Purchase Date”), which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the Indenture and described in such notice.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Excess Cash Flow Offer. To the extent that the provisions of any securities laws or regulations conflict with the Excess Cash Flow provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the Indenture by virtue of such conflict.

On or before the Excess Cash Flow Offer Purchase Date, the Company will, to the extent lawful accept for payment all notes or portions of notes properly tendered pursuant to Excess Cash Flow Offer. Promptly after such acceptance, on the Excess Cash Flow Offer Purchase Date, the Company will:

(i) deposit with the paying agent an amount equal to the Excess Cash Flow Offer Payment in respect of all notes or portions of notes properly tendered; and

On the Excess Cash Flow Offer Purchase Date, the paying agent will mail to each holder of notes properly tendered the Excess Cash Flow Offer Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), and the trustee will promptly authenticate and mail (or cause to be transferred by book-entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each new note will be in a principal amount of $2,000 or an integral multiple of $1,000. The Company will publicly announce the results of the Excess Cash Flow Offer as soon as practicable after the Excess Cash Flow Offer Purchase Date.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of the Company’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Company’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Company or payable to the Company or a Restricted Subsidiary of the Company);

Index to Financial Statements

(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Company) any Equity Interests of the Company or any direct or indirect parent of the Company;

(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness of an Issuer or any Guarantor that is subordinated to the notes or the Guarantees, except a payment of interest or principal at or within one year of the Stated Maturity thereof; or

(4) make any Restricted Investment (all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as “Restricted Payments”),

(1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;

(2) the Company would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Consolidated Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock;” and

(3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and its Restricted Subsidiaries after the date of the Indenture (excluding Restricted Payments permitted by clauses (2) through (9) of the next succeeding paragraph), is less than the sum, without duplication, of (the “Restricted Payments Basket”):

(a) 50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from the beginning of the first full fiscal quarter of the Company commencing immediately before the Issue Date to the end of the Company’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus

(b) 100% of the aggregate net cash proceeds received by the Company (including the fair market value of any Additional Assets (measured as of the date of the definitive agreement with respect to such Additional Assets) to the extent acquired in consideration of Equity Interests of the Company (other than Disqualified Stock and Sponsor Preferred Stock)) since the Issue Date as a contribution to its common equity capital or from the issue or sale of Equity Interests of the Company (other than Disqualified Stock and Sponsor Preferred Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of the Company that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of the Company), plus

(d) to the extent that any Restricted Investment that was made after the Issue Date is sold for cash or otherwise liquidated or repaid for cash, the lesser of (i) the cash return of capital with respect to such Restricted Investment (less the cost of disposition, if any) and (ii) the initial amount of such Restricted Investment, plus

(e) to the extent that any Unrestricted Subsidiary of the Company is redesignated as a Restricted Subsidiary after the Issue Date, the lesser of (i) the fair market value of the Company’s Investment in such Subsidiary as of the date of such redesignation or (ii) such fair market value as of the date on which such Subsidiary was originally designated as an Unrestricted Subsidiary.

Index to Financial Statements

So long as no Default or Event of Default has occurred and is continuing or would be caused thereby (except in the case of Restricted Payments pursuant to clause (8) below), the preceding provisions will not prohibit:

(1) the payment of any dividend or other distribution within 60 days after the date of declaration of the dividend or other distribution, if at the date of declaration such dividend or other distribution payment would have complied with the provisions of the Indenture;

(2) the purchase, redemption, defeasance or other acquisition or retirement for value of any Indebtedness of either Issuer or any Guarantor that is subordinated to the notes or the Guarantees or of any Equity Interests of the Company in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of the Company) of, Equity Interests of the Company (other than Disqualified Stock); provided that the amount of any such net cash proceeds that are utilized for any such purchase, redemption, defeasance, or other acquisition or retirement for value will be excluded from clause (3)(b) of the preceding paragraph;

(3) the purchase, redemption, defeasance or other acquisition or retirement for value of subordinated Indebtedness of an Issuer or any Guarantor with the net cash proceeds from an incurrence of, or in exchange for, Permitted Refinancing Indebtedness;

(6) so long as no Default has occurred and is continuing, upon the occurrence of a Change of Control or an Asset Sale and within 60 days after the completion of the offer to repurchase the notes under the covenants described under “—Repurchase at the Option of Holders—Change of Control” or “—Asset Sales” above (including the purchase of all notes tendered), any purchase, redemption, defeasance or other acquisition or retirement for value of any Indebtedness of either Issuer or any Guarantor that is subordinated to the notes or the Guarantees and that is required under the terms thereof as a result of such Change of Control or Asset Sale at a purchase or redemption price not to exceed 101% of the outstanding principal amount thereof, plus accrued and unpaid interest thereon, if any, provided that, in the notice to holders relating to a Change of Control or Asset Sale hereunder, the Company shall describe this clause (6);

(8) so long as the Company is treated for U.S. federal tax purposes as a disregarded entity or partnership, Permitted Tax Distributions; and

(9) other Restricted Payments in an aggregate amount since the Issue Date not to exceed $2.0 million.

The amount of all Restricted Payments (other than cash) will be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The fair market value of any assets or securities that are required to be valued by this covenant will be determined by the Board of Directors, whose determination shall be evidenced by a Board Resolution. The Board of Directors’ determination must be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if the fair market value exceeds $15.0 million. Not later than the date of making any Restricted Payment that would have the effect of reducing the Restricted Payments Basket under the first paragraph of this covenant, the Company will deliver to the trustee an officers’ certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by this “Restricted Payments” covenant were computed, together with a copy of any fairness opinion or appraisal required by the Indenture. For purposes of determining compliance with this “Restricted Payments” covenant, in the event that a Restricted Payment meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1)-(9), the Company will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such Restricted Payment in any manner that complies with this covenant.

Index to Financial Statements

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt) and neither the Issuers nor any Guarantor will issue any Disqualified Stock, and the Company will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock; provided, however, that the Issuers and any Guarantor may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, if the Consolidated Coverage Ratio for the Company’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock is issued would have been at least 2.5 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or Disqualified Stock had been issued, as the case may be, at the beginning of such four-quarter period.

The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Debt”):

(1) the incurrence by the Issuers or any Guarantor of Indebtedness under one or more Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of the Company and its Restricted Subsidiaries thereunder) not to exceed an amount equal to the greater of (a) $35.0 million (minus the amount of any permanent payment and commitment reductions) and (b) 10% of ACNTA as of the date of such incurrence;

(2) the incurrence by the Company or any of its Restricted Subsidiaries of the Existing Indebtedness;

(3) the incurrence by the Issuers and the Guarantors of Indebtedness represented by the old notes and the related Guarantees issued on the date of the Indenture and the new notes and the related Guarantees to be issued pursuant to the Registration Rights Agreement;

(4) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvement of property, plant or equipment used in the business of the Company or such Restricted Subsidiary, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to refund, refinance or replace any Indebtedness incurred pursuant to this clause (4), not to exceed $4.0 million at any time outstanding;

(5) the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund Indebtedness (other than intercompany Indebtedness) that was permitted by the Indenture to be incurred under the first paragraph of this covenant or clause (2), (3), (4) or (11) of this paragraph or this clause (5);

(6) the incurrence by the Company or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries; provided, however, that:

(a) if an Issuer is the obligor on such Indebtedness and a Guarantor is not the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the notes, or if a Guarantor is the obligor on such Indebtedness and neither an Issuer nor another Guarantor is the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the Guarantee of such Guarantor; and

(b)(i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person that is neither the Company nor a Restricted

Index to Financial Statements

Subsidiary of the Company will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the incurrence by the Company or any of its Restricted Subsidiaries of Hedging Obligations;

(8) the guarantee by either Issuer or any of the Guarantors of Indebtedness of an Issuer or any Guarantor that was permitted to be incurred by another provision of this covenant;

(9) the incurrence by the Company or any of its Restricted Subsidiaries of obligations relating to net gas balancing positions arising in the ordinary course of business and consistent with past practice;

(10) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness in respect of bid, performance, surety and similar bonds issued for the account of the Company and any of its Restricted Subsidiaries in the ordinary course of business, including guarantees and obligations of the Company and any of its Restricted Subsidiaries with respect to letters of credit supporting such obligations (in each other than an obligation for money borrowed);

(11) Indebtedness of a Restricted Subsidiary incurred and outstanding on the date on which such Restricted Subsidiary was acquired by, or merged into, the Company or any Restricted Subsidiary (other than Indebtedness incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was otherwise acquired by the Company or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that at the time such Restricted Subsidiary is acquired by the Company, the Company would have been able in incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant after giving effect to the incurrence of such Indebtedness pursuant to this clause (11);

(12) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness arising from agreements of the Company or any of its Restricted Subsidiaries providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or Capital Stock of a Subsidiary, provided that the maximum aggregate liability in respect of all such Indebtedness shall at no time exceed the gross proceeds actually received by the Company and its Restricted Subsidiaries in connection with such disposition; and

(13) the incurrence by the Company or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount at any time outstanding, not to exceed $2.0 million.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of Indebtedness (including Acquired Debt) meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (13) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such item of Indebtedness in any manner that complies with this covenant.

The amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP. Indebtedness of any Person existing at the time such Person becomes a Restricted Subsidiary shall be deemed to have been incurred by the Company and the Restricted Subsidiary at the time such Person becomes a Restricted Subsidiary. The accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, and the payment of dividends or other distributions on Disqualified Stock in the form of additional shares, units or the like of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; provided, in each such case, that the amount thereof is included for purposes of determining the Consolidated Coverage Ratio of the Company.

Index to Financial Statements

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, assume or suffer to exist any Lien securing Indebtedness of any kind on any asset now owned or hereafter acquired, except Permitted Liens.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock to the Company or any of its Restricted Subsidiaries, or pay any Indebtedness or other obligations owed to the Company or any of its Restricted Subsidiaries;

(2) make loans or advances to the Company or any of its Restricted Subsidiaries; or

(3) transfer any of its properties or assets to the Company or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements governing Existing Indebtedness and the Senior Credit Agreement as in effect on the date of the Indenture and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of those agreements, provided that the amendments, modifications, restatements, renewals, increases, supplements, refundings, replacement or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend, distribution and other payment restrictions than those contained in such agreements on the date of the Indenture;

(4) any instrument governing Indebtedness or Capital Stock of a Person acquired by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred or issued in connection with such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired, and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of those instruments, provided that the amendments, modifications, restatements, renewals, increases, supplements, refundings, replacement or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend, distribution and other payment restrictions than those contained in those instruments; provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the Indenture to be incurred;

(5) customary non-assignment provisions in contracts and leases entered into in the ordinary course of business and consistent with past practices;

(6) purchase money obligations for property acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions on that property of the nature described in clause (3) of the preceding paragraph;

(7) any agreement for the sale or other disposition of a Restricted Subsidiary of the Company that restricts distributions by that Restricted Subsidiary pending its sale or other disposition;

(8) Permitted Refinancing Indebtedness, provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

Index to Financial Statements

(9) agreements governing other Indebtedness of the Company and one or more Restricted Subsidiaries permitted under the Indenture, provided that the restrictions in the agreements governing such Indebtedness are not materially more restrictive, taken as a whole, than those in the Indenture;

(10) Liens securing Indebtedness otherwise permitted to be incurred under the provisions of the covenant described above under the caption “—Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

(11) provisions with respect to the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, stock sale agreements, agreements respecting Permitted Business Investments and other similar agreements entered into in the ordinary course of business; and

(12) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business.

Neither of the Issuers may, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not such Issuer is the survivor); or (2) sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of is properties or assets, in one or more related transactions, to another Person, unless:

(1) either (a) such Issuer is the surviving Person; or (b) the Person formed by or surviving any such consolidation or merger (if other than such Issuer) or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made is a corporation, limited partnership or limited liability company organized or existing under the laws of the United States, any state of the United States or the District of Columbia, provided that the Co-Issuer may not consolidate or merge with or into another Person other than a corporation for so long as the Company is not a corporation;

(2) the Person formed by or surviving any such consolidation or merger (if other than such Issuer) or the Person to which such sale, assignment, transfer, lease, conveyance or other disposition has been made assumes all the obligations of such Issuer under the notes, the Indenture and the Registration Rights Agreement pursuant to agreements reasonably satisfactory to the trustee;

(4) except with respect to a transaction solely between the Company and a Guarantor or a transaction involving only the Co-Issuer and not the Company, the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made will, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Consolidated Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock;” and

(5) such Issuer shall have delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and such supplemental indenture (if any) comply with the Indenture.

In addition, the Company will not, directly or indirectly, lease all or substantially all of the properties and assets of it and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to any other Person.

(1) a merger of an Issuer with an Affiliate solely for the purpose of reincorporating or reorganizing such Issuer in another jurisdiction; or

Index to Financial Statements

(2) any consolidation or merger, or any sale, assignment, transfer, conveyance, lease or other disposition of assets between or among the Company and its Restricted Subsidiaries.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the properties or assets of a Person.

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of the Company (each, an “Affiliate Transaction”), unless:

(1) the Affiliate Transaction is on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person; and

(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $5.0 million, a resolution of the Board of Directors set forth in an officers’ certificate certifying that such Affiliate Transaction(s) complies with this covenant and that such Affiliate Transaction(s) has been approved by a majority of the members of the Board of Directors;

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $15.0 million, the Company delivers to the trustee a written opinion that such Affiliate Transaction(s) is fair, from a financial point of view, to the Company and its Restricted Subsidiaries, taken as a whole, or that such Affiliate Transaction(s) is not less favorable to the Company and its Restricted Subsidiaries than could reasonably be expected to be obtained at the time in an arm’s- length transaction with a person who is not an Affiliate, in either such case issued by an independent accounting, appraisal or investment banking firm of recognized standing;

(3) so long as Platinum is an Affiliate of the Company, with respect to any Affiliate Transaction or series of related Affiliate Transactions, between the Company or any of its Restricted Subsidiaries, on the one hand, and Platinum Partners or any of its Affiliates (other than the Company or any of its Restricted Affiliates), on the other, the chief executive officer of the Company delivers to the trustee an officer’s certificate certifying that such Affiliate Transaction(s) complies with this covenant and that such Affiliate Transaction(s) has been approved by a majority of the members of the Board of Directors; and

(4) so long as Platinum is an Affiliate of the Company, with respect to any Affiliate Transaction or series of related Affiliate Transactions, between John Hoffman or any of his Affiliates (other than the Company or any of its Restricted Subsidiaries), on the one hand, and the Company or any of its Restricted Subsidiaries, on the other, Platinum Partners delivers to the trustee a certificate certifying that such Affiliate Transaction(s) complies with this covenant and that such Affiliate Transaction(s) has been approved by a majority of the members of the Board of Directors.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1) any employment or severance agreement or other employee or director compensation agreement, arrangement or plan, or any amendment thereto, entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business;

Index to Financial Statements

(2) transactions between or among any of the Company and its Restricted Subsidiaries;

(3) transactions with a Person (other than an Unrestricted Subsidiary of the Company) that is an Affiliate of the Company solely because the Company owns an Equity Interest in such Person;

(4) the payment of reasonable directors’ fees, the payments of other reasonable benefits and the provision of officers’ and directors’ indemnification and insurance to the extent permitted by law to persons who are officers and directors of the Company and its Restricted Subsidiaries, in each case in the ordinary course of business and approved by the Board of Directors;

(5) sales of Equity Interests (other than Disqualified Stock) to Affiliates of the Company, or contributions to the capital of the Company by its Affiliates;

(6) transactions pursuant to any agreement in effect on the Issue Date, as such agreement may be amended, modified or supplemented from time to time provided that any such amendment, modification or supplement will not be materially adverse to the Company or the Restricted Subsidiaries compared to the terms of such agreement in effect on the Issue Date; and

(7) Permitted Investments or Restricted Payments that are permitted by the provisions of the Indenture described above under the caption “—Restricted Payments.”

The Board of Directors of the Company may designate any Restricted Subsidiary of the Company to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary of the Company is designated as an Unrestricted Subsidiary, the aggregate fair market value of all outstanding Investments owned by the Company and its Restricted Subsidiaries in the Subsidiary properly designated will be deemed to be an Investment made as of the time of the designation and will reduce the amount of the Restricted Payments Basket or represent Permitted Investments, as determined by the Company. That designation will only be permitted if the Investment would be permitted at that time and if the Subsidiary so designated otherwise meets the definition of an Unrestricted Subsidiary.

Any designation of a Subsidiary of the Company as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee the Board Resolution giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture, and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of the Company as of such date under the covenant described under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock,” and any Lien of such Subsidiary will be deemed to be incurred as of such date under the covenant described under the caption “Liens,” and, if such Indebtedness is not permitted to be incurred under such covenant, or such Lien is not permitted to be incurred under such covenant then, in either case, the Company will be in default of such covenant.

The Board of Directors of the Company may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of the Company; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company of any outstanding Indebtedness of such Unrestricted Subsidiary and the creation, incurrence, assumption or otherwise causing to exist any Lien of such Unrestricted Subsidiary and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period, (2) such Lien is permitted under the covenant described above under the caption “—Liens” and (3) no Default or Event of Default would be in existence following such designation.

Index to Financial Statements

If any Restricted Subsidiary of the Company that is not already a Guarantor guarantees any other Indebtedness of the Company under a credit facility, then that Restricted Subsidiary will become a Guarantor by executing a supplemental Indenture and delivering it to the trustee within 20 Business Days of the date on which it guaranteed Indebtedness of the Company under a credit facility; provided, however, that the foregoing shall not apply to Subsidiaries of the Company that have properly been designated as Unrestricted Subsidiaries in accordance with the Indenture for so long as they continue to constitute Unrestricted Subsidiaries. Any such guarantee will be subject to the release provisions set forth above under “—Guarantees.”

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business, except to such extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

The Co-Issuer may not engage in any business not related directly or indirectly to obtaining money or arranging financing for the Company or its Restricted Subsidiaries.

Whether or not required by the rules and regulations of the SEC, so long as any notes are outstanding, the Company will furnish to the holders of notes and the trustee (by making them available on its website as described below), within the time periods specified in the SEC’s rules and regulations:

(1) all quarterly and annual reports that would be required to be filed with the SEC on Forms 10-Q and 10-K if the Company were required to file such reports; and

(2) all current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports.

All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10 K will include a report on the Company’s consolidated financial statements by the Company’s certified independent accountants. In addition, following the consummation of the Exchange Offer contemplated by the Registration Rights Agreement, the Company will file a copy of each of the reports referred to in clauses (1) and (2) above with the SEC for public availability within the time periods specified in the rules and regulations applicable to such reports (unless the SEC will not accept such a filing) and will post the reports on its website within those time periods.

If, at any time after consummation of the Exchange Offer contemplated by the Registration Rights Agreement, the Company is no longer subject to the periodic reporting requirements of the Exchange Act for any reason, the Company will nevertheless continue filing the reports specified in the preceding paragraphs of this covenant with the SEC within the time periods specified above unless the SEC will not accept such a filing. The Company will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the foregoing, the SEC will not accept the Company’s filings for any reason, the Company will post the reports referred to in the preceding paragraphs on its website within the time periods that would apply if the Company were required to file those reports with the SEC.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraphs will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

Index to Financial Statements

In addition, the Company will arrange and participate in quarterly conference calls to discuss its results of operations with noteholders, no later than 10 business days following the date on which each of the quarterly and annual reports are made available as provided above. The Company will provide to the holders of the notes dial-in conference call information substantially concurrently with the posting of such reports on its website. Access to any such reports on the Company’s website and to such quarterly conference calls may be password protected, provided that the Company’s makes reasonable efforts to notify the holders of the notes of the password and other information required to access such reports on its website and such quarterly conference calls.

The Company will post the reports specified in this covenant on its website no later than the date the Company is required to provide those reports to the trustee and the holders of the notes and maintain such posting so long as any notes remain outstanding; provided, however, that such website may be password protected so long as the Company makes reasonable efforts to notify the trustee and the holders of the notes of postings to the website (including through the information dissemination procedures of the depositary for the notes) and to provide the trustee and the holders of the notes with access to such website.

In the event that any direct or indirect parent company of the Company guarantees the notes at the time of or following an initial public offering of such parent company, the Indenture will permit the Company to satisfy its obligations in this covenant with respect to financial information relating to the Company by furnishing financial information relating to such parent company; provided, however, that the same is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such parent company and any of its Subsidiaries, on the one hand, and the information relating to the Company and its Subsidiaries, on a standalone basis, on the other hand.

The Company and its Restricted Subsidiaries will not allow their aggregate capital expenditures to exceed (i) $60.0 million for the fiscal year ending December 31, 2011 and (ii) 30% of Consolidated EBITDAX for any fiscal year thereafter; provided that, all capital expenditures in an aggregate amount not to exceed $210 million (including $39 million in cash and the assumption of $168.4 million of asset retirement obligations) relating, directly or indirectly, to the Merit acquisition shall not be deemed a capital expenditure and will not be included for purposes of determining compliance with this covenant; and provided further that, the difference between the Company’s and its Restricted Subsidiaries’ permitted capital expenditures for any fiscal year and their actual capital expenditures for such fiscal year, if positive, shall be available for use for capital expenditures in the subsequent fiscal year without regard to the preceding restriction. The Company shall certify its compliance with this covenant in a certificate delivered to the trustee in accordance with the Indenture no later than March 31 following the completion of each fiscal year.

The Company and its Restricted Subsidiaries will not allow the ratio of their SEC PV-10 to Consolidated Leverage to be less than 1.4 to 1.0 as of the last day of each fiscal year and shall certify their compliance with this covenant in a certificate delivered to the trustee in accordance with the Indenture no later than March 31 following the completion of each fiscal year.

