Milagro Oil & Gas 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)

RegistrationNo. 333-177534

PROSPECTUS

Milagro Oil & Gas, Inc.

Offer to Exchange
$250,000,000 10.500% Senior Secured Second Lien Notes due 2016
and the guarantees thereof, that have been registered under
the Securities Act of 1933 for any and all
$250,000,000 10.500% Senior Secured Second Lien Notes due 2016
and the guarantees thereof,
This Exchange Offer will expire at 5:00 P.M.,
New York City time, on December 13, 2011, unless extended.

We are offering, upon the terms and subject to the conditions set forth in this prospectus and the accompanying letter of transmittal (which together constitute the “exchange offer”), to exchange up to $250,000,000 aggregate principal amount of our registered 10.500% Senior Secured Second Lien Notes due 2016 and the guarantees thereof, or the exchange notes, for a like principal amount of our outstanding 10.500% Senior Secured Second Lien Notes due 2016 and the guarantees thereof, or the old notes. We refer to the old notes and the exchange notes collectively as the “notes.” The terms of the exchange notes and the guarantees thereof are identical to the terms of the old notes and the guarantees thereof in all material respects, except for the elimination of certain transfer restrictions, registration rights and additional interest provisions relating to the old notes.

We will exchange any and all old notes that are validly tendered and not validly withdrawn prior to 5:00 p.m., New York City time, on December 13, 2011, unless extended.

We have not applied, and do not intend to apply, for listing the notes on any national securities exchange or automated quotation system.

Each broker-dealer that receives exchange 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 exchange notes. The letter of transmittal states that by so acknowledging and 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. 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 exchange 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 available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

See “Risk Factors” beginning on page 9 for a discussion of certain risks you should consider before participating in this 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.

The date of this prospectus is November 14, 2011.

TABLE OF CONTENTS

THIS PROSPECTUS IS PART OF A REGISTRATION STATEMENT WE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION. IN MAKING YOUR INVESTMENT DECISION, YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS PROSPECTUS, IN THE ACCOMPANYING LETTER OF TRANSMITTAL OR THE INFORMATION TO WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH ANY OTHER INFORMATION. IF YOU RECEIVE ANY UNAUTHORIZED INFORMATION, YOU MUST NOT RELY ON IT. THIS PROSPECTUS MAY ONLY BE USED WHERE IT IS LEGAL TO EXCHANGE THE OLD NOTES. YOU SHOULD NOT ASSUME THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT COVER OF THIS PROSPECTUS.

This prospectus incorporates important business and financial information about us that is not included in or delivered with this document. This information is available to you without charge upon written or oral request to: Milagro Oil & Gas, Inc., 1301 McKinney, Suite 500, Houston, Texas 77010, telephone number(713) 750-1600. The exchange offer is expected to expire on December 13, 2011 and you must make your exchange decision by the expiration date. To obtain timely delivery, you must request the information no later than December 6, 2011, or the date which is five business days before the expiration date of this exchange offer.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains certain forward-looking statements. These forward-looking statements are included throughout this prospectus, including in the sections entitled “Prospectus Summary” and “Risk Factors” and other information of us and our subsidiaries. When used, statements which are not historical in nature, including those containing words such as “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “should,” “will,” “future” and similar expressions are intended to identify forward-looking statements in this prospectus regarding the parent, the issuer and their subsidiaries.