Within 180 days after the end of each second and fourth fiscal quarter of the Company, commencing with the fourth quarter of 2011 and continuing through the fourth quarter of 2013, after compliance with its obligations under the covenant described above under “—Excess Cash Flow Offer” to purchase any notes from the Excess Cash Flow Offer Amount generated during the preceding six month period and provided that such covenant would require an offer to be made for such period and the Company has made such offer, the Company

Index to Financial Statements

may, to the extent permitted by its Credit Facilities, purchase or otherwise retire any Sponsor Preferred Stock in an aggregate amount up to such Excess Cash Flow Offer Amount, provided that no more than $5.0 million may be expended for such purpose in either of the years ending December 31, 2012 and 2013. Within 180 days after the end of each second and fourth fiscal quarter of the Company, commencing with the fourth quarter of 2013, after compliance with its obligations under the covenant described above under “—Excess Cash Flow Offer” to purchase any notes from the Excess Cash Flow Offer Amount generated during the preceding six month period and provided that such covenant would require an offer to be made for such period and the Company has made such offer, the Company may, to the extent permitted by its Credit Facilities, repurchase or otherwise retire any Sponsor Preferred Stock in an aggregate amount up to such Excess Cash Flow Offer Amount. Notwithstanding the foregoing but subject to the terms of the Credit Facilities, the Company may at any time following an initial public offering of the Capital Stock of the Company (or any parent holding company) that does not result in a Change of Control, repurchase or otherwise retire any Sponsor Preferred Stock in cash with the net proceeds received by the Company from such initial public offering, provided that no more than the total amount of net proceeds received by the Company from such initial public offering may be expended for such purpose. Except as provided in this covenant, neither the Company nor any of its Subsidiaries shall make any payments on the Sponsor Preferred Stock.

(2) default in payment when due of the principal of, or premium, if any, on the notes;

(3) failure by the Company to comply with the provisions described under “—Certain Covenants—Merger, Consolidation or Sale of Assets” or under the caption “—Repurchase at the Option of Holders”;

(4) failure by the Company or any of its Restricted Subsidiaries, as applicable, to comply for 30 days after receipt of written notice from the trustee or the holders of at least 25% in aggregate principal amount of the notes with the provisions described under the captions “—Certain Covenants—Restricted Payments,” “—Incurrence of Indebtedness and Issuance of Preferred Stock,” “—Liens,” “—Dividends and Other Payment Restrictions Affecting Subsidiaries,” “—Transactions with Affiliates,” “—Additional Guarantees” and “—Business Activities”;

(5) failure by the Company for 30 days after notice from the trustee or the holders of at least 25% in aggregate principal amount of the notes outstanding to comply with any of the other agreements in the Indenture (or 60 days with respect to the covenant described above under “—Certain Covenants—Reports”);

(6) default under any mortgage, Indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), whether such Indebtedness or guarantee now exists, or is created after the date of the Indenture, if that default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”); or

(b) results in the acceleration of such Indebtedness prior to its Stated Maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $15.0 million or more and such Payment Default is not cured or such acceleration rescinded within 15 days;

Index to Financial Statements

(7) failure by the Company or any of its Restricted Subsidiaries to pay final judgments aggregating in excess of $15.0 million, which judgments are not paid, discharged or stayed (including a stay pending appeal) for a period of 60 days after the date of such final judgment (or, if later, the date when payment is due pursuant to such judgment);

(8) except as permitted by the Indenture, any Guarantee shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any Guarantor, or any Person acting on behalf of any Guarantor, shall deny or disaffirm its obligations under its Guarantee;

(9) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to the Company or any of its Restricted Subsidiaries; and

(10)(x) any Collateral Agreement at any time for any reason shall cease to be in full force and effect in all material respects, except as provided in the Collateral Agreements or the Indenture; (y) any Collateral Agreement ceases to give the Collateral Agent the Liens, rights, powers and privileges purported to be created thereby with respect to any Collateral having a fair market value in excess of $1.0 million, superior to and prior to the rights of all third Persons other than the holders of Permitted Liens and subject to no other Liens except as expressly permitted by the applicable Collateral Agreement or the Indenture; or (z) the Company or any of the Guarantors, directly or indirectly, contest in any manner the effectiveness, validity, binding nature or enforceability of any Collateral Agreement.

In the case of an Event of Default arising from certain events of bankruptcy, insolvency or reorganization, with respect to the Company or any Restricted Subsidiary, all outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes may declare all the notes to be due and payable immediately.

Holders of the notes may not enforce the Indenture or the notes except as provided in the Indenture. Subject to certain limitations, holders of a majority in aggregate principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold notice of any continuing Default or Event of Default from holders of the notes if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal of, or interest or premium, if any, on, the notes.

Subject to the provisions of the Indenture relating to the duties of the trustee in case an Event of Default occurs and is continuing, the trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any holders of notes unless such holders have offered to the trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, interest or premium, if any, when due, no holder of a note may pursue any remedy with respect to the Indenture or the notes unless:

(1) such holder has previously given the trustee notice that an Event of Default is continuing;

(2) holders of at least 25% in aggregate principal amount of the then outstanding notes have requested the trustee to pursue the remedy;

(3) such holders have offered the trustee reasonable security or indemnity against any loss, liability or expense;

(4) the trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) holders of a majority in aggregate principal amount of the then outstanding notes have not given the trustee a direction inconsistent with such request within such 60-day period.

The holders of a majority in aggregate principal amount of the notes then outstanding by notice to the trustee may on behalf of the holders of all of the notes rescind an acceleration or waive any past Default or Event

Index to Financial Statements

of Default and its consequences under the Indenture except a continuing Default or Event of Default in the payment of principal of, or interest or premium, if any, on, the notes or in respect of a covenant that cannot be amended without the consent of each holder.

In the case of any Event of Default occurring by reason of any willful action or inaction taken or not taken by or on behalf of the Company with the intention of avoiding payment of the premium that the Company would have had to pay if the Company then had elected to redeem the notes prior to stated maturity (other than with the net cash proceeds of an Equity Offering), an equivalent premium will also become and be immediately due and payable to the extent permitted by law upon the acceleration of the notes.

The Issuers are required to deliver to the trustee annually a statement regarding compliance with the Indenture. Upon becoming aware of any Default or Event of Default, the Company is required to deliver to the trustee a statement specifying such Default or Event of Default.

No director, officer, employee, incorporator or stockholder or other owner of Capital Stock of an Issuer or any Guarantor, as such, will have any liability for any obligations of such Issuer or any Guarantor under the notes, the Indenture or the Guarantees, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

The Issuers may at any time, at the option of its Board of Directors of the Company evidenced by a resolution set forth in an officers’ certificate, elect to have all of their obligations discharged with respect to outstanding notes and all obligations of the Guarantors discharged with respect to their Guarantees (“Legal Defeasance”) except for:

(1) the rights of holders of outstanding notes to receive payments in respect of the principal of, and interest or premium, if any, on such notes when such payments are due from the trust referred to below;

(2) the Issuers’ obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the trustee, and the Issuers’ obligations in connection therewith; and

In addition, the Issuers may, at their option and at any time, elect to have their and the Guarantors’ obligations released with respect to certain covenants that are described in the Indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, insolvency or reorganization events) described under “—Events of Default and Remedies” will no longer constitute an Event of Default. If the Issuers exercise either their Legal Defeasance or Covenant Defeasance option, each Guarantor will be released and relieved of any obligations under its Guarantee and any security for the notes (other than the trust) will be released.

Index to Financial Statements

(1) the Company or any Guarantor must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, and interest or premium, if any, on the outstanding notes on the date of fixed maturity or on the applicable redemption date, as the case may be, and the Company must specify whether the notes are being defeased to the date of fixed maturity or to a particular redemption date;

(2) in the case of Legal Defeasance, the Company has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that:

(a) the Company has received from, or there has been published by, the Internal Revenue Service a ruling; or

(b) since the date of the Indenture, there has been a change in the applicable federal income tax law,

in either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Company has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit);

(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the Indenture) to which either Issuer or any of the Guarantors is a party or by which either Issuer or any of the Guarantors is bound;

(6) the Company must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Company with the intent of preferring the holders of notes over the other creditors of the Company with the intent of defeating, hindering, delaying or defrauding creditors of the Company or others; and

(7) the Company must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Except as provided in the next three succeeding paragraphs, the Indenture Documents may be amended or supplemented with the consent of the holders of a majority in aggregate principal amount of the notes affected thereby then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or Exchange Offer for, notes), and any existing Default or Event of Default or compliance with any provision of the Indenture Documents may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or Exchange Offer for, notes); provided that notes held by Permitted Holders, the Company and their respective Affiliates shall not be counted in determining the vote of any amendment, supplement or waiver.

Index to Financial Statements

Without the consent of each holder affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):

(1) reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any note or alter the provisions with respect to the redemption or repurchase of the notes (other than provisions relating to the covenants described above under the caption “—Repurchase at the Option of Holders”);

(3) reduce the rate of or change the time for payment of interest, including any default interest, on any note;

(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, if any, on the notes (except a rescission of acceleration of the notes by the holders of a majority in aggregate principal amount of the notes and a waiver of the payment default that resulted from such acceleration);

(6) make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of, or interest or premium, if any, on the notes (other than as permitted in clause (7) below);

(7) waive a redemption or repurchase payment with respect to any note (other than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of holders”);

(8) release any Guarantor from any of its obligations under its Guarantee or the Indenture, except in accordance with the terms of the Indenture and the Intercreditor Agreement; or

(9) make any change in the preceding amendment, supplement and waiver provisions.

Notwithstanding the preceding, without the consent of any holder of notes, the Issuers, the Guarantors and the trustee may amend or supplement the Indenture Documents:

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

(3) to provide for the assumption of an Issuer’s or a Guarantor’s obligations to holders of notes in the case of a merger or consolidation or sale of all or substantially all of such Issuer’s or Guarantor’s properties or assets;

(4) to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the Indenture of any holder, provided that any change to conform the Indenture to this Prospectus will not be deemed to adversely affect the legal rights under the Indenture of any holder;

(5) to secure the notes or the Guarantees pursuant to the requirements of the covenant described above under the heading “—Collateral” or otherwise;

(6) to provide for the issuance of additional notes in accordance with the limitations set forth in the Indenture;

(7) to add any additional guarantor or to evidence the release of any Guarantor from its Guarantee, in each case as provided in the Indenture and in the Intercreditor Agreement;

(8) to comply with requirements of the Commission in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act; or

(9) to evidence or provide for the acceptance of appointment under the Indenture of a successor trustee.

Index to Financial Statements

Without the consent of the holders of at least 70% in aggregate principal amount of the notes then outstanding (excluding notes held by Permitted Holders, the Company and their respective affiliates and including, without limitation, consents obtained in connection with a purchase of, or tender offer or Exchange Offer for, notes), an amendment, supplement or waiver may not (i) release all or a material portion of the Collateral from the Liens created pursuant to the Collateral Agreements or (ii) subordinate any Liens created pursuant to the Collateral Agreements, except, in each case, in accordance with the Indenture and the Collateral Agreements.

Neither the Company nor any Restricted Subsidiary will take or omit to take any action which would adversely affect or impair in any material respect the Liens in favor of the Collateral Agent with respect to the Collateral, except as otherwise permitted or required by the Collateral Agreements or the Indenture. Neither the Company nor any Restricted Subsidiary will enter into any agreement that requires the proceeds received from any sale of Collateral to be applied to repay, redeem, defease or otherwise acquire or retire any Indebtedness of any Person, other than First Lien Debt Documents or as permitted by the Indenture and the Collateral Agreements (including the Intercreditor Agreement).

The Issuers and the Guarantors shall execute any and all further documents, financing statements, agreements and instruments, and take all further action that may be required under applicable law, or that the Collateral Agent may reasonably request, in order to grant, preserve, protect and perfect the validity and priority of the security interests created or intended to be created by the collateral agreements in the Collateral. In addition, from time to time, the Company will reasonably promptly secure the obligations under the Indenture and the Collateral Agreements by pledging or creating, or causing to be pledged or created, perfected security interests with respect to the Collateral. The Company shall deliver or cause to be delivered to the Collateral Agent all such instruments and documents as the Collateral Agent shall reasonably request to evidence compliance with this covenant.

The Indenture will be discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise specified in the Indenture), when:

(a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to the Issuers, have been delivered to the trustee for cancellation; or

(b) all notes that have not been delivered to the trustee for cancellation have become due and payable or will become due and payable within one year by reason of the mailing of a notice of redemption or otherwise and the Company or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire Indebtedness on the notes not delivered to the trustee for cancellation for principal, interest or premium, if any, and accrued interest to the date of fixed maturity or redemption;

(2) no Default or Event of Default has occurred and is continuing on the date of the deposit or will occur as a result of the deposit and the deposit will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the Indenture) to which either Issuer or any of Guarantors is a party or by which either Issuer or any Guarantor is bound;

Index to Financial Statements

(3) the Company or any Guarantor has paid or caused to be paid all sums payable by the Issuers and the Guarantors under the Indenture; and

(4) the Company has delivered irrevocable instructions to the trustee under the Indenture to apply the deposited money toward the payment of the notes at fixed maturity or the redemption date, as the case may be.

In addition, the Company must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

If the trustee becomes a creditor of either Issuer or any Guarantor, the Indenture will limit its right to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Trust Indenture Act) after a Default has occurred and is continuing, it must eliminate such conflict within 90 days, apply to the Commission for permission to continue (if the Indenture is then qualified under the Trust Indenture Act) or resign.

The holders of a majority in aggregate principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. If an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its powers, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any holder of notes, unless such holder has offered to the trustee security or indemnity satisfactory to it against any loss, liability or expense.

The Indenture, the notes and the Guarantees will be governed by the laws of the State of New York.

Anyone who receives this Prospectus may obtain a copy of the Indenture without charge by writing to the Company at: 11451 Katy Freeway, Suite 500, Houston, Texas 77079, Attention: Chief Financial Officer.

Set forth below are certain defined terms used in the Indenture. Reference is made to the Indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

“ACNTA” (Adjusted Consolidated Net Tangible Assets) means (without duplication), as of the date of determination:

(a) discounted future net revenue from proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a reserve report prepared by the Company as of the end of the Company’s most recently completed fiscal year (which, in the case of the fiscal year ended December 31, 2009 will be deemed to be the reserve report prepared as of December 31, 2010), as increased by, as of the date of determination, the discounted future net revenue from:

(i) estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to acquisitions consummated since the date of such year-end reserve report, and

Index to Financial Statements

(ii) estimated crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward determinations of estimates of proved crude oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior year end) due to exploration, development or exploitation, production or other activities which reserves were not reflected in such year-end reserve report,

in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report), and decreased by, as of the date of determination, the discounted future net revenue attributable to

(iii) estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report produced or disposed of since the date of such year-end reserve report and

(iv) reductions in the estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report since the date of such year-end reserve report attributable to downward determinations of estimates of proved crude oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such year-end reserve report,

in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report);

(b) the capitalized costs that are attributable to crude oil and natural gas properties of the Company and its Restricted Subsidiaries to which no proved crude oil and natural gas reserves are attributed, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest annual or quarterly financial statements;

(c) the Net Working Capital on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and

(d) the greater of (I) the net book value on a date no earlier than the date of the Company’s latest annual or quarterly financial statements and (II) the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries as of a date no earlier than the date of the Company’s latest audited financial statements;

(2) minus, to the extent not otherwise taken into account in the immediately preceding clause (1), the sum of:

(b) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest audited financial statements;

(c) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report), attributable to reserves subject to participation interests, overriding royalty interests or other interests of third parties, pursuant to participation, partnership, vendor financing or other agreements then in effect, or which otherwise are required to be delivered to third parties;

(d) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto; and

(e) the discounted future net revenue, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of

Index to Financial Statements

production included in determining the discounted future net revenue specified in the immediately preceding clause (1)(a) (utilizing the same prices utilized in the Company’s year-end reserve report), would be necessary to satisfy fully the obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.

(1) Indebtedness of any other Person existing at the time such other Person was merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Subsidiary of, such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

(2) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or another Restricted Subsidiary; or

(3) Capital Stock constituting a minority in any Person that at such time is a Restricted Subsidiary;

provided, however, that any such Restricted Subsidiary described in clause (2) or (3) is primarily engaged in the Oil and Gas Business.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; provided that beneficial ownership of 10% or more of the Voting Stock of a Person will be deemed to be control. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

“Agent” means each of the First Lien Collateral Agent and the Collateral Agent.

(1) the sale, lease, conveyance or other disposition of any properties or assets (including by way of a Production Payment or sale and leaseback transaction); provided that the sale, lease, conveyance or other disposition of all or substantially all of the properties or assets of the Company and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the Indenture described above under the caption “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant; and

(2) the issuance of Equity Interests in any of the Company’s Restricted Subsidiaries or the sale of Equity Interests in any of its Restricted Subsidiaries.

Notwithstanding the preceding, the following items will not be deemed to be Asset Sales:

(1) any single transaction or series of related transactions that involves properties or assets having a fair market value of less than $2.0 million;

(2) a transfer of assets between or among any of the Company and its Restricted Subsidiaries,

Index to Financial Statements

(3) an issuance or sale of Equity Interests by a Restricted Subsidiary to the Company or to another Restricted Subsidiary;

(4) the sale, lease or other disposition of hydrocarbons, equipment, inventory, accounts receivable or other properties or assets in the ordinary course of business, including, without limitation, any abandonment, farm-in, farm-out, lease or sublease of any oil and gas properties or the forfeiture or other disposition of such properties pursuant to standard form operating agreements, in each case in the ordinary course of business in a manner customary in the Oil and Gas Business;

(6) a Restricted Payment that is permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments” or a Permitted Investment;

(7) any trade or exchange by the Company or any Restricted Subsidiary of oil and gas properties or other properties or assets for oil and gas properties or other properties or assets owned or held by another Person, provided that the fair market value of the properties or assets traded or exchanged by the Company or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the fair market value of the properties or assets (together with any cash) to be received by the Company or such Restricted Subsidiary, and provided further that any net cash received must be applied in accordance with the provisions described above under the caption “—Repurchase at the Option of Holders—Asset Sales;”

(8) the creation or perfection of a Lien (but not the sale or other disposition of the properties or assets subject to such Lien) in accordance with the limitations set forth in the Indenture; and

(9) surrender or waiver of contract rights or the settlement, release or surrender of contract, tort or other claims of any kind.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

(2) with respect to a partnership, the board of directors of the general partner of the partnership; and

(3) with respect to any other Person, the board or committee of such Person serving a similar function.

“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the applicable Person to have been duly adopted by the Board of Directors of such Person and to be in full force and effect on the date of such certification, and delivered to the trustee.

“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York are authorized or required by law to close.

Index to Financial Statements

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty.

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person,

but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.

(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than six months from the date of acquisition;

(3) certificates of deposit and eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any lender party to the Senior Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of “B” or better;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

(5) commercial paper having the highest rating obtainable from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and in each case maturing within six months after the date of acquisition; and

(6) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition.

(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets (including Capital Stock) of the Company and its Subsidiaries taken as a whole to any “person” (as that term is used in Section 13(d)(3) of the Exchange Act) other than one or more Permitted Holders;

(2) the adoption of a plan relating to the liquidation or dissolution of the Company;

Index to Financial Statements

(3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” or “group” (as that term is used in Section 13(d)(3) of the Exchange Act), other than one or more Permitted Holders, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Company, measured by voting power rather than number of shares, units or the like, other than, with respect to a merger or consolidation, a transaction in which the Voting Stock of the Company outstanding immediately prior to such transaction is converted into or exchanged for Voting Stock (other than Disqualified Stock) of the surviving or transferee Person (or any parent thereof) constituting a majority of the outstanding shares, units or the like of such Voting Stock of such surviving or transferee Person (or any parent thereof) immediately after giving effect to such transaction;

(4) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors; or

(5) the first day on which John Hoffman, the chief executive officer of the Company as of the Issue Date, is no longer a manager of the Company for any reason other than (i) John Hoffman’s death or his “Disability” as defined in his employment agreement with the Company as in effect on the Issue Date or (ii) his termination for “cause” pursuant to the terms of such employment agreement as in effect on the Issue Date.

Notwithstanding the preceding, a conversion (whether by merger, statutory conversion or otherwise) of the Company from a limited liability company to a corporation, or an exchange of all of the outstanding memberships interests in the Company for Capital Stock in a corporation, shall not constitute a Change of Control, so long as following such merger, conversion or exchange the “persons” (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Voting Stock of the Company immediately prior to such transaction continue to Beneficially Own in the aggregate sufficient Voting Stock of such successor corporation to elect a majority of its directors.

“Collateral Agent” means the party named as the collateral agent for the Second Lien Secured Parties in the Indenture until a successor replaces it in accordance with the provisions of the Indenture and thereafter means any such successor.

“Collateral Agreements” means, collectively, the Intercreditor Agreement, each security agreement or other collateral agreement, and each other document or instrument creating Liens in favor of the Collateral Agent as required by the Indenture, in each case, as the same may be in force from time to time.

“Consolidated Coverage Ratio” means as of any date of determination, the ratio of (x) the aggregate amount of Consolidated EBITDAX of the Company for the period of the most recent four full consecutive fiscal quarters ending prior to the date of such determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters, provided, however, that:

(a) has incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an incurrence of Indebtedness, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to the incurrence of such Indebtedness and the use of proceeds thereof as if such Indebtedness had been incurred on the first day of such period and such proceeds had been applied as of such date (except that in making such computation, the amount of Indebtedness under any revolving credit facility outstanding on the date of such calculation will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such facility was outstanding or (ii) if such

Index to Financial Statements

revolving credit facility Indebtedness was incurred after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of incurrence of such revolving credit facility Indebtedness to the date of such calculation, in each case, provided that such average daily balance shall take into account any repayment of Indebtedness under such revolving credit facility as provided in clause (b)); or

(b) has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period, including with the proceeds of such new Indebtedness, that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case other than Indebtedness incurred under any revolving credit facility unless such Indebtedness has been permanently repaid and the related commitment terminated), Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness as if such discharge had occurred on the first day of such period;

(2) if, since the beginning of such period, the Company or any Restricted Subsidiary has made any Asset Sale or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Sale, the Consolidated EBITDAX for such period will be reduced by an amount equal to the Consolidated EBITDAX (if positive) directly attributable to the assets which are the subject of such Asset Sale for such period or increased by an amount equal to the Consolidated EBITDAX (if negative) directly attributable thereto for such period and Consolidated Interest Expense for such period shall be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with or with the proceeds from such Asset Sale for such period (or, if the Capital Stock of any Restricted Subsidiary is sold or otherwise disposed of, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

(3) if, since the beginning of such period, the Company or any Restricted Subsidiary (by merger or otherwise) has made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company or a Restricted Subsidiary) or an acquisition (or will have received a contribution) of assets, including any acquisition or contribution of assets occurring in connection with a transaction causing a calculation to be made under the Indenture, which constitutes all or substantially all of a company, division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the incurrence of any Indebtedness) as if such investment or acquisition or contribution had occurred on the first day of such period; and

(4) if, since the beginning of such period, any Person (that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period) made any Asset Sale or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Sale or Investment or acquisition of assets had occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of the Company; provided that such officer may in his or her discretion include any reasonably identifiable and factually supportable pro forma changes to Consolidated EBITDAX, including any pro forma expenses and cost reductions, that have occurred or in the judgment of such officer are reasonably expected to occur within 12 months of the date of the applicable transaction to the extent that such expense or cost reduction

Index to Financial Statements

or any other operating improvements could then be reflected properly in pro forma financial statements prepared in accordance with Regulation S-X under the Securities Act or any other regulation or policy of the SEC. If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the date of determination had been the applicable rate for the entire period (taking into account any interest rate Hedging Obligation applicable to such Indebtedness, but if the remaining term of such interest rate Hedging Obligation is less than 12 months, then such interest rate Hedging Obligation shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company, the interest rate shall be calculated by applying such optional rate chosen by the Company. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Company may designate.

“Consolidated EBITDAX” for any period means, without duplication, the Consolidated Net Income for such period, plus the following, without duplication and to the extent deducted (and not added back) in calculating such Consolidated Net Income:

(3) consolidated depletion and depreciation expense of the Company and its Restricted Subsidiaries;

(4) consolidated amortization expense or impairment charges of the Company and its Restricted Subsidiaries recorded in connection with the application of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 350, Intangibles-Goodwill and Other (formerly Statement of Financial Accounting Standard No. 142, “Goodwill and Other Intangibles” and Statement of Financial Accounting Standard No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets”);

(5) accretion of asset retirement obligations and other non-cash charges of the Company and its Restricted Subsidiaries (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation);

(6) so long as the Company uses successful efforts or a similar method of accounting for its oil and gas properties, consolidated exploration expense of the Company and its Restricted Subsidiaries; and

if applicable for such period; and less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto that were deducted (and not added back) in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments, (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments and (z) other non-cash gains (excluding any non-cash gain to the extent it represents the reversal of an accrual or reserve for a potential cash item that reduced Consolidated EBITDAX in any prior period).

Notwithstanding the preceding sentence, clauses (2) through (6) relating to amounts of a Restricted Subsidiary that is not a Guarantor will be added to Consolidated Net Income to compute Consolidated EBITDAX of the Company only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of the Company and, to the extent the amounts set forth in clauses (2) through (6) are in excess of those necessary to offset a net loss of such Restricted Subsidiary or if such Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a corresponding amount would be permitted at the date of determination to be dividended or distributed to the Company by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or the holders of its Capital Stock.

Index to Financial Statements

“Consolidated Income Tax Expense” means, with respect to any period, the provision for federal, state, local and foreign taxes (including state franchise taxes) based on income of the Company and its Restrict Subsidiaries for such period as determined in accordance with GAAP, or (for any period in which the Company is a partnership or limited liability company) the Tax Amount for such period.

“Consolidated Interest Expense” means, for any period, the total consolidated interest expense of the Company and its Restricted Subsidiaries, determined on a consolidated basis in accordance with GAAP, plus, to the extent not included in such interest expense and without duplication:

(1) interest expense for such period attributable to Capital Lease Obligations and the interest component of any deferred payment obligations;

(2) amortization of debt discount and debt issuance cost (provided that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense);

(4) commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing;

(5) the interest expense on Indebtedness of another Person that is guaranteed by the Company or one of its Restricted Subsidiaries or secured by a lien on assets of the Company or one of its Restricted Subsidiaries, to the extent such guarantee becomes payable or such lien becomes subject to foreclosure;

(6) costs associated with interest rate Hedging Obligations (including amortization of fees); provided, however, that if such interest rate Hedging Obligations result in net benefits rather than costs, such benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;

(7) the consolidated interest expense of the Company and its Restricted Subsidiaries that was capitalized during such period; and

(8) all dividends paid or payable in cash, Cash Equivalents or Indebtedness or dividends accrued during such period on any series of Disqualified Stock of the Company or on preferred stock of its Restricted Subsidiaries payable to a party other than the Company or a wholly owned Subsidiary;

minus, to the extent included above, write-off of deferred financing costs (and interest) attributable to Dollar-Denominated Production Payments.

“Consolidated Leverage” means, as of the date of determination, the Company’s long term debt reported on the Company’s audited consolidated balance sheet as of the last day of the previous fiscal year prepared in accordance with GAAP minus the Company’s cash and cash equivalents on such date.

“Consolidated Net Income” means, for any period, the aggregate net income (loss) of the Company and its consolidated Subsidiaries determined in accordance with GAAP and before any reduction in respect of preferred stock dividends of such Person, less (for any period the Company is a partnership or limited liability company) the Tax Amount for such period; provided, however, that there will not be included (to the extent otherwise included therein) in such Consolidated Net Income:

(1) any net income (loss) of any Person (other than the Company) if such Person is not a Restricted Subsidiary, except that:

(a) subject to the limitations contained in clauses (3) and (4) below, the Company’s equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (2) below); and

Index to Financial Statements

(b) the Company’s equity in a net loss of any such Person for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary during such period;

(2) any net income (but not loss) of any Restricted Subsidiary if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution paid to another Restricted Subsidiary, to the limitation contained in this clause); and

(b) the Company’s equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(3) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its consolidated Subsidiaries which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

(4) any extraordinary or nonrecurring gains or losses or nonrecurring other income or expenses, together with any related provision for taxes (and, without duplication, any Permitted Tax Distributions) on such gains or losses or other income or expenses and all related fees and expenses;

(6) any asset impairment write-downs on oil and gas properties under GAAP or SEC guidelines;

(7) any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 815);

(8) income or loss attributable to discontinued operations (including, without limitation, operations disposed of during such period whether or not such operations were classified as discontinued);

(9) all deferred financing costs written off, and premiums paid, in connection with any early extinguishment of Indebtedness;

(10) any depreciation, depletion and amortization expense in excess of capital expenditures; and

(11) any non-cash compensation charge arising from any grant of stock, stock options or other equity based awards; provided that the proceeds resulting from any such grant will be excluded from clause (3)(b) of the first paragraph of the covenant described under “—Limitations on Restricted Payments.”

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Company, as applicable, who:

(2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election.

“Credit Facilities” means one or more first-priority secured debt facilities (including, without limitation, the Senior Credit Agreement), commercial paper facilities or capital markets financings, in each case with banks or other institutional lenders or institutional investors providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to

Index to Financial Statements

borrow from (or sell receivables to) such lenders against such receivables), letters of credit or capital markets financings, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced (including by means of sales of debt securities) in whole or in part from time to time.

“Debt Documents” means, collectively, the First Lien Debt Documents and the Second Lien Debt Documents.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require the Company to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that the Company may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Certain Covenants—Restricted Payments.”

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary of the Company that was formed under the laws of the United States or any state of the United States or the District of Columbia or that guarantees or otherwise provides direct credit support for any Indebtedness of the Company.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means any public or private sale of Capital Stock (other than Disqualified Stock) made for cash on a primary basis by the Company after the date of the Indenture.

“Excess Cash Flow” means, with respect to the Company and its Restricted Subsidiaries for any period, Consolidated EBITDAX; minus, Consolidated Interest Expense; minus, Tax Amount; minus, aggregate capital expenditures (including all cash payments in respect of acquisitions of the Capital Stock, property or long-term assets of any other Person); minus, changes in Net Working Capital; minus, net cash contributions, deposits, payments or charges (including contributions, deposits, payments or charges in respect of performance, surety and similar bonds and with respect to letters of credit in support thereof) in respect of the Company’s plugging and abandonment obligations arising from, or related to, the Oil and Gas Business; minus, the aggregate payment, repayment, redemption, defeasance or other retirement for value by the Company of any Indebtedness.

“Excess Cash Flow Offer Amount” means, with respect to any period (A) 50% of Excess Cash Flow for such period minus (B) $2.5 million.

“Exchange Notes” means the notes (including any additional notes) issued in a Registered Exchange Offer pursuant to the Indenture.

“Existing Indebtedness” means the aggregate principal amount of Indebtedness of the Company and its Restricted Subsidiaries in existence on the date of the Indenture, until such amounts are repaid.

Index to Financial Statements

The term “fair market value” means, with respect to any asset or property, the sale value that would be obtained in an arm’s-length free market transaction between an informed and willing seller under no compulsion to sell and an informed and willing buyer under no compulsion to buy. Except as otherwise provided in the Indenture, the fair market value of an asset or property in excess of $10.0 million shall be determined by an independent accounting, appraisal or investment banking firm of recognized standing, and any lesser fair market value may be determined by an officer of the Company acting in good faith.

“First Lien Collateral Agent” means the collateral agent for the First Lien Secured Parties named in any First Lien Debt Document and any successor or replacement collateral agent designated as such by the holders of First Lien Obligations.

“First Lien Debt Documents” means, collectively, agreements, instruments and other documents evidencing, governing or providing any Lien for the benefit of any First Lien Obligations.

“First Lien Secured Creditor” means the holders of the First Lien Obligations.

“First Lien Secured Parties” means the holders of the First Lien Obligations and the First Lien Collateral Agent.

“First Priority Liens” means any Permitted Lien securing First Lien Obligations.

“Foreign Subsidiary” means any Restricted Subsidiary of the Company that is not a Domestic Subsidiary.

The term “freely tradable” means a Transfer Restricted Security shall be deemed to be “freely tradable” at any time of determination if at such time of determination (i) it may be sold to the public pursuant to Rule 144A under the Securities Act by a person that is not an “affiliate” (as defined in Rule 144 under the Securities Act) of the Company without regard to any of the conditions specified therein (other than the holding period requirement in paragraph (d) of Rule 144 so long as such holding period requirement is satisfied at such time of determination) and (ii) it does not bear any restrictive legends relating to the Securities Act.

“GAAP” means generally accepted accounting principles in the United States, which are in effect from time to time.

The term “guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness. When used as a verb, “guarantee” has a correlative meaning.

“Guarantee” means any guarantee by a Guarantor of the Issuers’ payment Obligations under the Indenture and on the notes.

“Guarantors” means each Restricted Subsidiary of the Company that executes the Indenture as an initial Guarantor or that becomes a Guarantor in accordance with the provisions of the Indenture, and their respective successors and assigns.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person incurred in the normal course of business and not for speculative purposes under:

(1) interest rate swap agreements, interest rate cap agreements and interest rate collar agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in interest rates with respect to Indebtedness incurred and not for purposes of speculation;

Index to Financial Statements

(2) foreign exchange contracts and currency protection agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in currency exchanges rates with respect to Indebtedness incurred and not for purposes of speculation;

(3) any commodity futures contract, commodity option or other similar agreement or arrangement designed to protect against fluctuations in the price of oil, natural gas or other commodities used, produced, processed or sold by that Person or any of its Restricted Subsidiaries at the time; and

(4) other agreements or arrangements designed to protect such Person or any of its Restricted Subsidiaries against fluctuations in interest rates, commodity prices or currency exchange rates.

“Indebtedness” means, with respect to any specified Person (excluding accrued expenses and trade payables), without duplication,

(a) the principal of and premium, if any, in respect of outstanding (A) Indebtedness of such Person for money borrowed and (B) Indebtedness evidenced by notes, debentures, bonds or other similar instruments for the payment of which such Person is responsible or liable;

(b) all Capital Lease Obligations of such Person and all Attributable Debt in respect of sale and leaseback transactions entered into by such Person;

(c) the deferred purchase price of property, which purchase price is due more than six months after the date of taking delivery of title to such property, including all obligations of such Person for the deferred purchase price of property under any title retention agreement, but excluding accrued expenses and trade accounts payable arising in the ordinary course of business; and

(d) the reimbursement obligation of any obligor for the principal amount of any letter of credit, banker’s acceptance or similar transaction (excluding obligations with respect to letters of credit securing obligations (other than obligations described in clauses (a) through (c) above) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no later than the tenth Business Day following receipt by such Person of a demand for reimbursement following payment on the letter of credit);

(2) all net obligations in respect of Hedging Obligations except to the extent such net obligations are otherwise included in this definition;

(3) all liabilities of others of the kind described in the preceding clause (1) or (2) that such Person has Guaranteed or that are otherwise its legal liability;

(4) with respect to any Production Payment, any warranties or guaranties of production or payment by such Person with respect to such Production Payment but excluding other contractual obligations of such Person with respect to such Production Payment;

(5) Indebtedness (as otherwise defined in this definition) of another Person secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person, the amount of such obligations being deemed to be the lesser of

(b) the fair market value of such asset as determined in good faith by such specified Person;

(6) Disqualified Stock of such Person or a Restricted Subsidiary in an amount equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

Index to Financial Statements

(7) the aggregate preference in respect of amounts payable on the issued and outstanding preferred stock of any of the Company’s Restricted Subsidiaries that are not Guarantors in the event of any voluntary or involuntary liquidation, dissolution or winding up (excluding any such preference attributable to such preferred stock that is owned by such Person or any of its Restricted Subsidiaries; provided, that if such Person is the Company, such exclusion shall be for such preference attributable to such preferred stock that is owned by the Company or any of its Restricted Subsidiaries); and

(8) any and all deferrals, renewals, extensions, refinancings and refundings (whether direct or indirect) of, or amendments, modifications or supplements to, any liability of the kind described in any of the preceding clauses (1), (2), (3), (4), (5), (6), (7) or this clause (8), whether or not between or among the same parties;

if and to the extent any of the preceding items (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and, to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person. Subject to clause (4) of the preceding sentence, Production Payments shall not be deemed to be Indebtedness.

“Indenture Documents” means, collectively, the Indenture, the applicable Registration Rights Agreement, the notes, the Guarantees and the Collateral Agreements.

“Intercreditor Agreement” means the intercreditor agreement that is entered into at the closing of the offering of the notes, among the trustee, the First Lien Collateral Agent and the Issuers, as the same may be amended, supplemented, restated or modified from time to time.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of the Company, the Company will be deemed to have made an Investment on the date of any such sale or disposition in an amount equal to the fair market value of the Equity Interests of such Restricted Subsidiary not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The acquisition by the Company or any Subsidiary of the Company of a Person that holds an Investment in a third Person will not be deemed to be an Investment by the Company or such Subsidiary in such third Person unless such Investment in such third Person was contemplated by the Company or such Subsidiary and not incidental to the acquisition of such Person.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement not intended as a security agreement.

Index to Financial Statements

“Merit Acquisition” means that certain acquisition of interests in various oil and gas properties in the U.S. Gulf of Mexico pursuant to that certain definitive agreement dated as of March 17, 2011, by and among the Company and the sellers party thereto, for an aggregate purchase price of approximately $39 million in cash plus the assumption of $168.4 million of asset retirement obligations, subject to customary adjustments for a transaction of that type.

“Net Proceeds” means the aggregate cash proceeds received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of, without duplication:

(1) the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, sales commissions, title and recording tax expenses, and any relocation expenses incurred as a result of the Asset Sale,

(2) taxes paid or payable as a result of the Asset Sale (including Permitted Tax Distributions), in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements,

(3) amounts required to be applied to the repayment of Indebtedness secured by a Lien on the properties or assets that were the subject of such Asset Sale,

(4) all payments made on any Hedging Obligation or other Indebtedness which is secured by any assets subject to such Asset Sale, in accordance with the terms of any Permitted Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Sale, or by applicable law be repaid out of the proceeds from such Asset Sale; and

(5) any reserve for adjustment in respect of the sale price of such properties or assets established in accordance with GAAP.

(2) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness;

(1) as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) is the lender;

(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness (other than the notes) of the Company or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity; and

(3) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of the Company or any of its Restricted Subsidiaries.

“Obligations” means any principal, premium, if any, interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization, whether or not a claim for post-filing interest is allowed in such proceeding), penalties, fees, charges, expenses, indemnifications, reimbursement obligations, damages, guarantees, and other liabilities or amounts payable under the documentation governing any Indebtedness or in respect thereto.

Index to Financial Statements

(1) the acquisition, exploration, development, operation and disposition of interests in oil, natural gas and other hydrocarbon properties;

(2) the gathering, marketing, treating, processing (but not refining), storage, selling and transporting of any production from those interests, including any hedging activities related thereto; and

(3) any activity necessary, appropriate, incidental or reasonably related to the activities described above.

“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business, including through agreements, transactions, interests or arrangements that permit one to share risk or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including without limitation:

(1) direct or indirect ownership of crude oil, natural gas, other related hydrocarbon and mineral properties or any interest therein or gathering, transportation, processing, storage or related systems; and

(2) the entry into operating agreements, joint ventures, processing agreements, working interests, royalty interests, mineral leases, farm-in agreements, farm-out agreements, development agreements, production sharing agreements, area of mutual interest agreements, contracts for the sale, transportation or exchange of crude oil and natural gas and related hydrocarbons and minerals, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, partnership agreements (whether general or limited), or other similar or customary agreements, transactions, properties, interests or arrangements and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding, however, Investments in corporations and publicly-traded limited partnerships.

“Permitted Holders” means any Beneficial Owner of Capital Stock of the Company on the Issue Date.

(3) any Investment by the Company or any Restricted Subsidiary of the Company in a Person, if as a result of such Investment:

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its properties or assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company;

(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales;”

(5) any Investment in any Person solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Company;

(6) any Investments received in compromise of obligations of trade creditors or customers that were incurred in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer;

Index to Financial Statements

(7) Hedging Obligations permitted to be incurred under the “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant;

(9) any repurchases of notes permitted pursuant to the terms of the Indenture, including open market purchases of the notes; and

(10) other Investments in any Person having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (10) that are at the time outstanding, not to exceed $5.0 million.

(1) Liens on any property or assets securing Indebtedness and other obligations under Credit Facilities permitted under the Indenture;

(3) Liens on any property or assets of a Person existing at the time such Person is merged with or into or consolidated with the Company or any Restricted Subsidiary of the Company, provided that such Liens were in existence prior to the contemplation of such merger or consolidation and do not extend to any property or assets other than those of the Person merged into or consolidated with the Company or the Restricted Subsidiary;

(4) Liens on any property or assets existing at the time of acquisition thereof by the Company or any Restricted Subsidiary of the Company, provided that such Liens were not incurred in connection with the contemplation of such acquisition;

(5) Liens to secure the performance of statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business;

(7) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(8) Liens securing Permitted Refinancing Indebtedness incurred to refinance Indebtedness that was previously so secured, provided that any such Lien is limited to all or part of the same property or assets (plus improvements, replacements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property that is the security for a Permitted Lien under the Indenture;

(9) Liens securing Hedging Obligations of the Company or any of its Restricted Subsidiaries;

(10) Liens securing Indebtedness incurred in connection with the acquisition by the Company or any Restricted Subsidiary of assets used in the Oil and Gas Business (including the office buildings and other real property used by the Company or such Restricted Subsidiary in conducting its operations); provided that (i) such Liens attach only to the assets acquired with the proceeds of such Indebtedness; (ii) such Indebtedness is not in excess of the purchase price of such fixed assets; and (iii) such Indebtedness is permitted to be incurred under the “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant;

(11) any Lien incurred in the ordinary course of business incidental to the conduct of the business of the Company or the Restricted Subsidiaries or the ownership of their property (including (a) easements, rights of way and similar encumbrances, (b) rights or title of lessors under leases (other than Capital Lease Obligations), (c) rights of collecting banks having rights of setoff, revocation, refund or chargeback with respect to money or instruments of the Company or the Restricted Subsidiaries on deposit with or in the

Index to Financial Statements

possession of such banks, (d) Liens imposed by law, including Liens under workers’ compensation or similar legislation and mechanics,’ carriers,’ warehousemen’s, materialmen’s, suppliers’ and vendors’ Liens, and (e) Liens incurred to secure performance of obligations with respect to statutory or regulatory requirements, performance or return-of-money bonds, surety bonds or other obligations of a like nature and incurred in a manner consistent with industry practice;

(12) Liens for taxes, assessments and governmental charges not yet due or the validity of which are being contested in good faith by appropriate proceedings, promptly instituted and diligently conducted, and for which adequate reserves have been established to the extent required by GAAP as in effect at such time;

(13) Liens created for the benefit of (or to secure) Second Lien Obligations in respect of notes issued on the Issue Date in an aggregate principal amount not to exceed $150.0 million; and

(14) Liens incurred with respect to obligations that do not exceed $2.0 million at any one time outstanding.