These forward-looking statements reflect our current views with respect to future events and are based on assumptions and subject to risks and uncertainties. You should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements. Among the factors that could cause actual results to differ materially are the risks and uncertainties described under “Risk Factors,” including the following:


	•	our ability to finance our planned capital expenditures;

	•	the volatility in commodity prices for oil and natural gas;

	•	future profitability;

	•	our ability to continue as a going concern;

	•	accuracy of reserve estimates;

	•	the need to take ceiling test impairments due to lower commodity prices;

	•	dependence on equity financing for acquisitions;

	•	the ability to replace our oil and natural gas reserves;

	•	general economic conditions;

	•	our ability to control activities on properties that we do not operate;

	•	hedging activities exposing us to pricing risks;

	•	availability of rigs, crews, equipment and oilfield services;

	•	our ability to retain key members of our senior management and key technical employees;

	•	geographic concentration of our assets;

	•	expiration of undeveloped leasehold acreage;

	•	exploitation, development, drilling and operating risks;

	•	the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

	•	availability of pipeline capacity and other means of transporting our crude oil and natural gas production;

	•	reliance on independent experts;

	•	our ability to integrate acquisitions with existing operations;

	•	the sufficiency of our insurance coverage;

	•	customer concentration;

	•	competition;

	•	the possibility that the industry may be subject to future regulatory or legislative actions (including changes to existing tax rules and regulations and changes in environmental regulation);


	•	environmental risks; and

	•	additional staffing requirements and other increased costs associated with being a reporting company.

For a more complete description of the various risks, relevant factors and uncertainties that could cause future results or events to differ materially from those expressed or implied in our forward-looking statements, see “Risk Factors” in this prospectus. Given these risks and uncertainties, you should not place undue reliance on these forward-looking statements.

Many of these factors are beyond our ability to control or predict. Any, or a combination, of these factors could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

All forward-looking statements included in this prospectus are made only as of the date of this prospectus, and we do not undertake any obligation to publicly update or correct any forward-looking statements to reflect events or circumstances that subsequently occur, or of which we become aware after the date of this prospectus. You should read this prospectus completely and with the understanding that our actual future results may be materially different from what we expect. We may not update these forward-looking statements, even if our situation changes in the future. All forward-looking statements attributable to us are expressly qualified by these cautionary statements.

iii

PROSPECTUS SUMMARY

This summary provides a brief overview of certain information from this prospectus, but may not contain all the information that may be important to you. You should read this entire prospectus before making an investment decision. You should carefully consider the information set forth under “Risk Factors.” In addition, certain statements include forward-looking information which involves risks and uncertainties. Please read “Cautionary Note Regarding Forward-Looking Statements.”

In this prospectus, we use the term “old notes” to refer to the 10.500% Senior Secured Second Lien Notes due 2016 that were issued on May 11, 2011, and the term “exchange notes” to refer to the 10.500% Senior Secured Second Lien Notes due 2016 that have been registered under the Securities Act of 1933, as amended (the “Securities Act”), and are being offered in exchange for the old notes as described in this prospectus. References to the “notes” in this prospectus include both the old notes and the exchange notes. As used in this prospectus, unless the context otherwise requires, “we,” “us,” and “our” refer to Milagro Oil & Gas, Inc. and its subsidiaries on a consolidated basis.

Our Company

As of December 31, 2010, we owned interests in 1,522 gross (858.3 net) wells and had average daily net production in December 2010 of approximately 9,048 Boe/d and approximately 9,005 Boe/d for the year ended December 31, 2010. As of December 31, 2010, our estimated net proved reserves, as prepared by our independent reserve engineering firm, W.D. Von Gonten & Co., were 36.7 MMBoe, consisting of 134.7 Bcf of natural gas, 9.9 MMBbl of oil, and 4.3 MMBbl of natural gas liquids (“NGLs”). As of December 31, 2010, approximately 61% of our net proved reserves were natural gas, approximately 39% were oil and NGLs, and approximately 67% of our reserves were proved developed. The wells that we operate provided approximately 78% of our average daily production for 2010. Our estimated reserve to production ratio as of December 31, 2010 was 11.1 years

Recent Developments

We used the proceeds of the offering of the old notes, together with borrowings under the New Credit Facility (as defined below), to refinance substantially all of our existing indebtedness (the “Refinancing”) as described below.