“Permitted Refinancing Indebtedness” means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:

(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded (plus all accrued interest on the Indebtedness and the amount of all expenses and premiums incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness has a final maturity date no earlier than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(3) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the notes or the Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to the notes or the Guarantees on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and

(4) such Indebtedness is not incurred by a Restricted Subsidiary of the Company if the Company is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; provided, however, that a Restricted Subsidiary that is also a Guarantor may guarantee Permitted Refinancing Indebtedness incurred by the Company, whether or not such Restricted Subsidiary was an obligor or guarantor of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

“Permitted Tax Distributions” means (i) for any calendar year or portion thereof of the Company during which it is a pass-through entity for U.S. federal income tax purposes, payments and distributions to the members of the Company on each estimated payment date as well as each other applicable due date to enable the members of the Company (or, if any of them are themselves a pass-through entity for U.S. federal income tax purposes, their shareholders, members or partners) to make payments of U.S. federal and state income taxes (including estimates thereof) as a result of the operations of the Company and its Subsidiaries during the current and any previous calendar year, not to exceed an amount equal to the amount of each such member’s (or, in the case of a pass-through entity, its shareholders,’ members’ or partners’) U.S. federal and state income tax liability resulting solely from the pass-through tax treatment of such member’s interest in the Company and as calculated pursuant to the operating agreement of the Company as in effect on the Issue Date and as it may be amended from time to time thereafter in a manner that is not adverse to the holders of the notes and (ii) payments and distributions to Black Elk Management LLC sufficient to permit its members to discharge their 2010 United States federal income tax liabilities in respect of the receipt by Black Elk Management LLC of Class B Units pursuant to

Index to Financial Statements

Paragraph 24 of the First Amended and Restated Operating Agreement of the Company and the receipt by Black Elk Management LLC of any amounts described in this clause (ii); provided, however, that all payments and distributions pursuant to this clause (ii) shall not exceed $1.3 million in the aggregate.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Production Payments” means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments.

“Registered Exchange Offer” has the meaning set forth for such term in the applicable Registration Rights Agreement.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

“Sarbanes-Oxley Act of 2002” means the Public Company Accounting Reform and Investor Protection Act and the rules and regulations promulgated thereunder.

“Second Lien Debt Documents” means, collectively, the Indenture Documents and corresponding documents relating to other Second Lien Obligations.

“Second Lien Secured Creditor” means the holders of the Second Lien Obligations.

“Second Lien Secured Parties” means the holders of the Second Lien Obligations, the trustee, the Agent for any Second Lien Obligations and the Collateral Agent.

“SEC PV-10” means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Commission. Such amount shall be determined by either Netherland, Sewell & Associates, Inc., Ryder Scott Company, L.P., or DeGolyer and MacNaughton.

“Secured Parties” means, collectively, the First Lien Secured Parties and the Second Lien Secured Parties.

“Senior Credit Agreement” means the Amended and Restated Credit Agreement by and among the Company, the guarantors party thereto, the lenders party thereto, and PPVA Black Elk (Cayman) Ltd., as agent, dated as of July 13, 2009, including any related notes, guarantees, collateral documents, instruments and agreements executed in connection therewith, and in each case as amended, restated, modified, renewed, refunded, replaced or refinanced from time to time, including with different lenders or in differing amounts of Indebtedness to the extent permitted under the Indenture.

“Senior Debt” means all Indebtedness of the Company or any of its Restricted Subsidiaries permitted to be incurred under the terms of the Indenture, including the notes, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the notes or any Guarantee, and all Obligations with respect to the foregoing.

“Sponsor Preferred Stock” means those shares of preferred stock with an aggregate liquidation preference of $30 million, issued by the Company to PPVA, and including any additional shares of preferred stock issued by way of a dividend; such shares shall accrue dividends payable in kind at a rate per annum of 24%.

Index to Financial Statements

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

(1) any corporation, association or other business entity of which more than 50% of the total voting power of Voting Stock is at the time owned or controlled, directly or through another Subsidiary, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof).

“Tax Amount” means, for any period, the combined federal, state and local income taxes, including estimated taxes, that would be payable by the Company if it were a Texas corporation filing separate tax returns with respect to its Taxable Income for such period; provided that in determining the Tax Amount, the effect thereon of any net operating loss carry-forwards or other carry-forwards or tax attributes, such as alternative minimum tax carry-forwards, that would have arisen if the Company were a Texas corporation shall be taken into account; provided, further, that, if there is an adjustment in the amount of the Taxable Income for any period, an appropriate positive or negative adjustment shall be made in the Tax Amount, and if the Tax Amount is negative, then the Tax Amount for succeeding periods shall be reduced to take into account such negative amount until such negative amount is reduced to zero. Notwithstanding anything to the contrary, Tax Amount shall not include taxes resulting from the Company’s reorganization as, or change in the status to, a corporation for tax purposes.

“Taxable Income” means, for any period, the taxable income or loss of the Company for such period for U.S. federal income tax purposes.

“Transfer Restricted Securities” means the notes; provided, however, that a note, shall cease to be a Transfer Restricted Security upon the earliest to occur of the following: (i) in certain circumstances, the note has been exchanged for an Exchange Note (as such term is defined in the Registration Rights Agreement) in an Exchange Offer (as such term is defined in the Registration Rights Agreement); (ii) in certain circumstances, a Shelf Registration Statement (as such term is defined in the Registration Rights Agreement) registering such note under the Securities Act has been declared or becomes effective and such note has been sold or otherwise transferred by the holder thereof pursuant to and in a manner contemplated by such effective Shelf Registration Statement; (iii) such note is actually sold by the holder thereof pursuant to Rule 144 under the Securities Act, as amended, under circumstances in which any legend borne by such note relating to restrictions on transferability thereof, under the Securities Act or otherwise, is removed by the Company or pursuant to the Indenture; or (iv) such note shall cease to be outstanding.

“Unrestricted Subsidiary” means any Subsidiary of the Company that is designated by the Board of Directors as an Unrestricted Subsidiary pursuant to a Board Resolution, but only to the extent that such Subsidiary:

(2) is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary of the Company unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company;

(3) is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

Index to Financial Statements

(4) does not guarantee or otherwise directly or indirectly provide credit support for any Indebtedness of the Company or any of its Restricted Subsidiaries.

Any designation of a Subsidiary of the Company as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee the Board Resolution giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of the Company as of such date and, if such Indebtedness is not permitted to be incurred, and any Lien of such Subsidiary will be deemed to be incurred as of such date under the covenant, or such Lien is not permitted to be incurred as of such date under the covenant described under the caption “Liens,” then in, in either case, described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” the Company will be in default of such covenant.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all related undertakings and obligations.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors of such Person.

“W&T Escrow Accounts” means the escrow accounts established pursuant to the terms of the W&T Purchase and Sale Agreement and subject to a first priority Lien in favor of W&T in accordance with the terms of the W&T Purchase and Sale Agreement.

“W&T Properties” means those certain properties of the Company purchased from W&T pursuant to the W&T Purchase and Sale Agreement.

“W&T Purchase and Sale Agreement” means that certain Agreement for Purchase and Sale dated effective August 1, 2009, by and between W&T, as “Seller” and the Company, as “Buyer.”

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

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The new notes, like substantially all the old notes, will be issued in the form of one or more fully registered notes in global form, without interest coupons (the “Global Notes”). Each Global Note will be deposited with the Trustee as custodian for DTC, in New York, New York, and registered in the name of DTC or its nominee, in each case, for credit to an account of a direct or indirect participant in DTC as described below.

Ownership of beneficial interests in each Global Note will be limited to persons who have accounts with DTC (“DTC participants”) or persons who hold interests through DTC participants. We expect that under procedures established by DTC:

Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for definitive notes in registered certificated form (“Certificated Notes”) except in the limited circumstances described below. See “— Exchange of Global Notes for Certificated Notes.” Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of notes in certificated form.

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between the Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

Except as described below, owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or “holders” thereof under the Indenture for any purpose.

Payments in respect of the principal of, and interest, premium on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the Indenture. Under the terms of the Indenture, we and the Trustee will treat the persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes.

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Consequently, neither we, the Trustee, the exchange agent nor any agent of ours, the Trustee, or the exchange agent has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee, the exchange agent or us. Neither we nor the Trustee nor the exchange agent will be liable for any delay by DTC or any of the Participants or the Indirect Participants in identifying the beneficial owners of the notes, and we, the Trustee and the exchange agent may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Subject to the transfer restrictions under applicable securities laws and the legends on the Global Notes, transfers between the Participants will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Subject to compliance with the transfer restrictions applicable to the notes described herein, cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for legended notes in certificated form, and to distribute such notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. None of us, the Trustee and any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

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(1) DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and, in either case, we fail to appoint a successor depositary;

(2) we, at our option, but subject to DTC’s rules, notify the Trustee in writing that we elect to cause the issuance of the Certificated Notes; or

(3) there has occurred and is continuing a Default or Event of Default with respect to the notes, and DTC has requested the exchange of such Global Notes for Certificated Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the Indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

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The following discussion is a summary of certain U.S. federal income tax considerations relevant to the exchange of old notes for new notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of notes. Some holders, including financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, U.S. persons whose functional currency is not the U.S. dollar, or persons who hold the notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction may be subject to special rules not discussed below.

We recommend that each holder consult its own tax advisor as to the particular tax consequences of exchanging such holder’s old notes for new notes, including the applicability and effect of any foreign, state, local or other tax laws or estate or gift tax considerations.

The exchange of old notes for new notes will not be an exchange or otherwise a taxable event to a holder for U.S. federal income tax purposes. Accordingly, a holder will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange, and the holder will have the same basis and holding period in the new note as it had in the corresponding old note immediately before the exchange.

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You may transfer new notes issued under the Exchange Offer in exchange for the old notes if:

Each broker-dealer that receives new notes for its own account pursuant to the Exchange Offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities.

If you wish to exchange new notes for your old notes in the Exchange Offer, you will be required to make representations to us as described in “Exchange Offer—Purpose and Effect of the Exchange Offer” and “—Procedures for Tendering—Your Representations to Us” in this Prospectus and in the letter of transmittal. In addition, if you are a broker-dealer who receives new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale by you of such new notes.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the Exchange Offer may be sold from time to time on one or more transactions in any of the following ways:

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes.

Any broker-dealer that resells new notes that were received by it for its own account pursuant to the Exchange Offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities may be deemed to be an “underwriter” within the meaning of the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. We agreed to permit the use of this Prospectus for a period of up to 180 days after the completion of the Exchange Offer by such broker-dealers to satisfy this Prospectus delivery requirement. Furthermore, we agreed to use our best efforts to amend or supplement this Prospectus during such period if so requested in order to expedite or facilitate the disposition of any new notes by broker-dealers.

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We have agreed to pay all expenses incident to the Exchange Offer other than transfer taxes, if any, and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

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The validity of the new notes being offered hereby and certain other legal matters will be passed upon by Vinson & Elkins L.L.P., Houston, Texas.

The consolidated financial statements of Black Elk Energy Offshore Operations, LLC and its subsidiaries as of December 31, 2010 and 2009, and for the years ended December 31, 2010 and 2009 and for the period from inception (January 29, 2008) through December 31, 2008 included in this Prospectus have been audited by UHY LLP, an independent registered public accounting firm, as set forth in their report appearing herein, in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses of Merit Energy Company’s oil and gas properties under contract for purchase by Black Elk Energy Offshore Operations, LLC for each of the years in the three-year period ended December 31, 2010, have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The statements of combined revenues and direct operating expenses of the oil and gas properties purchased by Black Elk Energy Offshore Operations, LLC from W&T Offshore, Inc. for the ten-month period ended October 31, 2009 and the year ended December 31, 2008, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The statements of combined revenues and direct operating expenses of the oil and gas properties purchased by Black Elk Energy Offshore Operations, LLC from Nippon Oil Exploration U.S.A. Limited for the nine-month period ended September 30, 2010 and the years ended December 31, 2009 and 2008, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The information included in this Prospectus regarding estimated quantities of proved reserves applicable to our oil and natural gas properties as of December 31, 2010 were prepared or derived from estimates prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, based on guidelines established by the SEC. The estimates applicable to our properties are included in this Prospectus in reliance on the authority of such firm as experts in these matters.

We have filed with the SEC a registration statement on Form S-4 with respect to the new notes being offered by this Prospectus. This Prospectus does not contain all of the information found in the registration statement. For further information regarding us and the new notes offered by this Prospectus, please review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be

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inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of this material can also be obtained from the public reference section of the SEC at prescribed rates, or accessed at the SEC’s website at www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room.

The SEC’s proxy rules and regulations do not, nor do the rules of any stock exchange, require us to send an annual report to security holders or to holders of American depository receipts. Upon the effectiveness of this registration statement, we will become subject to the Exchange Act’s period reporting requirements, including the requirement to file current, annual, and quarterly reports with the SEC. The annual reports we file will contain financial information that has been examined and reported on, with an opinion by an impendent certified public accounting firm.

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We have included below the definitions for certain oil and natural gas terms used in this Prospectus:

“3-D seismic” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two dimensional, seismic.

“Analogous reservoir” Analogous reservoir, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an analogous reservoir refers to a reservoir that shares the following characteristics with the reservoir of interest: same geological formation (but not necessarily in pressure communication with the reservoir of interest), same environment of deposition, similar geological structure, and same drive mechanism.

“Basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl” One stock tank barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.

“Boe” One barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil.

“Btu” A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one–pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

“Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Condensate” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“Developed acreage” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed oil and natural gas reserves” Reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

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“Development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole or well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

“Farm-in” An agreement between a participant who brings a property into the venture and another participant who agrees to spend an agreed amount to explore and develop the property and has no right of reimbursement but may gain a vested interest in the venture. A “farm-in” describes the position of the participant who agrees to spend the agreed-upon sum of money to gain a vested interest in the venture.

“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation” A layer of rock which has distinct characteristics that differ from nearby rock.

“Gross acres or gross wells” The total acres or wells, as the case may be, in which a working interest is owned.

“Henry Hub” The pricing point for natural gas futures contracts traded on the NYMEX.

“Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Lease operating expenses” The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

Index to Financial Statements

“Natural gas liquids” The hydrocarbon liquids contained within natural gas.

“Net acres or net wells” The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

“Pay” The vertical thickness of an oil and natural gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data.

“Plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

“Producing well” A well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

“Production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and natural gas produced. Examples of production costs (sometimes called lifting costs) are:

“Productive well” An exploratory, development or extension well that is not a dry well.

“Proved reserves” 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The

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project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“PUD” Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

“PV-10” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Commission.

“Reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

“Recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserve life” A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years.

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“Reserves” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.

“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Sand” A geological term for a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.

“Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized Measure” Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, without giving effect to non–property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our Standardized Measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes.

“Successful well” A well capable of producing oil and/or natural gas in commercial quantities.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“Wellbore” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

“Working interest” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploitation, development, and operating costs on either a cash, penalty, or carried basis.

“Workover” Operations on a producing well to restore or increase production.

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We have audited the accompanying consolidated balance sheets of Black Elk Energy Offshore Operations, LLC and Subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, members’ equity (deficit) and cash flows for the years ended December 31, 2010 and 2009 and for the period from inception (January 29, 2008) to December 31, 2008. 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 (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes 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.

As discussed in Note 2 to the consolidated financial statements, in 2009, the Company adopted SEC release 33-8995 and the amendments to ASC Topic 932, Extractive Industries—Oil and Gas, resulting from ASU 2010-03 (collectively, the “Modernization Rules”).

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, 2010 and 2009, and the consolidated results of their operations and their cash flows for the years ended December 31, 2010 and 2009 and for the period from inception (January 29, 2008) to December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

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Black Elk Energy Offshore Operations, LLC and Subsidiaries (collectively with its wholly-owned subsidiaries, “Black Elk” or the “Company”) is a Houston-based oil and natural gas company engaged in the exploration, development, production and exploitation of oil and natural gas properties. The Company was 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.

Reclassifications: Certain reclassifications have been made to conform 2008 and 2009 balances with 2010 presentation.

Principles of Consolidation: The consolidated financial statements include the accounts of Black Elk Energy Offshore Operation, LLC and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates: The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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. The Company analyzes its 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.

The Company accounts for business combinations using the purchase method, in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805 Business Combinations. The Company uses estimates to record the fair value of assets and liabilities acquired.

Oil and natural gas reserve 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: The Company considers 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.

Restricted Cash: Restricted cash at December 31, 2009 consists of two certificates of deposit with original maturities greater than a year related to plugging and abandonment liabilities.

Revenue Recognition: Oil, natural gas and plant products revenues are recorded using the sales method whereby the Company recognizes oil and natural gas revenue based on the amount of oil and natural gas sold to purchasers. The Company does 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.

Index to Financial Statements

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, 2010 and 2009.

Oil and Natural Gas Properties: The Company accounts 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 periods ended December 31, 2010, 2009 and 2008 was $29,595,750, $15,364,663 and $3,306,110, respectively. As more fully described below, proved reserves are estimated annually by the Company’s 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 the Company’s 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 operations. 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. The Company compares 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 the Company’s 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 periods ended December 31, 2010, 2009 and 2008, the Company recorded an impairment charge of approximately $6,406,551, $446,361 and $0, 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.

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

Index to Financial Statements

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 periods ended December 31, 2010, 2009 and 2008 was $198,942, $54,662 and $10,000, respectively.

In accordance with authoritative guidance on accounting for the impairment or disposal of long-lived assets, as set forth in ASC 360, the Company assesses the recoverability of the carrying value of its 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: The Company’s 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. The Company’s independent engineering firm prepares a reserve and economic evaluation of all the Company’s properties on a well-by-well basis utilizing information provided to it by the Company and information available from state agencies that collect information reported to it by the operators of the Company’s properties. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2010 and 2009 have been prepared and presented in accordance with new Securities and Exchange Commission (“SEC”) rules and accounting standards. These new rules are effective for fiscal years ending on or after December 31, 2009, and 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. The previous rule required that reserve estimates be calculated using last-day-of-the-year pricing.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to DD&A and impairment are made concurrently with changes to reserve estimates. The Company prepares its 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 the Company’s 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.

The Company’s 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 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 periods ended December 31, 2010, 2009 and 2008 amounted to $833,509, $745,334 and $277,685, respectively.

Index to Financial Statements

Derivative Financial Instruments: The Company utilizes certain derivative contracts to reduce its exposure in 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 the Company. The Company did not designate any of its derivative contracts as qualifying cash flow hedges. Accordingly, all gains and losses from the Company’s price risk management activities are currently included in earnings. Open positions are marked-to-market and recorded as unrealized gains or losses. Upon settlement, the resulting cash flows are reported as cash flows from operating activities.

Asset Retirement Obligations: ASC 410, 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. The Company recognizes the legal obligation of the dismantlement, restoration and abandonment costs associated with its oil and natural gas properties with its 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: The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company 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 payable is a result of imbalances acquired in conjunction with the acquisition of oil and natural gas properties. At December 31, 2010 and 2009, the Company’s gas imbalances were $4,552,171 and $2,041,942, respectively.

Income Taxes: The Company is 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 new margin-based franchise tax law that replaced the existing franchise tax. This new tax is commonly referred to as the Texas margin tax and is assessed at a 1% rate. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint 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 periods ended December 31, 2010, 2009 and 2008, the margin tax was immaterial to the consolidated financial statements.

Index to Financial Statements

Subsequent Events: The Company evaluates all events and transactions occurring subsequent to the balance sheet date through the date the consolidated financial statements are available to be issued. The Company evaluated such events and transactions through March 31, 2011, which is the date the consolidated financial statements were available for issuance. See Note 19.

Recent Accounting Pronouncements: In January, 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820) Improving Disclosures about Fair Value Measurements, which enhances the usefulness of fair value measurements. The amended guidance requires both the disaggregation of information in certain existing disclosures, as well as the inclusion of more robust disclosures about valuation techniques and inputs to recurring and nonrecurring fair value measurements.

The amended guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disaggregation requirement for the reconciliation disclosure of Level 3 measurements, which is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. The Company adopted ASU 2010-06 effective December 31, 2009, and the adoption did not have a significant impact on our consolidated financial statements.

In June 2009, the FASB issued ASC 105-10, Generally Accepted Accounting Principles, which establishes the codification as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of consolidated financial statements in conformity with GAAP. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This guidance was effective for financial statements issued for interim and annual periods ending after September 15, 2009. On the effective date of this guidance, all then-existing non-SEC accounting and reporting standards were superseded, except as noted within ASC 105. Concurrently, all non-grandfathered, non-SEC accounting literature not included in the Codification is deemed non-authoritative with some exceptions as noted within the literature. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial position or results of operations.

In May 2009, the FASB issued ASC 855, Subsequent Events, establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before consolidated financial statements are issued or are available to be issued. Although there is new terminology, the standard is based on the same principles as those that currently exist. This guidance, which includes a new required disclosure of the date through which an entity has evaluated subsequent events, is effective for interim or annual periods ending after June 15, 2009. The Company adopted this guidance for the year ended December 31, 2009. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial position or results of operations.