New Credit Facility. Concurrently with the closing of the offering of the old notes, we amended and restated our prior first lien credit agreement (as amended and restated, the “New Credit Facility”). The New Credit Facility permits borrowings of up to $300.0 million, subject to borrowing base limitations and other customary conditions. Our initial borrowing base under the New Credit Facility is approximately $170.0 million. As of June 30, 2011, we had approximately $74.0 million of availability under our New Credit Facility. With the exception of increased flexibility under certain financial covenants, the New Credit Facility has terms substantially similar to those in our prior first lien credit agreement. See “Description of New Credit Facility.”

Repayment in full of indebtedness under our prior first lien and second lien credit agreements. Concurrently with the closing of the offering of the old notes, we repaid in full the approximately $176.6 million in aggregate principal amount currently outstanding under our prior first lien credit agreement

and the approximately $152.6 million in aggregate principal amount outstanding under our prior second lien credit agreements, together, in each case, with the accrued interest thereon to the date of such repayment.

Amend terms of Series A preferred stock. In connection with the offering of the old notes, we amended the terms of our Series A preferred stock to provide, among other things, that only dividends in kind will accrue and be payable on the Series A preferred stock and the Series A preferred stock may not be redeemed by us sooner than 180 days after the maturity of all “qualified debt,” which includes the notes and the indebtedness under the New Credit Facility. See “Description of Series A Preferred Stock.”

The Exchange Offer

On May 11, 2011, we completed an offering of $250,000,000 in aggregate principal of the old notes and the guarantees thereof. As part of this offering, we entered into a registration rights agreement with the initial purchasers of the old notes. You are entitled to exchange in the exchange offer your old notes for exchange notes which are identical in all material respects to the old notes except that:


	•	The exchange notes have been registered under the Securities Act and will be freely tradable by persons who are not affiliated with us;

	•	The exchange notes are not entitled to registration rights which are applicable to the old notes under the registration rights agreement; and

	•	Our obligation to pay additional interest on the old notes due to the failure to consummate the exchange offer by a prior date does not apply to the exchange notes.

The following is a summary of the exchange offer.


Exchange Offer		We are offering to exchange up to $250,000,000 aggregate principal amount of our exchange notes and the guarantees thereof that have been registered under the Securities Act for an equal amount of our old notes.

Expiration Date; Withdrawal of Tenders		The exchange offer will expire at 5:00 p.m., New York City time, on December 13, 2011, unless we decide to extend it. We do not currently intend to extend the expiration date.

Conditions to the Exchange Offer		The exchange offer is subject to customary conditions, which we may waive. Please read “The Exchange Offer — Conditions to the Exchange Offer” for more information regarding the conditions to the exchange offer.

Procedures for Tendering Old Notes		Unless you comply with the procedures described under the caption “The Exchange Offer — Procedures for Tendering — Guaranteed Delivery,” you must do one of the following on or prior to the expiration of the exchange offer to participate in the exchange offer:

		• tender your old notes by sending the certificates for your old notes, in proper form for transfer, a properly completed and duly executed letter of transmittal, with any required signature guarantees, and all other documents required by the letter of transmittal, to Wells Fargo Bank, National Association, as registrar and exchange agent, at the address listed under the caption “The Exchange Offer — Exchange Agent;” or

		• tender your old notes by using the book-entry transfer procedures described below and transmitting a properly completed and duly executed letter of transmittal, with any required signature


		guarantees, or an agent’s message instead of the letter of transmittal, to the exchange agent. In order for a book-entry transfer to constitute a valid tender of your old notes in the exchange offer, Wells Fargo Bank, National Association, as registrar and exchange agent, must receive a confirmation of book-entry transfer of your old notes into the exchange agent’s account at The Depository Trust Company prior to the expiration of the exchange offer. For more information regarding the use of book-entry transfer procedures, including a description of the required agent’s message, please read the discussion under the caption “The Exchange Offer — Procedures for Tendering — Book-Entry Transfer.”