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting (the “Final Rule”). The Final Rule is intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves, which should help investors evaluate the relative value of oil and natural gas companies. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than year-end prices. In January 2010, the FASB issued ASU 2010-03, Extractive Activities—Oil and Gas (Topic 932) Oil and Gas Reserve Estimation and Disclosures (“ASU 2010-03”), which aligns the oil and natural gas reserve estimation and disclosure requirements of ASC 932 with the requirements in the SEC’s Final Rule, Modernization of the Oil and Gas Reporting Requirements discussed above. We adopted the Final Rule and ASU effective December 31, 2009. The impact of this change was immaterial to the Company’s consolidated financial statements.

Index to Financial Statements

The estimated fair values of the Company’s consolidated financial instruments closely approximate the carrying amounts as discussed below:

Cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities: The carrying amounts approximate fair value due to the short-term maturity of these instruments.

Debt: The carrying amount of the revolving long-term debt approximates fair value because the Company’s current borrowing rate does not materially differ from market rates for similar bank borrowings.

Derivative Instruments: See Note 9 for discussion of process used in estimating the fair value of derivative instruments.

On September 30, 2010, the Company acquired 27 properties in the Gulf of Mexico from Nippon Oil Exploration U.S.A. Limited. The purchase included 19 fields, for a purchase price of $5 million before normal purchase price adjustments. The acquisition gave us an aggregate interest in 684 gross wells on 41 platforms located across 169 thousand gross acres offshore.

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

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.

The following amounts of the Nippon acquisition’s revenue and earnings are included in our consolidated statements of operations for the year ended December 31, 2010:

Index to Financial Statements

On January 30, 2010, the Company 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 adds interest in an additional 40 wells and an estimated 14 thousand gross acres to the Company’s 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:

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.

On October 29, 2009, the Company acquired multiple properties in the Gulf of Mexico from W&T Offshore Inc. and paid 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 encompasses an estimated 195 thousand gross acres in the Gulf of Mexico. Also included in the transaction are 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:

Index to Financial Statements

On January 30, 2008, the Company closed the purchase of oil and gas properties in the South Timbalier 8 field from Stone Energy Corporation and received approximately $1.9 million, net of acquisition costs, and the assumption of $2.6 million of non-current liabilities.

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, 2008:

On March 31, 2008, the Company closed the purchase of oil and gas properties in the West Cameron 66 field from Stone Energy Corporation and received approximately $688,000, net of acquisition costs, and the assumption of $2.9 million of non-current liabilities.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on March 31, 2008:

The summarized unaudited pro forma financial information for the twelve months ended December 31, 2010 and 2009 and for the period from Inception (January 29,2008) to December 31, 2008, respectively, assumes that the Nippon and W&T acquisitions had occurred on January 29, 2008. 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 29, 2008 or the results that will be attained in the future.

Index to Financial Statements

The following table reflects capitalized costs related to the oil and natural gas properties as of December 31, 2010 and 2009:

ASC 410, Retirement Obligations, require 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 the Company’s 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 the Company’s 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 the Company’s 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.

Index to Financial Statements

In accordance with FASB ASC 815, Derivatives and Hedging, as amended, 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 of FASB ASC 815-30, are granted hedge accounting thereby allowing the Company 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.

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. The Company elected not to designate any of its 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.

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

Index to Financial Statements

The following table quantifies the fair values, on a gross basis, of all our derivatives contracts and identifies its balance sheet locations as of December 31, 2010:

The Company adopted ASC 820, Fair Value Measurements. ASC 820 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:

As required by ASC 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s 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 table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

Index to Financial Statements

At December 31, 2010 and 2009, management estimates that the derivative contracts had a fair value of ($15,455,958) and ($2,756,000), respectively. The Partnership 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 ASC 820. These factors include not only the impact of our nonperformance risk but also the credit standing of the counterparties involved in the Company’s derivative contracts.

During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Company’s derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to the current financial environment. In such cases, derivative instruments may be classified Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition.

On January 1, 2009, the Company adopted the provisions of ASC 820 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to the Company, the adoption applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; and the initial recognition of asset retirement obligations for which fair value is used.

This adoption of ASC 820 did not have a material impact on the Company’s financial statements or its disclosures with respect to the initial recognition of asset retirement obligations during the year ended December 31, 2010. These estimates are derived from historical costs as well as management’s expectation of future cost environments.

Index to Financial Statements

credit to be used exclusively for the issuance of letters of credit in support of the Company’s future plugging and abandonment liabilities relating to its 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. At December 31, 2010 there was no outstanding debt borrowed under our credit facility.

A commitment of 0.5% per annum is computed based on the unused borrowing base and paid quarterly. For the year ended December 31, 2010, the Company recognized $3,403 in commitment fees which has been included in interest expense on the consolidated statements of operations. A letter of credit fee is computed based on the same applicable margin used to determine the interest rate to Eurodollar loans times the stated face amount of each letter of credit.

The Credit Facility is secured by mortgages on at least 80% of the total value of the proved oil and gas reserves. The borrowing base is re-determined semi-annually on or around April 1^st and October 1st of each year. The administrative agent and the Company may each elect to cause the borrowing base to be re-determined one time between scheduled semi-annual redetermination periods.

The Credit Facility requires the Company and its subsidiaries to maintain certain financial covenants. Specifically, the Company may not permit, in each case as calculated as of the end of each fiscal quarter, its total leverage ratio to be more than 2.5 to 1.0, its interest rate coverage ratio to be less than 3.0 to 1.0, or its current ratio (in each case as defined in our revolving credit facility) to be less than 1.0 to 1.0. In addition, Black Elk and its 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, 2010, the Company was in compliance with all covenants.

On November 23, 2010, the Company issued $150 million face value of 13.75% Senior Secured Notes (the “13.75% Senior Secured Notes”) discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under its revolving credit facility, to fund Bureau of Ocean Energy Management, Regulation and Enforcement collateral requirements, and to prefund our escrow accounts. The Company will pay interest on the notes semi-annually, on June 1 and December 1 of each year, in arrears, commencing on June 1, 2011. The 13.75% Senior Secured Notes will mature on December 1, 2015, of which all principal then outstanding will be due. As of December 31, 2010, the recorded value of the 13.75% Senior Secured Notes was $148.7 million, which excludes the unamortized discount of $1.3 million. 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 the Credit Facility.

We have the right to redeem the 13.75% Senior Secured Notes under various circumstances. If the Company experiences a change of control, the holders of the notes may require the Company 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 its 13.75% Senior Secured Notes, the Company 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.

Index to Financial Statements

The 13.75% Senior Secured Notes require the Company to maintain certain financial covenants. Specifically, the Company may not permit its SEC PV-10 (as defined in Note 18) to consolidated leverage to be less than 1.4 to 1.0 as of the last day of each fiscal year. In addition, Black Elk and its 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. The Company’s capital expenditures are 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. As of December 31, 2010, the Company was in compliance with all covenants except that the Company did not furnish an annual report on Form 10-K for the year ended December 31, 2010 that complies in all material respects with all of the rules and regulations applicable to such reports pursuant to the Notes. The Company is preparing and intends to furnish an annual report on Form 10-K for the year ended December 31, 2010 that complies in all material respects with all of the rules and regulations applicable to such reports within the 60-day cure period as permitted under the Notes.

We are 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. Under certain circumstances, we may be required to pay additional cash interest beginning at 0.25% escalating to a maximum of 1% if the registration of the notes does not occur.

During 2010, the Company entered into two notes to finance annual insurance premiums related to its 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 $2,015,823.

Plainfield Specialty Holdings II, Gross Capital Management—Notes Payable

During 2008, the Company entered into two loan agreements with Plainfield Specialty Holdings II, Inc in the amounts of $7,000,000 and $2,200,000. The notes carried interest rates of 15% plus a credit fee of 0.625% of the outstanding balance. The notes were collateralized by the oil and natural gas reserves of Black Elk Energy, LLC and the Company. Additionally, the Company entered into a note payable with a member, Gross Capital Management (“GCP”), in the amount of $110,000. The notes carried an interest rate of 15% plus a credit fee of 0.625% of the outstanding balance and were collateralized by the assets of the Company. On July 13, 2009, the Company paid these notes off in full with proceeds received from the line of credit.

In September of 2008, the Company entered into a $200,000 note bearing an interest rate of 6.5% due in September of 2011, collateralized by the Company’s barge. The remaining balance of the note payable was $53,717 at December 31, 2010.

On July 13, 2009, and as amended on October 1, 2009 and further amended on October 29, 2009, the Company had a line of credit agreement with a member, PPVA Black Elk (Cayman) Ltd. (“Platinum”), to borrow an amount up to a maximum borrowing base of $75,000,000 to fund drilling and completion costs on wells. The line of credit carried an interest rate of 20% with accrued unpaid interest due monthly. The line of credit was collateralized by all of the Company’s assets. On November 23, 2010, the Company paid the outstanding principal and interest due to Platinum and retired the line of credit.

Index to Financial Statements

In September 2010, the Company entered into two promissory notes with affiliates of Platinum, for an aggregate $22 million of which $15 million was borrowed. These notes bear an interest rate of 24% per annum with a maturity date of March 23, 2011. The notes are secured by and have the benefits of the collateral described in the credit agreement and security instruments in the Platinum line of credit. In aggregate, the promissory notes have a prepayment penalty of $0.6 million. The notes were repaid in full in November 2010, including interest and prepayments of $1.2 million.

The amounts of required principal payments as of December 31, 2010, are as follows:

The 13.75% Senior Secured Notes have a face value of $150 million and were discounted at 99.109%. The discount is recognized over the life of the Notes and the full value of the Notes will be due at maturity.

The Company has 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 the Company 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 the Company fully vest after 3 years of service. The Company provided matching contributions to the Plan for the periods ended December 31, 2010, 2009 and 2008 of $348,853, $127,196 and $15,775, respectively.

The Member Agreement (the “Agreement”) has two classes of members. Net income (loss) of the Company 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 July 13, 2009 in connection with the line of credit, a portion of the membership interest was reallocated to include Platinum as a member. See also “Note 10—Long-Term Debt and Notes Payable.”

In June 2008, there was an extensive amount of well damage caused by a blowout. The Company 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 was reimbursed by the insurance company as expenditures were incurred.

The Company accounted for the insurance proceeds in accordance with ACS 605-40, 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 subject to ACS 605-40, 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

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caused by the blowout and hurricane, the Company has recognized a gain from involuntary conversions for the periods ended December 31, 2010, 2009 and 2008 of $0, $18,718,357 and $9,526,449, respectively, after applying the insurance deductibles.

The Company paid certain expenses on behalf of Black Elk Energy, LLC. At December 31, 2010 and 2009, the amount due from the related party was $22,430 and $22,430, respectively.

The Company had loan agreements with our members, Plainfield Specialty Holdings II, Inc and GCP, as described in Note 10. At December 31, 2009, the balance outstanding was $0. Interest expense of $0.4 million was recorded for the year ended December 31, 2009.

The Company had two notes payable to affiliates of our member, Platinum, as described in Note 10. At December 31, 2010, the balance of the notes was $0. Interest expense and prepayment penalties totaling $1.2 million were recorded for the year ended December 31, 2010.

The Company had a line of credit with a member, Platinum, as described in Note 10. At December 31, 2010 and 2009, the balance of the line of credit was $0 and $40.0 million, respectively. Interest expense for the periods ended December 31, 2010, 2009 and 2008 was $8.1 million, $2.5 million and $1.2 million, respectively.

During 2010, the Company loaned $1.0 million to a related party which was subsequently repaid in November 2010. At December 31, 2010, the interest receivable from the related party for the loan was $79,535. In October 2010, the Company guaranteed a loan in the aggregate principal amount of $3.2 million for the related party.

For periods ended December 31, 2010, 2009 and 2008, the Company paid $541,603, $10,396 and $133,176, respectively, to a related party for IT consulting services. At December 31, 2010 and 2009, the outstanding amount due to the related party was $119,452 and $20,546, respectively.

The following purchasers and operators accounted for 10% or more of the Company’s oil and natural gas sales:

In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of the Company’s 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. The Company believes that the loss of any of its major purchasers would not have a long-term material adverse effect on its operations.

Index to Financial Statements

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. The Company had cash deposits in certain banks that at times exceeded the maximum limits federally insured by the Federal Deposit Insurance Corporation. The Company monitors the financial condition of the banks and has 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. The Company actively monitors its 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 the Company’s oil and natural gas reserves and production are located in the Gulf of Mexico. The 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.

Due to the nature of the Company’s business, some contamination of the real estate property owned or leased by the Company 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 the Company. Accordingly, no provision for potential remediation costs is reflected in the accompanying consolidated financial statements.

The Company is 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 the consolidated financial position or results of operations of the Company.

The Company leases office space and certain equipment under non-cancelable operating lease agreements that expire on various dates through 2020. Approximate future minimum lease payments for operating leases at December 31, 2010 are as follows:

Index to Financial Statements

Rent expense of approximately $457,000, $253,000 and $146,000 was incurred under operating leases in the years ended December 31, 2010, 2009 and the period from Inception (January 29, 2008) through December 31, 2008, respectively.

Pursuant to the purchase agreement for the W&T Acquisition, the Company is required to fund two escrow accounts (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 plugging and abandonment costs that may be incurred on such properties. The Company was 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 amount may be adjusted downward in certain situations. The Company may withdraw cash from the W&T Escrow Accounts as reimbursement for performed plugging and abandonment obligations. However, no cash may be withdrawn if at any point the Company is in default under our stipulated payment schedules. As of November 2010, the Company fully funded the operating escrow account in the amount of $32.6 million and payment schedule was amended. As of December 31, 2010, the Company funded the non-operating escrow account in the amount of $8.6 million, leaving $22.6 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 and Platinum are pari passu second lien holders. Once plugging and abandonment 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 automatically be extinguished. W&T Offshore Inc. also has a second priority lien with respect to the interest in properties acquired from the W&T Acquisition (with Platinum and BNP Paribas sharing a first priority lien), which lien will be released once the W&T Escrow Accounts have been fully funded.

On January 1, 2009, the Company adopted ASC 740 which clarifies the accounting for uncertainty in income taxes recognized in the Company’s financial statements in accordance with ASC 740 and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. ASC 740 also provides guidance on derecognition and measurement of a tax position taken or expected to be taken in a tax return. The adoption of ASC 740 did not have a material effect on the Company as the Company is considered a flow through entity for US federal tax purposes. As such, the Company’s only exposure to uncertain tax positions relates to the Texas margins tax.

The Company did not have unrecognized tax benefits as of December 31, 2010 and 2009, and does not expect this to change significantly over the next 12 months. In connection with the adoption of ASC 740-10-25, the Company will recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of December 31, 2010 and 2009, the Company has not accrued interest or penalties related to uncertain tax positions.

The Company’s tax years for fiscal years ended December 31, 2010, 2009, and 2008 are subject to examination in the United States and relevant state jurisdictions.

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The supplementary data presented herein reflects information for all of our oil and natural gas producing activities. Costs incurred for oil and natural gas property acquisition, exploration and development activities follows:

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

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

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

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 ASU 932, 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”).

Index to Financial Statements

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 the Company’s 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.

Index to Financial Statements

On March 16, 2011, the Company entered into a purchase agreement to acquire interests in various oil and natural gas properties in the Gulf of Mexico for a purchase price of $40 million and paid an earnest money deposit of $4 million upon execution of the agreement. The Company intends to finance the acquisition with existing available cash and borrowings under its Credit Facility. The Company intends to commence a consent solicitation to amend the maximum capital expenditures provision of the indenture governing its outstanding 13.75% Senior Secured Notes due 2015 to permit the Company to consummate this acquisition. The acquisition will close subject to the satisfaction of a number of conditions, including receipt of third-party consents.

On February 23, 2011, the Company acquired properties in the Gulf of Mexico, primarily located within Texas state waters for a purchase price of $6 million before normal purchase price adjustments.

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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

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NOTE 1—ORGANIZATION AND BUSINESS; SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations: Black Elk Energy Offshore Operations, LLC and Subsidiaries (collectively with its wholly-owned subsidiaries, “Black Elk” or the “Company”) is a Houston-based oil and natural gas company engaged in the exploration, development, production and exploitation of oil and natural gas properties. The Company was 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.

Basis of Presentation: The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the U.S. for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation of the Company’s interim and prior period results have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for any other interim period or for the entire fiscal year. For further information, refer to the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 which is located on its website.

Principles of Consolidation: The consolidated financial statements include the accounts of Black Elk Energy Offshore Operation, LLC and its wholly-owned subsidiaries. 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 accounting principles generally accepted in the United States of America 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. The Company analyzes its estimates based on historical experience, current factors and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates.

Recent Accounting Pronouncements: In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820) Improving Disclosures about Fair Value Measurements (“ASU 2010-06”), which enhances the usefulness of fair value measurements. The amended guidance requires both the disaggregation of information in certain existing disclosures, as well as the inclusion of more robust disclosures about valuation techniques and inputs to recurring and nonrecurring fair value measurements.

Index to Financial Statements

The amended guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disaggregation requirement for the reconciliation disclosure of Level 3 measurements, which is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. The Company adopted ASU 2010-06 effective December 31, 2010, and the adoption did not have a significant impact on its consolidated financial statements.

In December 2009, the SEC released Final Rule, Modernization of Oil and Gas Reporting (the “Final Rule”). The Final Rule is intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves, which should help investors evaluate the relative value of oil and natural gas companies. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than year-end prices. In January 2010, the FASB issued ASU 2010-03, Extractive Activities — Oil and Gas (Topic 932) Oil and Gas Reserve Estimation and Disclosures (“ASU 2010-03”), which aligns the oil and natural gas reserve estimation and disclosure requirements of ASC 932 with the requirements in the SEC’s Final Rule, Modernization of the Oil and Gas Reporting Requirements discussed above. The Company adopted the Final Rule and ASU effective December 31, 2009. The impact of this change was immaterial to the Company’s consolidated financial statements.

Oil and Gas Properties: The Company accounts 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 the Company’s 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 annually by the Company’s 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 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 the Company’s engineers using existing regulatory requirements and anticipated future inflation rates.

Index to Financial Statements

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.

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

The following table describes the changes to the Company’s asset retirement obligations:

On February 23, 2011, the Company acquired properties in the Gulf of Mexico from Maritech Resources Incorporated, primarily located within federal offshore waters 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. The purchase included eight fields and adds interest in an additional 108 gross wells and an estimated 46 thousand gross acres to the Company’s portfolio. Upon closing on the Maritech Acquisition in February 2011, the Company entered into an irrevocable letter of credit (“ILOC”) with Capital One in the amount of $2.8 million costs related to P&A obligations for interests in properties acquired.

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:

Index to Financial Statements

On September 30, 2010, the Company acquired 27 properties in the Gulf of Mexico from Nippon Oil Exploration U.S.A. Limited. The purchase included 19 fields, for a purchase price of $5 million before normal purchase price adjustments and the assumption of $57.2 million in asset retirement obligations related to P&A obligations associated with acquired properties. The acquisition gave the Company an aggregate interest in 684 gross wells on 41 platforms located across 169 thousand gross acres offshore.

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

The following unaudited pro forma combined, condensed financial information for the three months ended March 31, 2010 was derived from the historical financial statements of the Company giving effect to the Nippon acquisition as if it 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 the Company had completed the acquisition as of January 1, 2010 or the results that will be attained in the future.

Index to Financial Statements

The Company enters into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of oil and natural gas. It uses financially settled crude oil and natural gas swaps. The Company elected not to designate any of its 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.

At March 31, 2011, the Company had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss)):

The following table quantifies the fair values, on a gross basis, of all the Company’s derivatives contracts and identifies its balance sheet locations as of March 31, 2011 (in thousands):

Index to Financial Statements

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2011, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

At March 31, 2011, management estimates that the derivative contracts had a fair value of ($46.4) million. The Company 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 ASC 820. These factors include not only the impact of the Company’s nonperformance risk but also the credit standing of the counterparties involved in its derivative contracts.

Index to Financial Statements

As of March 31, 2011, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s 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 March 31, 2011 was $154.2 million.

This adoption of ASC 820 did not have a material impact on the Company’s financial statements or its disclosures with respect to the initial recognition of asset retirement obligations. These estimates are derived from historical costs as well as management’s expectation of future cost environments.

On December 24, 2010 the Company entered into an aggregate $110 million credit facility (“the 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 the Company’s future plugging and abandonment liabilities relating to its 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. At March 31, 2011 there was no outstanding debt borrowed on the Credit Facility.

A commitment of 0.5% per annum is computed based on the unused borrowing base and paid quarterly. For the three months ended March 31, 2011, the Company recognized $43,750 in commitment fees which has been included in interest expense on the consolidated statements of operations. A letter of credit fee is computed based on the same applicable margin used to determine the interest rate to Eurodollar loans times the stated face amount of each letter of credit.

Index to Financial Statements

administrative agent and the Company may each elect to cause the borrowing base to be re-determined one time between scheduled semi-annual redetermination periods.

On May 31, 2011, the Company 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.

The Credit Facility requires the Company and its subsidiaries to maintain certain financial covenants. Specifically, the Company may not permit, in each case as calculated as of the end of each fiscal quarter, its total leverage ratio to be more than 2.5 to 1.0, its interest rate coverage ratio to be less than 3.0 to 1.0, or its current ratio (in each case as defined in our revolving credit facility) to be less than 1.0 to 1.0. In addition, the Company and its 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 March 31, 2011, the Company was in compliance with all covenants.