Guaranteed Delivery Procedures		If you are a registered holder of the old notes and wish to tender your old notes in the exchange offer, but:

		• the old notes are not immediately available,

		• time will not permit your old notes or other required documents to reach the exchange agent before the expiration of the exchange offer, or

		• the procedure for book-entry transfer cannot be completed prior to the expiration of the exchange offer,

		then you may tender old notes by following the procedures described under the caption “The Exchange Offer — Procedures for Tendering — Guaranteed Delivery.”

Special Procedures for Beneficial Owners		If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your old notes in the exchange offer, you should promptly contact the person in whose name the old notes are registered and instruct that person to tender on your behalf.

		If you wish to tender in the exchange offer on your own behalf, prior to completing and executing the letter of transmittal and delivering the certificates for your old notes, you must either make appropriate arrangements to register ownership of the old notes in your name or obtain a properly completed bond power from the person in whose name the old notes are registered.

Withdrawal; Non-Acceptance		You may withdraw any old notes tendered in the exchange offer at any time prior to 5:00 p.m., New York City time, on December 13, 2011. If we decide for any reason not to accept any old notes tendered for exchange, the old notes will be returned to the registered holder at our expense promptly after the expiration or termination of the exchange offer. In the case of old notes tendered by book-entry transfer into the exchange agent’s account at The Depository Trust Company, any withdrawn or unaccepted old notes will be credited to the tendering holder’s account at The Depository Trust Company. For further information regarding the withdrawal of tendered old notes, please read “The Exchange Offer — Withdrawal Rights.”


U.S. Federal Income Tax Considerations		The exchange of the exchange notes for the old notes in the exchange offer should not be a taxable event for U.S. federal income tax purposes. For more information, please see “Certain U.S. Federal Income Tax Considerations.”

Use of Proceeds		The issuance of the exchange 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.

Fees and Expenses		We will pay all of our expenses incident to the exchange offer.

Exchange Agent		We have appointed Wells Fargo Bank, National Association, as exchange agent for the exchange offer. You can find the address, telephone number and fax number of the exchange agent under the caption “The Exchange Offer — Exchange Agent.”

Resales of Exchange Notes		Based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties that are not related to us, we believe that the exchange notes you receive in the exchange offer may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act so long as:

		• the exchange notes are being acquired in the ordinary course of business;

		• you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the exchange notes issued to you in the exchange offer;

		• you are not our affiliate; and

		• you are not a broker-dealer tendering old notes acquired directly from us for your account.

		The SEC has not considered this exchange offer in the context of a no-action letter, and we cannot assure you that the SEC would make similar determinations with respect to this exchange offer. If any of these conditions are not satisfied, or if our belief is not accurate, and you transfer any exchange notes issued to you in the exchange offer without delivering a resale prospectus meeting the requirements of the Securities Act or without an exemption from registration of your exchange notes from those requirements, you may incur liability under the Securities Act. We will not assume, nor will we indemnify you against, any such liability. Each broker-dealer that receives exchange notes for its own account in exchange for old notes, where the old notes 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 exchange notes. Please read “Plan of Distribution.”

		Please read “The Exchange Offer — Resales of Exchange Notes” for more information regarding resales of the exchange notes.


Effect on Holders of Old Notes		As a result of the making of, and upon acceptance for exchange of all validly tendered old notes pursuant to the terms of, the exchange offer, we will have fulfilled a covenant contained in the registration rights agreement and, accordingly, we will not be obligated to pay additional interest as described in the registration rights agreement. If you are a holder of old notes and do not tender your old notes in the exchange offer, you will continue to hold such old notes and you will be entitled to all the rights and limitations applicable to the old notes in the indenture, except for any rights under the registration rights agreement that by their terms terminate upon the consummation of the exchange offer.