On November 23, 2010, the Company issued $150 million face value of 13.75% Senior Secured Notes (the “13.75% Senior Secured Notes”) discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under its revolving credit facility, to fund Bureau of Ocean Energy Management, Regulation and Enforcement collateral requirements, and to prefund our escrow accounts. The Company pays interest on the notes semi-annually, on June 1 and December 1 of each year, in arrears, commencing on June 1, 2011. The 13.75% Senior Secured Notes will mature on December 1, 2015, of which all principal then outstanding will be due. As of March 31, 2011, the recorded value of the 13.75% Senior Secured Notes was $148.7 million, which includes the unamortized discount of $1.3 million. 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.

On May 23, 2011, the Company commenced a consent solicitation that was completed on May 31, 2011 under the First Supplemental Indenture to the Indenture. The Supplemental Indenture amended the Indenture, among other things, to: (i) increase the amount of capital expenditures permitted to be made by the Company on an annual basis, (ii) enable the Company to obtain financial support from its majority equity holder by way of a $30 million investment in Sponsor Preferred Stock, which can be repaid over time, and (iii) obligate the Company 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 it meets certain defined financial tests and as permitted by its credit facilities.

The 13.75% Senior Secured Notes require the Company to maintain certain financial covenants. Specifically, the Company may not permit its SEC PV-10 to consolidated leverage to be less than 1.4 to 1.0 as of the last day of

Index to Financial Statements

each fiscal year. In addition, Black Elk and its 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. The Company’s capital expenditures are 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, 2010, the Company was in compliance with all covenants except that the Company did not furnish an Annual Report on Form 10-K for the year ended December 31, 2010 that complies in all material respects with all of the rules and regulations applicable to such reports pursuant to the Notes. The Company is preparing and intends to furnish an Annual Report on Form 10-K for the year ended December 31, 2010 that complies in all material respects with all of the rules and regulations applicable to such reports within the 60-day cure period as permitted under the Notes. In May 2011, the Company prepared and posted an Annual Report on Form 10-K for the year ended December 31, 2010 on the Company’s website and included the financial statements for the year ended December 31, 2010.

The amounts of required principal payments as of March 31, 2011, are as follows:

Index to Financial Statements

Pursuant to the purchase agreement for the Maritech Acquisition, the Company is 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 plugging and abandonment costs that may be incurred on such properties. As of March 31, 2011, the Company has funded $0.4 million, leaving an unfunded amount of $12.7 million to be funded through February 2014.

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 and Platinum are pari passu second lien holders. Once plugging and abandonment 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 automatically be extinguished. W&T Offshore Inc. 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.

The Company paid certain expenses on behalf of Black Elk Energy, LLC. At March 31, 2011 and December 31, 2010, the amount due from the related party was $22,430 and $22,430, respectively.

For three months ended March 31, 2011, the Company paid $320,516, to a related party for IT consulting services. At March 31, 2011, the outstanding amount due to the related party was $40,851.

Acquisitions. On May 31, 2011, the Company completed its previously announced purchase of certain properties from Merit Energy. The Company acquired interests in various properties across approximately 250,126 gross (127,894 net) acres in the Gulf of Mexico for a purchase price of $39 million plus the assumption of approximately $168.4 million (based on current estimates) of undiscounted asset retirement obligations related to plugging and abandonment (“P&A”) obligations associated with the acquired properties, subject to customary adjustments for a transaction of that type.

Index to Financial Statements

At closing, the Company was required to establish an escrow account to secure the performance of its P&A obligations and other indemnity obligations with respect to P&A and/or decommissioning of the acquired wells and facilities. The Company paid $33 million in surety bonds at closing and is 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.

Prior to closing, the Company paid the sellers an earnest money deposit of $6 million, of which $4 million was paid upon execution of the agreement and is included in “Prepaid expense and other” on the consolidated balance sheets. The additional $2 million was paid in May 2011. The earnest money was applied against the purchase price. The Company financed the remainder of the purchase price and related expenditures with existing available cash and approximately $35 million in borrowings under its Credit Facility, together with equity financing from its members.

In order to consummate this acquisition, the Company commenced a consent solicitation to amend the maximum capital expenditures provision of the indenture governing its outstanding 13.75% Senior Secured Notes due 2015 (the “Notes”). On May 31, 2011, the Company acquired the consents to (i) increase the amount of capital expenditures permitted by the Company on an annual basis, (ii) enable the Company to obtain financial support from its majority equity holder in the amount of a $30 million investment, and (iii) obligate the Company 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 the Company meets certain defined financial tests and as permitted by its credit facilities.

There are no material relationships, other than in respect of the acquisition, between the sellers and the Company or any of its affiliates or any director or officer of the Company, or any associate of any such director or officer.

Financing. Subsequent to March 31, 2011, we had an aggregate amount of $72.3 million of indebtedness outstanding under our credit facility, $27.3 million that was drawn as a letter of credit in support of our P&A obligations and $45 million of borrowings under the revolver; $122.7 million is available for additional borrowings. On May 31, 2011, the Company entered into an amendment on the Credit Facility. See Note 6 for additional information.

On May 23, 2011, the Company commenced a consent solicitation relating to the 13.75% Senior Secured Notes. On May 31, 2011, the Company received the requisite consents and paid a consent solicitation fee of $4.5 million. See Note 6 regarding additional information on the First Supplemental Indenture to the Indenture. As part of the First Supplemental Indenture to the Indenture, the Company obtained financial support from its majority equity holder by way of a $30 million investment in Sponsor Preferred Stock, which can be repaid over time. As a result of this change, the Company entered into a Second Amendment that amended the Company’s operating agreement which created a class of non-voting Class D Units having an aggregate liquidation preference of $30 million and accrued dividends payable in kind at a rate per annum of 24%. Additionally, the Company prepared and posted an Annual Report on Form 10-K for the year ended December 31, 2010 on the Company’s website and included the financial statements for the year ended December 31, 2010 in a registration statement on Form S-4, which was filed with the SEC in May 2011. The registration statement is currently not effective.

Commitments and Contingencies. On April 29, 2011, the Company 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 tentative commencement date for the move is expected to occur in June 2011. The termination date of the agreement is December 31, 2020.

Index to Financial Statements

of the Oil and Gas Properties Purchased by Black Elk Energy Offshore Operations, LLC

Index to Financial Statements

We have audited the accompanying statements of combined revenues and direct operating expenses of the oil and gas properties purchased by Black Elk Energy Offshore Operations, LLC from W&T Offshore, Inc. (the Acquired Properties), as described in Note 1, for the ten-month period ended October 31, 2009 and the year ended December 31, 2008. These financial statements are the responsibility of Black Elk Energy Offshore Operations, LLC and W&T Offshore, Inc. management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Acquired Properties’ internal control over financial reporting. Our audit 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 Acquired Properties’ internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the basis of accounting used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

The accompanying financial statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission, and are not intended to be a complete financial presentation of the Acquired Properties.

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined revenues and direct operating expenses of the Acquired properties for the ten-month period ended October 31, 2009 and the year ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

Index to Financial Statements

Statements of Combined Revenues and Direct Operating Expenses of The Oil and

The accompanying notes to the statements of combined revenues and direct operating expenses are an integral part of these statements.

Index to Financial Statements

Notes to Statements of Combined Revenues and Direct Operating Expenses of The

Oil and Gas Properties Purchased by Black Elk Energy Offshore Operations, LLC

On October 29, 2009, Black Elk Energy Offshore Operations, LLC (Black Elk) acquired certain oil and natural gas property interests in offshore producing fields located in the Gulf of Mexico from W&T Offshore, Inc. (W&T), referred to herein as the “Acquired Properties”. The effective date of the transaction was August 1, 2009. The purchase price was $30 million, subject to customary effective-date adjustments and closing adjustments. The Acquired Properties consist primarily of interests in 36 fields including related leases, platforms, equipment and other associated assets located in the outer continental shelf of the Gulf of Mexico.

The statements of combined revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from W&T’s historical accounting records prepared using the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Revenues and direct operating expenses relate to W&T’s historical net revenue interest and net working interest, respectively, in the Acquired Properties. Natural gas, oil, natural gas liquids, and other related revenues are recognized when production is sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and when collectability is reasonably assured. Revenues are reported net of overriding and other royalties due to third parties. Direct operating expenses include lease and well repairs, production taxes, gathering and transportation, maintenance, utilities, payroll and other direct operating expenses. During the periods presented, the Acquired Properties were not accounted for as a separate division by W&T and therefore certain costs such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, and corporate income taxes were not allocated to the individual properties. Accordingly, full separate financial statements prepared in accordance with generally accepted accounting principles are not presented because the information necessary to prepare such a statement is neither readily available on an individual property basis nor practicable to obtain in these circumstances. As such, these financial statements are not intended to be a complete presentation of the revenues and expenses of the Acquired Properties and are not indicative of the financial condition or results of the operation of the Acquired Properties going forward due to the changes in the business and the omission of various operating expenses as described above.

Subsequent events have been evaluated for recognition and disclosure through April 20, 2011, the date the financial statements were available to be issued.

The following tables summarize the net ownership interest in the estimated proved reserves and the standardized measure of discounted future net cash flows related to proved reserves for the Acquired Properties. The standardized measure presented here excludes income taxes as the tax basis for the Acquired Properties could not be determined or reasonably estimated for the periods presented. The other components of standardized measure were determined in accordance with the authoritative guidance of the Financial Accounting Standards Board (FASB) and the Securities and Exchange Commission (SEC) effective for December 31, 2008. Production for the ten month period ended October 31, 2009 was approximately 8,036 Mcfe. Proved reserves were not independently estimated as of October 31, 2009, and thus are not available for this report.

Index to Financial Statements

Notes to Statements of Combined Revenues and Direct Operating Expenses of The

Oil and Gas Properties Purchased by Black Elk Energy Offshore Operations, LLC

There are numerous uncertainties in estimating quantities of proved reserves, which incorporate estimates of the future rates of production, the timing of development expenditures and other assumptions. The following reserve data represent estimates only and are inherently imprecise and may be subject to substantial revisions as additional information becomes available, such as reservoir performance, additional drilling, technological advancements and other factors. Decreases in the prices of oil and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. Similarly, the standardized measure incorporates various assumptions such as prices, costs, production rates and discounts rates that are inherently imprecise. Actual results could be materially different and the results may not be comparable to estimates disclosed by other oil and gas companies.

W&T engaged a third party to perform reserve studies on the Acquired Properties, in addition to other properties it owned, as of December 31, 2008 based on SEC reserve definitions and pricing in effect for that time period. Certain amendments to the Extractive Activities—Oil and Gas topic of the Financial Accounting Standards Board Accounting Standards Codification were adopted effective December 31, 2009; the reserves presented for the year ended December 31, 2008 do not include these amendments.

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate was made. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. All of the reserves are located offshore in the Gulf of Mexico.

The following table sets forth estimated quantities of the Acquired Properties net proved, proved developed and proved undeveloped oil (including natural gas liquids) and natural gas reserves.

Index to Financial Statements

Notes to Statements of Combined Revenues and Direct Operating Expenses of The

Oil and Gas Properties Purchased by Black Elk Energy Offshore Operations, LLC

The standardized measure is the estimated net future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs, and a discount factor. Production costs do not include depreciation, depletion and amortization of capitalized acquisitions, exploration and development costs. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the year-end commodity prices and any fixed and determinable future price changes provided by contractual arrangements in existence at year end. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end proved reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. As mentioned above, the standardized measure presented here does not include the effects of income taxes.

In calculating standardized measure, future net cash inflows were estimated by using future production of period-end proved reserves and assume continuation of existing economic conditions. The commodity prices used for the December 31, 2008 and December 31, 2007 periods, adjusted for items specific to the properties, were $6.33 per Mcfe and $9.64 per Mcfe, respectively, which combines the prices for natural gas, oil and natural gas liquids. Prices for each commodity were not available. Future production and development costs are based on estimated costs in effect at the end of the respective period with no escalations. Estimated future net cash flows have been discounted to their present values based on a 10% annual discount rate in accordance with FASB’s authoritative guidance.

The standardized measure does not purport, nor should it be interpreted, to present the fair market value of the oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in the future, and the risks inherent in reserve estimates. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.

Index to Financial Statements

Notes to Statements of Combined Revenues and Direct Operating Expenses of The

Oil and Gas Properties Purchased by Black Elk Energy Offshore Operations, LLC

Standardized measure of discounted future net cash flows before income taxes relating to proved oil and natural gas reserves is as follows:

Changes to the standardized measure relating to our proved oil and natural gas reserves are as follows:

Index to Financial Statements

of the Oil and Gas Properties Purchased by Black Elk Energy Offshore Operations, LLC

Index to Financial Statements

We have audited the accompanying statements of combined revenues and direct operating expenses of the oil and gas properties purchased by Black Elk Energy Offshore Operations, LLC from Nippon Oil Exploration U.S.A. Limited (the Acquired Properties), as described in Note 1, for the nine-month period ended September 30, 2010 and the years ended December 31, 2009 and 2008. These financial statements are the responsibility of Black Elk Energy Offshore Operations, LLC and Nippon Oil Exploration U.S.A. Limited management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Acquired Properties’ 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 Acquired Properties’ 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 financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined revenues and direct operating expenses of the Acquired Properties for the nine-month period ended September 30, 2010 and the years ended December 31, 2009 and 2008, in conformity with U.S. generally accepted accounting principles.

Index to Financial Statements

The accompanying notes to the statements of combined revenues and direct operating expenses are an integral part of these statements.

Index to Financial Statements

On September 30, 2010 Black Elk Energy Offshore Operations, LLC (the Company) acquired from Nippon Oil Exploration U.S.A. Limited (Nippon) certain offshore oil and natural gas properties and related facilities located in the Gulf of Mexico as defined in the Purchase and Sale Agreement between the Company and Nippon (the Acquired Properties) for approximately $5.0 million, subject to closing adjustments, with an effective date of January 1, 2010. The accompanying statements of combined revenues and direct operating expenses relate to the operations of the Acquired Properties.

The statements of combined revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from Nippon’s historical accounting records prepared using the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Revenues and direct operating expenses relate to Nippon’s historical net revenue interest and net working interest, respectively, in the Acquired Properties. Natural gas, oil and natural gas liquids revenues are recognized when production is sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and when collectability is reasonably assured. Revenues are reported net of overriding and other royalties due to third parties. Direct operating expenses include lease and well repairs, production taxes, gathering and transportation, maintenance, utilities, payroll and other direct operating expenses. During the periods presented, the Acquired Properties were not accounted for as a separate division by Nippon and therefore certain costs such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, and corporate income taxes were not allocated to the individual properties. Accordingly, full separate financial statements prepared in accordance with generally accepted accounting principles are not presented because the information necessary to prepare such a statement is neither readily available on an individual property basis nor practicable to obtain in these circumstances. As such, these financial statements are not intended to be a complete presentation of the revenues and expenses of the Acquired Properties and are not indicative of the financial condition or results of the operation of the Acquired Properties going forward due to the changes in the business and the omission of various operating expenses as described above.

Subsequent events have been evaluated for recognition and disclosure through May 9, 2011, the date the financial statements were available to be issued.

The following tables summarize the net ownership interest in the estimated proved reserves and the standardized measure of discounted future net cash flows related to proved reserves for the Acquired Properties for the periods indicated. The standardized measure presented here excludes income taxes as the tax basis for the Acquired Properties could not be determined or reasonably estimated for the periods presented. The other components of standardized measure were determined in accordance with the authoritative guidance of the Financial Accounting Standards Board (FASB) and the Securities and Exchange Commission (SEC) effective for December 31, 2008. Production for the nine month periods ended September 30, 2010 and 2009 were approximately 1,573 and 1,750 MBoe, respectively. Proved reserves were not independently estimated as of September 30, 2010 or 2009, and thus are not available for this report.

Index to Financial Statements

There are numerous uncertainties in estimating quantities of proved reserves, which incorporate estimates of the future rates of production, the timing of development expenditures and other assumptions. The following reserve data represent estimates only and are inherently imprecise and may be subject to substantial revisions as additional information becomes available, such as reservoir performance, additional drilling, technological advancements and other factors. Decreases in the prices of oil and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. Similarly, the standardized measure incorporates various assumptions such as prices, costs, production rates and discount rates that are inherently imprecise. Actual results could be materially different and the results may not be comparable to estimates disclosed by other oil and gas companies.

The Company did not engage a third party to perform reserve studies for the periods indicated. As of December 31, 2010, the Company engaged Netherland Sewell & Associates, Inc. to prepare an independent reserve report on all properties owned by Black Elk including the Acquired Properties. For this presentation, the estimates of reserves as of December 31, 2009 and 2008 have been prepared internally by (i) adding back the quantity of oil and natural gas produced from the Acquired Properties for the periods from January 1, 2009 through December 31, 2009 and January 1, 2010 through December 31, 2010 from the reserve estimates at December 31, 2010 based on the reserve report dated January 26, 2011 of Netherland, Sewell & Associates, Inc., independent petroleum engineers, which was prepared in accordance with the Oil & Gas Disclosure Rules and other applicable rules and regulations of the SEC. Accordingly, there will be no “revisions of prior estimates” amounts.

The following table sets forth estimated quantities of the Acquired Properties net proved, proved developed and proved undeveloped oil (including natural gas liquids) and natural gas reserves.

Index to Financial Statements

The standardized measure is the estimated net future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs, and a discount factor. Production costs do not include depreciation, depletion and amortization of capitalized acquisitions, exploration and development costs. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the year-end commodity prices and any fixed and determinable future price changes provided by contractual arrangements in existence at year end for 2008, and the twelve month unweighted average of the first of the month commodity prices for 2009. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end proved reserves are based on period-end costs. Such costs include, but are not limited to production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. As mentioned above, the standardized measure presented here does not include the effects of income taxes.

In calculating the standardized measure, future net cash inflows were estimated by using future production of period-end proved reserves and assume continuation of existing economic conditions. The oil prices used for the December 31, 2009 and December 31, 2008 periods, adjusted for items specific to the properties, were $57.65 per barrel and $41.00 per barrel, respectively. The natural gas prices used for the December 31, 2009 and December 31, 2008, adjusted for items specific to the properties, were $3.87 per million cubic feet and $5.71 per million cubic feet, respectively. Future production and development costs are based on estimated costs in effect at the end of the respective periods with no escalation. Estimated future net cash flows have been discounted to their present values based on a 10% annual discount rate in accordance with FASB’s authoritative guidance.

The standardized measure does not purport, nor should it be interpreted, to present the fair market value of the oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in the future, and the risks inherent in the reserve estimates. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.

The standardized measure of discounted future net cash flows before income taxes related to proved oil and gas reserves of the Acquired Properties is as follows:

Index to Financial Statements

Changes to the standardized measure relating to our proved oil and natural gas reserves as follows:

Index to Financial Statements

Statements of Revenues and Direct Operating Expenses of Merit Energy Company’s

Oil and Gas Properties under contract for Purchase by Black Elk Energy Offshore Operations, LLC

Index to Financial Statements

We have audited the accompanying statements of revenues and direct operating expenses of Merit Energy Company’s oil and gas properties under contract for purchase by Black Elk Energy Offshore Operations, LLC (the Properties) for each of the years in the three-year period ended December 31, 2010. These statements are the responsibility of the Properties’ management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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 Properties’ 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 financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements referred to above were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. The statements are not intended to be a complete presentation of the revenues and expenses of the Properties.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of Merit Energy Company’s oil and gas properties under contract for purchase by Black Elk Energy Offshore Operations, LLC for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

Index to Financial Statements

OF MERIT ENERGY COMPANY’S OIL AND GAS PROPERTIES UNDER CONTRACT FOR PURCHASE BY BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

Index to Financial Statements

OF MERIT ENERGY COMPANY’S OIL AND GAS PROPERTIES UNDER CONTRACT FOR PURCHASE BY BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

On March 17, 2011, Black Elk Energy Offshore Operations, LLC ( “Black Elk”) entered into an agreement with 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. (“Merit Energy”) to sell certain offshore oil and gas properties and related facilities located in the Gulf of Mexico (the “Properties”) as defined in the Purchase and Sale Agreement between the Black Elk and Merit Energy for approximately $40 million, subject to normal closing adjustments, with an effective date of January 1, 2011. The accompanying statements of revenues and direct operating expenses relate only to the properties to be divested by Merit Energy and subsequently acquired by Black Elk (Black Elk Properties).

Historical financial statements prepared in accordance with accounting principles generally accepted in the United States of America have never been prepared for the Black Elk Properties. During the periods presented, the Black Elk Properties were not accounted for or operated as a consolidated entity or as a separate division by Merit Energy. The accompanying statements of revenues and direct operating expenses related to the Black Elk Properties were prepared from the historical accounting records of Merit Energy.

Certain indirect expenses, as further described in Note 4, were not allocated to the Black Elk Properties and have been excluded from the accompanying statements. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and may not be indicative of the performance of the properties on a stand-alone basis.

These statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting financial position, results of operations, stakeholder’s equity and cash flows of the Black Elk Properties and are not necessarily indicative of the results of operations for the Black Elk Properties going forward.

The accompanying statements of revenues and direct operating expenses for the three months ended March 31, 2011 and 2010 are unaudited but, in the opinion of management, include all adjustments (consisting of normal recurring adjustments) that are necessary for a fair presentation of the revenues and direct operating expenses of the Properties for those periods.

The preparation of statements of revenues and direct operating expenses in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates.

Merit Energy utilizes the sales method of accounting for oil and natural gas revenues whereby revenues, net of royalties, are recognized based on the actual volumes of oil and natural gas production sold to purchasers. The amount of gas sold may differ from the amount to which Merit Energy is entitled based on its revenue interests in the properties.