Consequences of Failure to Exchange		All untendered old notes will continue to be subject to the restrictions on transfer provided for in the old notes and in the indenture. In general, the old notes may not be offered or sold unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable sate securities laws. Other than in connection with the exchange offer, we do not currently anticipate that we will register the old notes under the Securities Act.

Terms of the Exchange Notes

The exchange notes will be identical to the old notes except that the exchange notes are registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest and will contain different administrative terms. The exchange notes will evidence the same debt as the old notes, and the same indenture will govern the exchange notes and the old notes. Because the exchange notes will be registered, the exchange notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their old notes accepted in the exchange offer will have no registration rights.

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


Issuer		Milagro Oil & Gas, Inc.

Notes Offered		$250,000,000 in aggregate principal amount of our 10.500% senior secured second lien notes due 2016.

Interest		10.500% per year (calculated using a360-day year).

Interest Payment Dates		Each May 15 and November 15, commencing November 15, 2011.

Maturity Date		May 15, 2016.

Note Guarantees		The exchange notes will be fully and unconditionally guaranteed, jointly and severally, on a senior secured second-priority lien basis by each of our existing and future subsidiaries, subject to certain exceptions. All of the subsidiary guarantors will guarantee our obligations under our New Credit Facility on a senior secured first-priority lien basis. In the future, the note guarantees may be released or terminated under certain circumstances. See “Description of Notes — Note Guarantees.”

Collateral		The exchange notes and the related note guarantees will be secured by a second-priority lien on all of our and the subsidiary


		guarantors’ assets that secure our New Credit Facility (other than certain excluded assets). Subject to certain limitations, the collateral will consist of not less than 80% of the total present value of our and the subsidiary guarantors’ proved oil and gas properties in the United States and adjacent Federal waters. The collateral agent will hold second-priority liens on the collateral in trust for the benefit of the holders of Parity Lien Obligations. See “Description of Notes — Security.”

Ranking		The exchange notes and the related note guarantees will be our and the subsidiary guarantors’ general senior secured second-priority obligations. Accordingly, they will rank:

		• effectively junior, to the extent of the value of the collateral, to our and the subsidiary guarantors’ obligations under the New Credit Facility and any other Priority Lien Debt, which will be secured on a first-priority basis by the same assets of ours that secure the exchange notes and the note guarantees;

		• pari passuin right of payment with all of our existing and future senior indebtedness, including indebtedness under the New Credit Facility;

		• effectively senior to all of our and the subsidiary guarantors’ existing and future unsecured indebtedness to the extent of the value of the collateral securing the exchange notes and the note guarantees; and

		• senior in right of payment to any future subordinated indebtedness.

Intercreditor Agreement		The collateral trustee has entered into an intercreditor agreement with us, the subsidiary guarantors and Wells Fargo Bank, N.A., as administrative agent under our New Credit Facility, which governs the relationship of noteholders and the lenders under our New Credit Facility with respect to collateral and certain other matters. See “Description of Notes — The Intercreditor Agreement.”

Collateral Trust Agreement		Wells Fargo Bank, N.A., as the collateral trustee, has entered into a collateral trust agreement with us and the subsidiary guarantors. The collateral trust agreement sets forth the terms on which the collateral trustee will receive, hold, administer, maintain, enforce and distribute the proceeds of all of its liens upon the collateral. See “Description of Notes — Collateral Trust Agreement.”

Sharing of Liens and Collateral		We and the subsidiary guarantors may incur additional Priority Lien Debt, which would be effectively senior to the exchange notes to the extent of the value of the collateral securing such debt. In addition, liens securing the exchange notes may also secure, together on an equal and ratable basis with the exchange notes, additional Parity Lien Debt, including additional exchange notes of the same class under the indenture governing the exchange notes.


Optional Redemption		At any time prior to May 15, 2014, we may, from time to time, redeem up to 35% of the aggregate principal amount of the exchange notes with the net cash proceeds of certain equity offerings at the redemption price set forth under “Description of Notes — Optional Redemption,” if at least 65% of the aggregate principal amount of the exchange notes issued under the indenture remains outstanding immediately after such redemption and the redemption occurs within 90 days of the closing date of such equity offering.

		At any time prior to May 15, 2014, we may redeem the exchange notes, in whole or in part, at a “make whole” redemption price set forth under “Description of Notes — Optional Redemption.”

		On and after May 15, 2014, we may redeem the exchange notes, in whole or in part, at the redemption prices set forth under “Description of Notes — Optional Redemption.”

Change of Control		If a change of control occurs, each noteholder may require us to repurchase all or a portion of its exchange notes for cash at a price equal to 101% of the aggregate principal amount of such exchange notes, plus any accrued and unpaid interest and special interest, if any, to, but not including, the date of repurchase.

Certain Covenants		The indenture governing the exchange notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

		• incur or guarantee additional indebtedness or issue certain preferred stock;

		• declare or pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

		• transfer or sell assets;

		• make investments;

		• create certain liens;

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

		• engage in transactions with affiliates; and

		• create unrestricted subsidiaries.

		These covenants are subject to important exceptions and qualifications as described under “Description of Notes — Certain Covenants.”

Absence of Established Market for the Notes		The notes are new issues of securities and there is currently no established market for them. Accordingly, a market for the notes, or, if issued, the exchange notes, may not develop, or if one does develop, it may not provide adequate liquidity. The initial purchasers advised us that they intend to make a market for the notes as permitted by applicable laws and regulations. However, the initial purchasers are not obligated to do so and may discontinue any such market making activities without any notice.

Ratio of Earnings to Fixed Charges

The following table sets forth our historical consolidated ratio of earning to fixed charges for the periods shown:

Six Months Ended

June 30,

Year Ended December 31,

2011

2010

2009

2008

Ratio of earnings to fixed charges

—

1.24

—

For purposes of calculating the ratio of earnings to fixed charges, fixed charges include imputed interest on rent expense, interest expense, capitalized interest and amortization of debt issuance costs. Earnings were inadequate to cover fixed charges for the year ended December 31, 2010 by approximately $15.6 million. As a result of ceiling limitation impairments, earnings were inadequate to cover fixed charges for the years ended December 31, 2009 and 2008 by approximately $69.9 million and $325.2 million, respectively. As of the six months ended June 30, 2011, earnings were inadequate to cover fixed charges by approximately $19.8 million. A combination of factors results in our inability to provide a ratio of earnings to fixed charges for the years ended December 31, 2007 and 2006. These factors are: 1) our predecessor was not accounted for as a separate entity, subsidiary, or division by the previous owner, and as a result, the financial data for the predecessor for 2006 and 2007 was not prepared and does not exist, and 2) we did not acquire the employees of the predecessor and as such the time and expense associated with preparing the applicable selected financial data for the predecessor would be unreasonable. See “Selected Consolidated Financial Data.”

Risk Factors

Investing in the exchange notes involves substantial risk. Please read “Risk Factors,” beginning on page 9 of this prospectus for a discussion of certain factors that you should consider before participating in the exchange offer.

Corporate Information

We were formed as a limited liability company in Delaware in 2007 and converted to a corporation in 2010. Our principal offices are located at 1301 McKinney, Suite 500, Houston, Texas 77010, where our telephone number is(713) 750-1600. Our website address is www.milagroexploration.com. Information on our website is not incorporated by reference in this prospectus.

RISK FACTORS

You should carefully consider the risks described below and other information in this prospectus before deciding to tender your old notes and participate in the exchange offer. Some of the following factors relate principally to our business and the industry in which we operate. Other factors relate principally to the exchange notes offered hereby. The risks and uncertainties described below are not intended to be exhaustive but represent the risks that we believe are material. Additional risks and uncertainties not presently known to us, or which we currently deem immaterial, may also have a material adverse effect on our business, financial condition and operating results and could therefore affect your investment in the exchange notes.