Index to Financial Statements

OF MERIT ENERGY COMPANY’S OIL AND GAS PROPERTIES UNDER CONTRACT FOR PURCHASE BY BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

Direct operating expenses, which are recognized on an accrual basis, relate to the direct expenses of operating the Black Elk Properties. The direct operating expenses include lease operating, ad valorem tax and production tax expense. Lease operating expenses include lifting costs, well repair expenses, surface repair expenses, well workover costs and other field expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment and facilities directly related to oil and natural gas production activities.

Merit Energy management has evaluated subsequent events from December 31, 2010 through May 17, 2011, the date at which the financial statements were available to be issued, and determined that there are no other items to disclose.

The activities of the Black Elk Properties are subject to potential claims and litigation in the normal course of operations. Merit Energy management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Black Elk Properties.

The Black Elk Properties were part of a much larger enterprise prior to the expected date of the sale by Merit Energy to Black Elk. Indirect general and administrative expenses, interest, income taxes, and other indirect expenses were not allocated to the Black Elk Properties and have been excluded from the accompanying statements. In addition, any allocation of such indirect expenses may not be indicative of costs which would have been incurred by the Black Elk Properties on a stand-alone basis.

Also, depreciation, depletion, and amortization have been excluded from the accompanying statements of revenues and direct operating expenses as such amounts would not be indicative of the depletion calculated on the Black Elk Properties on a stand-alone basis.

The estimates of Proved Oil and Gas Reserves as of December 31, 2010, 2009 and 2008 were prepared for Merit Energy utilizing year-end estimates of reserve quantities provided by third-party independent petroleum engineering consultants. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at the SEC applicable prices and costs for each year under the then existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves estimated to be recovered through existing wells. Proved Undeveloped Reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operation is required. All of the Black Elk Properties’ Proved Reserves are located offshore in the Gulf of Mexico.

Index to Financial Statements

OF MERIT ENERGY COMPANY’S OIL AND GAS PROPERTIES UNDER CONTRACT FOR PURCHASE BY BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

The following table sets forth estimates of the proved oil and natural gas reserves (net of royalty interests) for the Black Elk Properties and changes therein, for the periods indicated.

Index to Financial Statements

We have summarized the Standardized Measure related to our proved oil, natural gas and NGL reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on SEC pricing applicable for each year, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in place and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.

During recent years, prices paid for oil and natural gas have fluctuated significantly. Estimated discounted future net cash flows in the table above for December 31, 2010, 2009 and 2008 were computed using NYMEX prices of $79.79, $61.08, and $44.60 per barrel of oil, respectively, and $4.39, $3.99, and $5.62 per MMBTU of natural gas, respectively.

Index to Financial Statements

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods indicated.

Index to Financial Statements

TO TENDER OLD 13.75% SENIOR SECURED NOTES DUE 2015 OF BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC

THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME , ON , 2011 (THE “EXPIRATION DATE”), UNLESS EXTENDED BY THE ISSUERS.

The Exchange Agent for the Exchange Offer is The Bank of New York Mellon Trust Company, N.A., and its contact information is as follows:

If you wish to exchange your issued and outstanding 13.75% Senior Secured Notes due 2015 (the “old notes”) for an equal aggregate principal amount of 13.75% Senior Secured Notes due 2015 (the “new notes”) with materially identical terms that have been registered under the Exchange Act of 1933, as amended (the “Exchange Act”), pursuant to the Exchange Offer, you must validly tender (and not withdraw) old notes to the Exchange Agent prior to the Expiration Date.

We refer you to the Prospectus, dated , 2011 (the “Prospectus”), of Black Elk Energy Offshore Operations, LLC (the “Company”) and Black Elk Energy Finance Corp. (the “Co-Issuer” and together with the Company, the “Issuers”), and this Letter of Transmittal (this “Letter of Transmittal”), which together describe the Issuers’ offer (the “Exchange Offer”) to exchange the old notes for a like aggregate principal amount of new notes. Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

The Issuers reserve the right, at any time or from time to time, to extend the Exchange Offer at their discretion, in which event the term “Expiration Date” shall mean the latest date to which the Exchange Offer is

Index to Financial Statements

extended. The Issuers shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

This Letter of Transmittal is to be used by holders of the old notes. Tender of the old notes in book-entry form is to be made according to the Automated Tender Offer Program (“ATOP”) of The Depository Trust Company (“DTC”) pursuant to the procedures set forth in the Prospectus under the caption “Exchange Offer—Procedures for Tendering.” DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent’s DTC account. DTC will then send a computer generated message known as an “agent’s message” to the Exchange Agent for its acceptance. For you to validly tender your old notes in the Exchange Offer, the Exchange Agent must receive, prior to the Expiration Date, an agent’s message under the ATOP procedures that confirms that:

BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

Index to Financial Statements

(a) the new notes acquired pursuant to the Exchange Offer are being obtained in the ordinary course of business of you, whether or not you are the holder;

(b) you have no arrangement or understanding with any person to participate in the distribution of old notes or new notes within the meaning of the Securities Act;

(c) you are not an “affiliate,” as such term is defined under Rule 405 promulgated under the Securities Act, of the Issuers; and

(d) if you are a broker-dealer, that you will receive the new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities and that you acknowledge that you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your old notes registered in the shelf registration statement described in the Registration Rights Agreement, dated as of November 23, 2010 (the “Registration Rights Agreement”), by and among the Issuers, the several guarantors named therein, and the Placement Agents (as defined therein), on behalf of the purchasers of the old notes. Such election may be made by notifying the Issuers in writing at 11451 Katy Freeway, Suite 500, Houston, Texas 77009. By making such election, you agree, as a holder of old notes participating in a shelf registration, to indemnify and hold harmless the Issuers, each of the directors of the Issuers, each of the officers of the Issuers who signs such shelf registration statement, each person who controls the Issuers within the meaning of either the

Index to Financial Statements

Securities Act or the Exchange Act, and each other holder of old notes, from and against any and all losses, claims, damages or liabilities caused by any untrue statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to you furnished in writing by or on behalf of you expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provision of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.

Index to Financial Statements

Any confirmation of a book-entry transfer to the Exchange Agent’s account at DTC of old notes tendered by book-entry transfer (a “Book-Entry Confirmation”), as well as Agent’s Message and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at one of its addresses set forth herein prior to 5:00 p.m., New York City time, on the Expiration Date.

Tenders of old notes will be accepted only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The entire principal amount of old notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all old notes is not tendered, then old notes for the principal amount of old notes not tendered and new notes issued in exchange for any old notes accepted will be delivered to the holder via the facilities of DTC promptly after the old notes are accepted for exchange.

All questions as to the validity, form, eligibility (including time of receipt), acceptance, and withdrawal of tendered old notes will be determined by the Issuers, in their sole discretion, which determination will be final and binding. The Issuers reserve the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Issuers, be unlawful. The Issuers also reserve the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any old notes. The Issuers’ interpretation of the terms and conditions of the Exchange Offer (including the instructions on the Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as the Issuers shall determine. Although the Issuers intend to notify holders of defects or irregularities with respect to tenders of old notes, neither the Issuers, the Exchange Agent, nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any old notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders, unless otherwise provided in the Letter of Transmittal, promptly following the Expiration Date.

The Issuers reserve the absolute right to waive, in whole or part, up to the expiration of the Exchange Offer, any of the conditions to the Exchange Offer set forth in the Prospectus or in this Letter of Transmittal.

No alternative, conditional, irregular or contingent tender of old notes will be accepted.

Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent using the contact information set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.

Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption “Exchange Offer—Withdrawal of Tenders.”

Index to Financial Statements

IMPORTANT: BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

Index to Financial Statements

Black Elk Energy Offshore Operations, LLC is a limited liability company formed under the Texas Business Organizations Code (the “TBOC”). Black Elk Energy Finance Corp. is a corporation formed under the TBOC.

Sections 8.051 and 8.105(b) of Chapter 8 of the TBOC provide that a corporation or limited liability company shall indemnify a person who is or was a director, officer, manager of a manager-managed limited liability company or member of a member-managed limited liability company, or any of the foregoing who serve at the request of the corporation or limited liability company as a director, officer, venturer, proprietor, partner, trustee, administrator, employee, agent, or similar functionary of another enterprise, organization or employee benefit plan, against reasonable expenses actually incurred by such person in connection with a proceeding in which the person is a respondent because the person is or was serving in such a capacity if the person is wholly successful, on the merits or otherwise, in the defense of the proceeding.

Sections 8.101, 8.102 and 8.105 of Chapter 8 of the TBOC also provide generally that a person sued as a director, officer, manager of a manager-managed limited liability company, member of a member-managed limited liability company, employee or agent of a corporation or limited liability company, or while serving at the request of the corporation or limited liability company as a director, officer, venturer, proprietor, partner, trustee, administrator, employee, agent, or similar functionary of another enterprise, organization or employee benefit plan, may be indemnified by the corporation or limited liability company against judgments and reasonable court costs, penalties, fines, settlements, excise or similar taxes, and attorney’s fees if it is determined that such person has conducted himself in good faith and reasonably believed, in the case of conduct in his official capacity with the entity, that his conduct was in the entity’s best interests, and in all other cases, that his conduct was at least not opposed to the entity’s best interests (and, in the case of any criminal proceeding, had no reasonable cause to believe his conduct was unlawful). Section 8.104 of the TBOC provides that a corporation or limited liability company may advance expenses incurred by a director, officer, manager of a manager-managed limited liability company or member of a member-managed limited liability company, or any of the foregoing who serve at the request of the corporation or limited liability company as a director, officer, venturer, proprietor, partner, trustee, administrator, employee, agent, or similar functionary of another enterprise, organization or employee benefit plan, in defending a suit or similar proceeding. Pursuant to Section 8.105 of the TBOC, a Texas corporation or limited liability company is also permitted to indemnify and advance expenses to officers, employees and agents who are not directors, managers of a manager-managed limited liability company, or members of a member-managed limited liability company to such extent as may be provided by its certificate of formation, by-laws, actions of its board of directors or managers, resolutions of its shareholders or members, or contract or required by common law. Section 8.102 of the TBOC provides that indemnification of a person found liable to the corporation or limited liability company or found liable on the basis that a personal benefit was improperly received by him is limited to reasonable expenses actually incurred by the person in connection with the proceeding (not including a judgment, penalty, fine or excise or similar tax), and shall not be made if the person is found liable for (1) willful or intentional misconduct in the performance of his duty to the entity, (2) breach of the person’s duty of loyalty owed to the entity; or (3) an act or omission not committed in good faith that constitutes a breach of a duty owed by the person to the entity.

Section 8.151 of the TBOC also authorizes a corporation or limited liability company to purchase and maintain insurance on behalf of any person who is or was a director, officer, manager of a manager-managed limited liability company, member of a member-managed limited liability company, employee or agent of the corporation or limited liability company, or who is or was serving at the request of the corporation or limited liability company as a director, officer, venturer, proprietor, partner, trustee, administrator, employee, agent or

Index to Financial Statements

similar functionary of another enterprise, organization or employee benefit plan, against any liability asserted against him and incurred by him in such a capacity or arising out of his status as such, whether or not the corporation or limited liability company would have the power to indemnify him against that liability under Chapter 8 of the TBOC.

Section 7.001 of the TBOC provides that a corporation’s certificate of formation may limit or eliminate a director’s liability for monetary damages to the corporation or its shareholders for an act or omission in the director’s capacity as a director, except that no limitation or elimination of liability is permitted to the extent the director is found liable for a breach of the duty of loyalty, an act or omission not in good faith that constitutes a breach of duty or involves intentional misconduct or a knowing violation of the law, a transaction involving an improper personal benefit to the director, or an act or omission for which liability is expressly provided by an applicable statute.

In addition, Section 101.402 of the TBOC provides that a limited liability company may (1) indemnify a member, manager, officer, or assignee of a membership interest in the company, (2) pay in advance or reimburse expenses incurred by such person, and (3) purchase or procure or establish and maintain insurance or another arrangement to indemnify or hold harmless such person.

Section 11.3 of the Second Amended and Restated Limited Liability Company Operating Agreement (as amended) of Black Elk Energy Offshore Operations, LLC (the “Operating Agreement”) authorizes the Company to make any tax payments or withhold any amount required by federal, state, local law or non-U.S. law on behalf of or with respect to any Member. If the Company is obligated to make any payment because of a Member, then such Member (the “Indemnifying Member”) is then required to indemnify the Company in full for the entire amount paid. The Company may collect this amount by charging the Capital Account of the Indemnifying Member, requiring a cash payment by the Indemnifying Member, or reducing current or subsequent distributions that would otherwise be made to the Indemnifying Member until it has recovered the amount to be indemnified. A Member’s obligation to make contributions to the Company under this section shall survive the termination, dissolution, liquidation and winding-up of the Company. The Company may pursue and enforce all rights and remedies against any Member including instituting a lawsuit to collect such payments with interest.

Article Sixteen of the Operating Agreement provides that the Company shall indemnify and hold harmless any Covered Person, Member, Manager, officer and Affiliate thereof (individually, in each case, an “Indemnitee”) to the fullest extent permitted by law from and against any losses, claims, demands, costs, damages, liabilities (joint or several) and expenses of any nature. However, this provision shall not eliminate or limit the liability of an Indemnitee, subject to the limitations set forth elsewhere in this Agreement with regard to Excused Persons, (i) for any breach of the Indemnitee’s duty of loyalty to the Company or its Members, (ii) for acts or omissions which involve intentional misconduct or a knowing violation of law or (iii) for any transaction from which the Indemnitee received any improper personal benefit.

In addition, Article Sixteen of the Operating Agreement sets forth the responsibility of the Manager to act in good faith and outlines the limitation of indemnification liability. Full indemnity is provided unless a court of competent jurisdiction has rendered a final determination that an Indemnitee has committed fraud, willful misconduct or a bad faith violation of such Indemnitee’s implied contractual covenant of good faith and fair dealing.

Article Sixteen of the Operating Agreement also provides for advancement of legal expenses incurred by the Indemnitee for defending any claim, demand, action, suit, or proceeding subject to this article. If it is determined in a judicial proceeding or binding arbitration that such Indemnitee is not entitle to be indemnified, the Indemnitee shall repay the amount of the advance.

Index to Financial Statements

The indemnification provided under the Operating Agreement shall be in addition to any rights to which an Indemnitee may be entitled under any agreement, vote of the Board, or matter of law or equity regardless of the Indemnitee’s capacity and shall continue after the Indemnitee has ceased to serve. The indemnification shall also inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

The Operating Agreement also requires the Company to obtain from financially sound and reputable insurers “directors and officers” insurance covering the actions and omissions of the Managers and officers of the Company with coverage customary for companies similarly situated to the Company. The Company will cause to be maintained such insurance required by this section and shall not be cancelled by the Company without prior approval of the Board.

Article VI, Section 1 of the Bylaws of Black Elk Energy Finance Corp. (the “Bylaws”) asserts that each person who is or was serving at the request of the Corporation as director or officer shall by indemnified by the Corporation to the fullest extent permitted by the TBOC. Indemnification under this article shall continue as to a person who has ceased to serve in the capacity which initially entitled such person to indemnity. These rights shall be deemed contract rights, and no amendment, modification or repeal of Article VI shall have the effect of limiting or denying any such rights with respect to actions taken or proceedings arising prior to any such amendment, modification or repeal. The Bylaws expressly provide that indemnification could involve indemnification for negligence or under theories of strict liability.

Article VI, Section 2 includes the right to be paid or reimbursed by the Corporation the reasonable expenses incurred by the indemnified person under section one who was, is or is threatened to be made a named defendant or respondent in a proceeding in advance of the final disposition of the proceeding. The Corporation must receive a written affirmation by the indemnified person indicating their good faith belief that he or she has met the standard of conduct necessary for indemnification and a written undertaking to repay all amounts if it is ultimately found that such person is not entitled to indemnification.

Under Article VI, Section 3, employees and agents of the Corporation may receive indemnification to the extent given to directors and officers by adoption of a resolution by the Board of Directors. Section 4 authorizes the Corporation to pay or reimburse expenses incurred by a director or officer in connection with his or her appearance as a witness or other participant in a proceeding at a time when he or she is not a names defendant or respondent in the proceeding.

The right to indemnification and the advancement and payment of expenses shall not be exclusive of any other right which a director or officer or other person indemnified may already have or will acquire under any law (common or statutory), provision of the Certificate of Formation of the Corporation or under the Bylaws, agreement, vote of shareholders or disinterested directors or otherwise.

The Corporation is also required to purchase and maintain insurance, at its expense, to protect itself and any person it indemnifies under Article VI.

If Article VI is deemed invalid by any court of competent jurisdiction, the Corporation shall nevertheless indemnify and hold harmless each person indemnified under such article.

Shareholders must be notified, to the extent applicable by law, of any indemnification of or advance of expenses to a director or officer in accordance with Article VI.

Index to Financial Statements

Black Elk Energy Offshore Operations, LLC maintains, at its expense, policies of insurance which insure its member, manager and officers, subject to exclusions and deductions as are usual in these kinds of insurance policies, against specified liabilities which may be incurred in those capacities.

The exhibits required to be filed pursuant to the requirements of Item 601 of Regulation S-K are set forth in the Index to the Exhibits accompanying this registration statement.

Schedules are omitted because they either are not required or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrants, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of a registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, such registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof;

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering;

Index to Financial Statements

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, if such registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use;

(5) That, for the purpose of determining liability of such registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, in a primary offering of securities of such registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(6) To respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request; and

(7) To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

Index to Financial Statements

Pursuant to the requirements of the Security Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on June 29, 2011.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.

Index to Financial Statements

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.

Index to Financial Statements

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.


Texas	1311	38-3769404
Texas	1311	80-0656113
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)


Large accelerated filer	¨		Accelerated filer	¨

Non-accelerated filer	x	(Do not check if a smaller reporting company)	Smaller reporting company	¨


	Oil Reserves (MBbls)
Balance, December 31, 2009		3,268
Production		(986	)
Purchases of reserves in-place		4,600
Extensions, discoveries and improved recovery		1,067
Transfers/sales of reserves in place		—
Revisions of previous estimates		2,308

Balance, December 31, 2010		10,257


	Natural Gas Reserves (MMcf)
Balance, December 31, 2009		20,114
Production		(7,997	)
Purchases of reserves in-place		37,021
Extensions, discoveries and improved recovery		11,242
Transfers/sales of reserves in place		—
Revisions of previous estimates		8,218

Balance, December 31, 2010		68,598


	Total Oil and Natural Gas Equivalent (MBoe)⁽¹⁾
Balance, December 31, 2009		6,620
Production		(2,319	)
Purchases of reserves in-place		10,770
Extensions, discoveries and improved recovery		2,941
Transfers/sales of reserves in place		—
Revisions of previous estimates		3,678

Balance, December 31, 2010		21,690


	December 31, 2010
	(in thousands)
Standardized Measure
Future cash inflows	$	1,104,561
Future costs:
Production		318,974
Development		99,286
Dismantlement and abandonment		179,499
Income taxes ⁽¹⁾		11,591

Future net cash inflows before 10% discount		495,211
10% annual discount factor		103,022

	$	392,189


	Page
About This Prospectus		ii
Cautionary Note Regarding Forward-Looking Statements		iii
Prospectus Summary		1
Summary Historical Financial Data		10
Summary Reserve and Operating Data		12
Risk Factors		13
The Exchange Offer		40
Ratios of Earnings to Fixed Charges		46
Use of Proceeds		47
Supplemental Oil and Gas Disclosures		48
Selected Financial and Other Data		50
Unaudited Pro Forma Financial Information		52
Management’s Discussion and Analysis of Financial Condition and Results of Operations		56
Business		80
Management and Corporate Governance		99
Executive Compensation		102
Security Ownership of Certain Beneficial Owners and Management		110
Certain Relationships and Related Transactions		114
Description of Other Indebtedness		116
Description of Notes		119
Book-Entry; Delivery and Form		175
Certain United States Federal Income Tax Considerations		178
Plan of Distribution		179
Legal Matters		181
Experts		181
Independent Petroleum Engineers		181
Available Information		181
Glossary of Oil and Natural Gas Terms		183

Index to Consolidated Financial Statements		F-1
Annex A: Letter of Transmittal.		A-1


	Historical March 31, 2011			Pro Forma Adjustments for Merit Acquisition			Pro Forma March 31, 2011
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	15,524		$	(1,060	)^(1),(2),(3)	$	14,464
Accounts receivable, net		33,158			—			33,158
Due from affiliates		520			—			520
Prepaid expenses and other		13,011			96	⁽³⁾		13,107

TOTAL CURRENT ASSETS		62,213			(964	)		61,249

OIL AND GAS PROPERTIES, NET		131,474			123,950	⁽⁴⁾		255,424
OTHER PROPERTY AND EQUIPMENT, NET		1,322			—			1,322
OTHER ASSETS
Debt issue costs, net		9,025			—			9,025
Restricted cash		2,750			—			2,750
Escrow for abandonment costs		115,023			32,956	⁽³⁾		147,979
Other assets		50			—			50

TOTAL OTHER ASSETS		126,848			32,956			159,804

TOTAL ASSETS	$	321,857		$	155,942		$	477,799

LIABILITIES AND MEMBERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	30,624		$	—		$	30,624
Derivative liabilities		20,423			—			20,423
Asset retirement obligations		7,565			—			7,565
Current portion of long-term debt and notes payable		36			—			36

TOTAL CURRENT LIABILITIES		58,648			—			58,648

LONG-TERM LIABILITIES
Gas imbalance payable		5,313			314	⁽³⁾		5,627
Derivative liabilities		26,011			—			26,011
Asset retirement obligations, net of current portion		129,784			90,628	⁽³⁾		220,412
Long-term debt, net of current portion		148,732			35,000	⁽²⁾		183,732