Risk Related to the Exchange Offer

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

We will only issue exchange 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. Please read “The Exchange Offer — Procedures for Tendering” and “Description of the Exchange Notes.”

If you do not exchange your old notes for exchange notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your old notes described in the legend on the certificates for your old notes. In general, you may only offer or sell the old notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. We do not plan to register any sale of the old notes under the Securities Act. For further information regarding the consequences of tendering your old notes in the exchange offer, please read “The Exchange Offer — Consequences of Failure to Exchange Outstanding Securities.”

You may find it difficult to sell your exchange notes.

Although the exchange notes will be registered under the Securities Act, the exchange notes will not be listed on any securities exchange. Because there is no public market for the exchange notes, you may not be able to resell them.

We cannot assure you that an active market will exist for the exchange notes or that any trading market that does develop will be liquid. If an active market does not develop or is not maintained, the market price and liquidity of the exchange notes may be adversely affected. If a market for the exchange notes develops, they may trade at a discount from their initial offering price. The trading market for the exchange notes may be adversely affected by:


	•	changes in the overall market for non-investment grade securities;

	•	changes in our financial performance or prospects;

	•	the financial performance or prospects for companies in our industry generally;

	•	the number of holders of the exchange notes;

	•	the interest of securities dealers in making a market for the exchange notes; and

	•	prevailing interest rates and general economic conditions.

Historically, the market for non-investment grade debt has been subject to substantial volatility in prices. The market for the exchange notes, if any, may be subject to similar volatility. Prospective investors in the exchange notes should be aware that they may be required to bear the financial risks of such investment for an indefinite period of time.

Some holders who exchange their old notes may be deemed to be underwriters.

If you exchange your old notes in the exchange offer for the purpose of participating in a distribution of the exchange notes, you may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Risks Related to the Notes

Our level of indebtedness may adversely affect our cash available for operations.

As of June 30, 2011, we had approximately $339.2 million in outstanding indebtedness and had approximately $74.0 million of available borrowing capacity under our New Credit Facility. Our level of indebtedness will have several important effects on our operations, including:


	•	we will dedicate a portion of our cash flow from operations to the payment of interest on our indebtedness and to the payment of our other current obligations and will not have that portion of cash flow available for other purposes;

	•	our debt agreements limit our ability to borrow additional funds or dispose of assets and may affect our flexibility in planning for, and reacting to, changes in business conditions;

	•	our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired;

	•	we may be more vulnerable to economic downturns and our ability to withstand sustained declines in oil and natural gas prices may be impaired;

	•	since outstanding balances under our New Credit Facility are subject to variable interest rates, we are vulnerable to increases in interest rates;

	•	our flexibility in planning for or reacting to changes in market conditions may be limited; and

	•	we may be placed at a competitive disadvantage compared to our competitors that have less indebtedness.

We cannot assure you that we will be able to improve our leverage position.

A significant element of our business strategy involves improving our ratio of debt to EBITDA and the aggregate value of our assets. However, we are also seeking to acquire, exploit and develop additional reserves which may require the incurrence of additional indebtedness. Although we will seek to improve our leverage position, our ability to reduce our level of indebtedness depends on a variety of factors, including future performance. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to improve our leverage position. Many of these factors are beyond our control.

The indenture governing the notes and the agreements governing our New Credit Facility imposes significant operating and financial restrictions, which may prevent us from capitalizing on business opportunities and taking some actions.

The indenture governing the notes and the agreements governing our New Credit Facility contain customary restrictions on our activities, including covenants that restrict our and our subsidiaries’ ability to:


	•	incur additional indebtedness;

	•	pay dividends on, redeem or repurchase stock;

	•	create liens;

	•	make specified types of investments;

	•	apply net proceeds from certain asset sales;


	•	engage in transactions with our affiliates;

	•	engage in sale and leaseback transactions;

	•	merge or consolidate;

	•	restrict dividends or other payments from subsidiaries;

	•	sell equity interests of subsidiaries; and

	•	sell, assign, transfer, lease, convey or dispose of assets.