TOTAL LONG-TERM LIABILITIES		309,840			125,942			435,782

TOTAL LIABILITIES		368,488			125,942			494,430
COMMITMENTS AND CONTINGENCIES
MEMBERS’ DEFICIT		(46,631	)		30,000	⁽¹⁾		(16,631	)

TOTAL LIABILITIES AND MEMBERS’ DEFICIT	$	321,857		$	155,942		$	477,799


	Historical Three Months Ended March 31, 2011			Pro Forma Adjustments for Merit Acquisition			Pro Forma Three Months Ended March 31, 2011
	(in thousands)
Crude oil, natural gas and plant product sales	$	55,827		$	31,454	⁽¹⁾	$	87,281
Realized gain (loss) on derivative financial statements		(336	)		—			(336	)
Unrealized gain (loss) on derivative financial statements		(30,978	)		—			(30,978	)

Total revenues		24,513			31,454			55,967

Lease operating expenses		26,252			21,728	⁽¹⁾		47,980
Depreciation, depletion and amortization		7,994			4,365	⁽²⁾		12,359
General and administrative expense		4,525			600	⁽³⁾		5,125
Accretion expense		3,938			912	⁽⁴⁾		4,850

Total cost and expenses		42,709			27,605			70,314

Operating income (loss)		(18,196	)		3,849			(14,347	)
Other income (expense)		(5,923	)		(455	)⁽⁵⁾		(6,378	)

Net income (loss)	$	(24,119	)	$	3,394		$	(20,725	)


	Historical Year Ended December 31, 2010			Pro Forma Adjustments for Nippon Acquisition			Pro Forma Adjustments for Merit Acquisition			Pro Forma Year Ended December 31, 2010
	(in thousands)
Crude oil, natural gas and plant product sales	$	112,565		$	71,902	⁽¹⁾	$	118,588	⁽⁵⁾	$	303,055
Realized gain (loss) on derivative financial statements		9,271			—			—			9,271
Unrealized gain (loss) on derivative financial statements		(12,700	)		—			—			(12,700	)

Total revenues		109,136			71,902			118,588			299,626

Lease operating expenses		59,555			26,423	⁽¹⁾		75,430	⁽⁵⁾		161,408
Exploration expense		14			—			—			14
Depreciation, depletion and amortization		29,795			6,477	⁽²⁾		18,994	⁽⁶⁾		55,266
Impairment expense		6,406			—			—			6,406
General and administrative expense		14,588			1,914	⁽³⁾		2,400	⁽⁷⁾		18,902
Accretion expense		9,175			5,252	⁽⁴⁾		3,647	⁽⁸⁾		18,074

Total cost and expenses		119,533			40,066			100,471			260,070

Operating income (loss)		(10,397	)		31,836			18,117			39,556
Other income (expense)		(13,501	)		—			(1,867	)⁽⁹⁾		(15,368	)

Net income (loss)	$	(23,898	)	$	31,836		$	16,250		$	24,188


	Three Months Ended March 31,					Year Ended December 31,				Period from Inception (January 29, 2008) through December 31, 2008
	2011		2010			2010		2009
Oil:
Average price before effects of hedges ($/Bbl)⁽¹⁾	$	99.49	$	75.98		$	80.09	$	70.43	$	99.51
Average price after effects of hedges ($/Bbl)		93.15		77.31			80.97		71.59		99.51
Average price differentials⁽²⁾		5.03		(2.86	)		0.59		8.44		(0.41	)

Gas:
Average price before effects of hedges ($/Mcf)⁽¹⁾	$	4.52	$	5.34		$	4.38	$	4.29	$	8.87
Average price after effects of hedges ($/Mcf)		5.13		6.31			5.44		4.55		8.87
Average price differentials⁽²⁾		0.34		0.25			0.00		0.34		(0.02	)


	Three Months Ended March 31,					Year Ended December 31,					Period from Inception (January 29, 2008) through December 31, 2008
	2011			2010		2010			2009
Average daily sales:
Oil (Boepd)		4,178			2,039		2,348			385		97
Natural gas (Mcfpd)		37,165			16,846		21,911			6,695		2,918
Plant products (Gal/d)		23,760			5,792		14,802			876		—
Oil equivalents (Boepd)		10,938			4,984		6,353			1,521		584

Average realized prices⁽¹⁾
Oil ($/Bbl)	$	93.15		$	77.31	$	80.97		$	71.59	$	99.51
Natural gas ($/Mcf)		5.13			6.31		5.44			4.55		8.87
Plant products ($/Gallon)		1.01			1.07		1.10			1.32		—
Oil equivalents ($/Boe)		55.20			54.18		52.54			38.88		60.96
Lease operating expense ($/Boe)		23.43			15.24		23.56			15.55		18.34
Production tax expense ($/Boe)		0.03			0.14		0.28			0.96		2.05
General and administrative expense ($/Boe)		4.60			4.52		6.29			12.90		15.81
Net income (loss) (in thousands)		(24,119	)		5,261		(23,898	)		663		4,233
Adjusted EBITDA⁽²⁾ (in thousands)		24,584			15,207		47,050			4,617		(405	)


	Three Months Ended March 31,						Year Ended December 31,						Period from Inception (January 29, 2008) through December 31, 2008
	2011			2010			2010			2009
REVENUES
Oil sales	$	37,412,050		$	13,942,501		$	68,653,899		$	9,887,392		$	3,546,195
Natural gas sales		15,106,514			8,090,595			34,998,500			10,480,414			9,477,778
Plant product sales and other income		3,308,633			1,298,426			8,912,516			420,590			—
Realized (loss) gain on derivative financial instruments		(335,913	)		1,713,747			9,271,399			800,501			—
Unrealized (loss) gain on derivative financial instruments ...		(30,977,999	)		753,084			(12,699,958	)		(2,756,000	)		—

		24,513,285			25,798,353			109,136,356			18,832,897			13,023,973
OPERATING EXPENSES
Lease operating		23,060,406			6,836,368			54,626,926			8,634,750			3,917,729
Production taxes		29,300			62,176			640,015			533,453			438,797
Workover		3,162,787			436,749			4,287,745			873,991			5,638,352
Exploration		(29	)		475,474			13,836			46,864			79,418
Depreciation, depletion and amortization		7,994,130			6,630,233			29,794,692			15,419,325			3,316,110
Impairment		—			—			6,406,551			446,361			—
General and administrative		4,524,616			2,027,228			14,588,331			7,164,329			3,377,386
Gain due to involuntary conversion of asset		—			—			—			(18,718,357	)		(9,526,449	)
Accretion		3,938,262			1,831,805			9,175,357			387,707			421,572

TOTAL OPERATING EXPENSES		42,709,472			18,300,033			119,533,453			14,788,423			7,662,915

(LOSS) INCOME FROM OPERATIONS		(18,196,187	)		7,498,320			(10,397,097	)		4,044,474			5,361,058

OTHER INCOME (EXPENSE)
Interest income		6,764			31			128,607			281,073			9,610
Miscellaneous (expense) income		(136,336	)		—			(757,021	)		—			12,017
Interest expense		(5,793,084	)		(2,237,368	)		(12,872,094	)		(3,662,074	)		(1,149,716	)

TOTAL OTHER INCOME (EXPENSE)		(5,922,656	)		(2,237,337	)		(13,500,508	)		(3,381,001	)		(1,128,089	)

NET (LOSS) INCOME	$	(24,118,843	)	$	5,260,983		$	(23,897,605	)	$	663,473		$	4,232,969

PRODUCTION:
Oil (MBbl)		376			183			857			140			36
Natural gas (MMcf)		3,345			1,516			7,997			2,444			1,068
Plant products (Gal)		2,138			521			5,403			320			—
Total (MBoe)		984			449			2,319			555			214


	Payments Due by Period
	Total		Less than 1 Year		1-3 Years		4-5 Years		After 5 Years
	(in thousands)
Contractual Obligations
Total debt	$	152,070	$	2,070	$	—	$	150,000	$	—
Interest on long-term debt		103,583		21,083		41,250		41,250
Operating leases⁽¹⁾		5,168		703		1,355		951		2,179

Total contractual obligations	$	260,821	$	23,856	$	42,585	$	192,201	$	2,179
Other Obligations
Asset retirement obligations		122,242		1,023		79,465		18,140		23,614

Total obligations	$	383,063	$	24,879	$	122,050	$	210,341	$	25,793


Remaining Contract Term: Oil	Contract Type	Notational Volume in Bbls/Month		NYMEX Strike Price
April 2011 – December 2011	Swap		25,400	$	81.22
January 2012 – December 2012	Swap		17,050	$	81.22
April 2011 – December 2011	Swap		2,600	$	81.14
January 2012 – December 2012	Swap		1,900	$	81.14
April 2011 – December 2011	Swap		200	$	83.50
January 2012 – July 2012	Swap		200	$	83.50
April 2011 – December 2011	Swap		41,500	$	85.90
January 2012 – December 2012	Swap		27,500	$	85.90
January 2013 – December 2013	Swap		19,750	$	85.90
January 2014 – December 2014	Swap		15,000	$	65.00
April 2011 – December 2011	Swap		45,000	$	96.90
January 2012 – December 2012	Swap		23,000	$	96.90
January 2013 – December 2013	Swap		27,750	$	96.90
January 2014 – February 2014	Swap		19,000	$	96.90


Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month		NYMEX Strike Price
April 2011 – December 2011	Swap		6,250	$	5.89
January 2012 – July 2012	Swap		5,250	$	5.89
April 2011 – December 2011	Swap		78,500	$	5.70
January 2012 – July 2012	Swap		53,000	$	5.70
April 2011 – December 2011	Swap		93,569	$	5.89
January 2012 – December 2012	Swap		26,838	$	5.89
April 2011 – December 2011	Swap		321,000	$	5.00
January 2012 – December 2012	Swap		112,000	$	5.00
January 2013 – December 2013	Swap		47,000	$	5.00
April 2011 – December 2011	Swap		350,000	$	4.595
January 2012 – December 2012	Swap		227,000	$	4.595
January 2013 – December 2013	Swap		104,000	$	4.595
January 2014 – February 2014	Swap		82,000	$	4.595


Remaining Contract Term: Natural Gas	Contract Type	Notational Volume in MMBtus/Month		NYMEX Strike Price
July 2011 – December 2011	Swap		549,637	$	4.94
January 2012 – December 2012	Swap		318,958	$	4.94
January 2013 – December 2013	Swap		200,669	$	4.94
January 2014 – June 2014	Swap		129,960	$	4.94


	SEC Pricing 12/31/2010
	Effective 12/31/2010
	Reserve Category
	PDP		PDNP		PUD		Total
Net Proved Reserves
Oil (MBbls)		5,239		2,658		2,360		10,257
Natural gas (MMcf)		21,764		33,243		13,591		68,598
Future Net Revenues
Oil	$	407,346	$	201,024	$	180,015	$	788,385
Gas		99,150		153,421		63,606		316,177

Total Revenues		506,496		354,445		243,621		1,104,562
Production Costs⁽¹⁾		165,817		116,211		48,537		330,565
Dev and P&A costs		179,499		45,907		53,378		278,784

Future net cash flows		161,180		192,327		141,706		495,213

PV-10⁽²⁾⁽³⁾	$	155,807	$	148,543	$	87,839	$	392,189


	Developed acres				Undeveloped acres				Total
	Gross		Net		Gross		Net		Gross		Net
Offshore⁽¹⁾		368,346		141,855		16,456		13,956		384,802		155,811
Total		368,346		141,855		16,456		13,956		384,802		155,811


	2011				2012				2013
	Gross		Net		Gross		Net		Gross		Net
Offshore⁽¹⁾		11,456		11,456		5,000		2,500		—		—
Total		11,456		11,456		5,000		2,500		—		—


	Average Net Daily Production for the Year Ended December 31, 2009						Average Net Daily Production for the Year Ended December 31, 2010
	Bbls		Mcf		Boe		Bbls		Mcf		Boe
Offshore⁽¹⁾		406		6,695		1,521		2,700		21,911		6,353


	Year Ended December 31,
Customer	2010			2009
Conoco Phillips Company		14	%		18	%
Shell Trading (US) Company		52	%		46	%
Katrina Energy, LLC		—			28	%


Name	Age		Title
John Hoffman		53	President and Chief Executive Officer and Manager of Black Elk Energy Offshore Operations, LLC
James Hagemeier		43	Vice President and Chief Financial Officer and Manager of Black Elk Energy Offshore Operations, LLC
Doug Fehr		56	Vice President, Facilities
Arthur Garza		45	Chief Technical Officer
Carl Hammond		54	Chief Well Officer
Daniel Small		42	Manager of Black Elk Energy Offshore Operations, LLC


Name and Principal Position	Year		Salary ($)⁽¹⁾		Bonus ($)⁽²⁾		Non-Equity Incentive Plan Compensation ($)⁽³⁾		All Other Compensation ($)⁽⁴⁾		Total $
John Hoffman, CEO		2010	$	300,000	$	1,760,200		—	$	62,549	$	2,122,749
James Hagemeier, CFO		2010	$	250,000	$	1,186,800		—	$	16,368	$	1,453,168
Arthur Garza, CTO		2010	$	235,000	$	155,000	$	61,469	$	12,044	$	463,513
Carl Hammond, CWO		2010	$	200,000	$	54,000	$	64,768	$	9,500	$	328,268
Doug Fehr, VPF		2010	$	250,000	$	47,000	$	73,772	$	22,935	$	393,707


	Grant Date		Non-Equity Incentive Plan Awards: Right to Percentage of Distributable Income⁽¹⁾
John Hoffman, CEO		—		—
James Hagemeier, CFO		—		—
Arthur Garza, CTO		August 19, 2010		1.4	%
Carl Hammond, CWO		August 19, 2010		0.8	%
Doug Fehr, VPF		August 19, 2010		1.0	%


	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	$	82,825	$	382,825
James Hagemeier, CFO	$	250,000	$	36,906	$	286,906


Name and Address of Beneficial Owner⁽¹⁾	Number of Class A Units Beneficially Owned		Number of Class B Units Beneficially Owned		Percentage of Voting Membership Interests Beneficially Owned⁽²⁾
Manager and Named Executive Officers⁽³⁾:
John Hoffman⁽⁴⁾		—		918.57		9.07	%
James Hagemeier⁽⁵⁾		—		484.21		4.80	%
Dan Small		—		—		0	%
Arthur Garza⁽⁶⁾		—		5.50		*
Carl Hammond⁽⁷⁾		—		21.45		*
Doug Fehr⁽⁸⁾		—		21.45		*
All Managers and Executive Officers as a Group (Six persons)		—		1,451.18		13.10	%
5% Beneficial Owners:
Black Elk Management, LLC^(4)(5)(9)		—		1,271.88		11.49	%
PPVA Black Elk (Equity) LLC⁽¹⁰⁾		136.13		6,000.00		48.59	%
PPVA Black Elk (Investor) LLC⁽¹¹⁾		—		2,191.91		18.35	%


*Consolidated Financial Statements—December 31, 2010 and 2009*
Report of Independent Registered Public Accounting Firm			F-3
Consolidated Balance Sheets			F-4
Consolidated Statements of Operations			F-5
Consolidated Statements of Members’ Equity (Deficit)			F-6
Consolidated Statements of Cash Flows			F-7
Notes to Consolidated Financial Statements			F-8

*Consolidated Financial Statements—March 31, 2011 and 2010 (Unaudited)*
Consolidated Balance Sheets			F-30
Consolidated Statements of Operations			F-31
Consolidated Statements of Cash Flows			F-32
Notes to Consolidated Financial Statements			F-33

*Statements of Combined Revenues and Direct Operating Expenses—10 Month Period Ended October 31, 2009 and Year Ended December 31, 2008 (W&T)*
Report of Independent Auditors			F-45
Statements of Combined Revenues and Direct Operating Expenses			F-46
Notes to Statements of Combined Revenues and Direct Operating Expenses			F-47

*Statements of Combined Revenues and Direct Operating Expenses—9 Month Periods Ended September 30, 2010 and 2009 and Years Ended December 31, 2009 and 2008 (Nippon)*
Report of Independent Auditors			F-52
Statements of Combined Revenues and Direct Operating Expenses			F-53
Notes to Statements of Combined Revenues and Direct Operating Expenses			F-54

*Statements of Revenues and Direct Operating Expenses—Three Months Ended March 31, 2011 and 2010 (Unaudited) and Years Ended December 31, 2010, 2009 and 2008 (Merit Energy)*
Independent Auditors’ Report			F-59
Statements of Revenues and Direct Operating Expenses			F-60
Notes to Statements of Revenues and Direct Operating Expenses			F-61


	At December 31,
	2010			2009
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	18,879,470		$	6,235,902
Accounts receivable, net		26,092,429			10,501,652
Due from affiliates		435,138			22,430
Prepaid expenses		13,122,492			510,780

TOTAL CURRENT ASSETS		58,529,529			17,270,764

OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $55,119,435 and $19,117,134 at December 31, 2010 and 2009, respectively		123,783,292			88,600,111

OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $263,604 and $64,662 at December 31, 2010 and 2009, respectively		1,152,286			482,887

OTHER ASSETS
Restricted cash		—			521,797
Debt issue costs, net		8,870,818			632,308
Derivative assets		—			569,386
Escrow for abandonment costs		114,167,803			5,932,049

TOTAL OTHER ASSETS		123,038,621			7,655,540

TOTAL ASSETS	$	306,503,728		$	114,009,302

LIABILITIES AND MEMBERS’ EQUITY

CURRENT LIABILITIES
Accounts payable and accrued expenses	$	34,110,761		$	11,423,961
Derivative liabilities		3,754,423			1,800,950
Asset retirement obligations		1,022,733			960,800
Current portion of long-term debt and notes payable		2,069,541			67,655

TOTAL CURRENT LIABILITIES		40,957,458			14,253,366

LONG-TERM LIABILITIES
Gas imbalance payable		4,552,171			2,041,942
Derivative liabilities		11,701,535			1,524,436
Asset retirement obligations, net of current portion		121,219,065			50,402,015
Long-term debt, less current portion, net of discount $1,316,181 and $0 at December 31, 2010 and 2009, respectively		148,683,819			40,064,991

TOTAL LONG-TERM LIABILITIES		286,156,590			94,033,384

TOTAL LIABILITIES		327,114,048			108,286,750

COMMITMENTS AND CONTINGENCIES

MEMBERS’ (DEFICIT) EQUITY		(20,610,320	)		5,722,552

TOTAL LIABILITIES AND MEMBERS’ EQUITY	$	306,503,728		$	114,009,302


	Year Ended December 31, 2010			Year Ended December 31, 2009			Period from Inception (January 29, 2008) through December 31, 2008
REVENUES
Oil sales	$	68,653,899		$	9,887,392		$	3,546,195
Natural gas sales		34,998,500			10,480,414			9,477,778
Plant product sales and other income		8,912,516			420,590			—
Realized gain on derivative financial instruments		9,271,399			800,501			—
Unrealized loss on derivative financial instruments		(12,699,958	)		(2,756,000	)		—

TOTAL REVENUES		109,136,356			18,832,897			13,023,973

OPERATING EXPENSES
Lease operating		54,626,928			8,634,750			3,917,729
Production taxes		640,015			533,453			438,797
Workover		4,287,745			873,991			5,638,352
Exploration		13,836			46,864			79,418
Depreciation, depletion and amortization		29,794,692			15,419,325			3,316,110
Impairment		6,406,551			446,361			—
General and administrative		14,588,329			7,164,329			3,377,386
Gain due to involuntary conversion of asset		—			(18,718,357	)		(9,526,449	)
Accretion		9,175,357			387,707			421,572

TOTAL OPERATING EXPENSES		119,533,453			14,788,423			7,662,915

(LOSS) INCOME FROM OPERATIONS		(10,397,097	)		4,044,474			5,361,058

OTHER INCOME (EXPENSE)
Interest income		128,607			281,073			9,610
Miscellaneous (expense) income		(757,021	)		—			12,017
Interest expense		(12,872,094	)		(3,662,074	)		(1,149,716	)

TOTAL OTHER INCOME (EXPENSE)		(13,500,508	)		(3,381,001	)		(1,128,089	)

NET (LOSS) INCOME	$	(23,897,605	)	$	663,473		$	4,232,969


	Members’ Capital			Retained Earnings (Accumulated Deficit)			Total Members’ Equity (Deficit)
Balance at inception (January 29, 2008)	$	—		$	—		$	—
Contributions		1,110,000			—			1,110,000
Distributions		(423,890	)		—			(423,890	)
Net income		—			4,232,969			4,232,969

Balance at December 31, 2008	$	686,110		$	4,232,969		$	4,919,079
Contributions		140,000			—			140,000
Net income		—			663,473			663,473

Balance at December 31, 2009		826,110			4,896,442			5,722,552
Distribution		(2,435,267	)					(2,435,267	)
Net loss					(23,897,605	)		(23,897,605	)

Balance at December 31, 2010	$	(1,609,157	)	$	(19,001,163	)	$	(20,610,320	)


	Year Ended December 31,
	($ in thousands)
2011	$	1,978
2012		1,978
2013		1,978
2014		1,614
2015		1,323

	$	8,871


	*(in thousands)*
Oil and gas properties	$	35,326
less:
Gas imbalances		2,041
Asset retirement obligations		57,150

Cash received	$	(23,865	)


	September 1, 2010 through December 31, 2010
	(in thousands)
Revenues	$	23,230
Earnings*		11,843


	*(in thousands)*
Oil and gas properties	$	10,462
less:
Asset retirement obligations		5,761

Cash paid	$	4,701


	*(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