The indenture governing the notes contains certain incurrence-based covenants that limit our ability to incur indebtedness and engage in other transactions. One of these covenants incorporates the net present value of our net proved reserves calculated based on SEC rules. Our ability to increase our borrowings in 2011 will depend, in part, on prices for oil and natural gas and our drilling results at the time of redetermination. Our New Credit Facility also requires us to meet a minimum current ratio, a minimum interest coverage ratio and leverage ratios relating to both total debt to EBITDA and total senior debt to EBITDA. We may not be able to maintain or comply with these ratios, and if we fail to be in compliance with these covenants, we will not be able to borrow funds under our New Credit Facility, which would make it difficult for us to operate our business.

The restrictions in the indenture governing the notes and the agreements governing our New Credit Facility may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future indebtedness obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. We cannot assure you that we will be granted waivers or amendments to these agreements if for any reason we are unable to comply with these agreements or that we will be able to refinance our indebtedness on terms acceptable to us, or at all.

The breach of any of these covenants and restrictions could result in a default under the indenture governing the notes or under the agreements governing our New Credit Facility. An event of default under our debt agreements would permit some of our lenders to declare all amounts borrowed from them to be due and payable. If we are unable to repay such indebtedness, lenders having secured obligations, such as the lenders under our New Credit Facility, could exercise their rights and remedies against the collateral securing the indebtedness. Because the indenture governing the notes and the agreements governing our New Credit Facility have customary cross-default provisions, if the indebtedness under the notes or under our New Credit Facility or any future facilities is accelerated, we may be unable to repay or refinance the amounts due.

Availability under our New Credit Facility is based on a borrowing base that is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to post additional assets as collateral or repay amounts outstanding under our New Credit Facility.

Under the terms of our New Credit Facility, our borrowing base is subject to semi-annual redetermination by our lenders based on their valuation of our net proved reserves and their internal criteria. In addition to such semi-annual determinations, our lenders may request one additional borrowing base redetermination during each six-month period between borrowing base determinations. In the past, the borrowing base under our credit agreements has been reduced as a result of, among other things, changes in pricing, production, monetization of unrealized hedging gains and our disposition of assets included in the then-current borrowing base. A reduction in our borrowing base below the amount then outstanding under our New Credit Facility will result in a borrowing base deficiency requiring us to cure such deficiency by posting additional assets as collateral or repaying a portion of the loan under the New Credit Facility over a period no longer than five months. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our New Credit Facility or sell assets. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to cure a borrowing base

deficiency could result in a default under our New Credit Facility, which could adversely affect our business, financial condition and results of operations.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our New Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on such variable rate indebtedness would increase, although the amount borrowed would remain the same, and our net income and cash available for servicing our indebtedness would decrease. A significant increase in our interest expense could adversely affect our business, financial condition and results of operations.

We may incur additional indebtedness, which could further exacerbate the risks associated with our substantial leverage.

We may incur substantial additional indebtedness in the future. The indenture governing the notes and the agreements governing our New Credit Facility contain restrictions on our ability to incur indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions will not prevent us from incurring obligations that do not constitute “Indebtedness” under the indenture and the New Credit Facility, respectively. If we incur indebtedness above our current levels, the related risks that we now face could intensify and we may not be able to meet all our debt obligations. Failure to meet these obligations could result in a default under our debt agreements, which could adversely affect our business, financial condition and results of operations.

Failure to generate sufficient cash to service our indebtedness could adversely affect our business, financial condition and results of operations.

Our ability to meet our indebtedness obligations and other expenses will depend on our future performance, which will be subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our New Credit Facility or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. Failure to generate sufficient cash to service our indebtedness could adversely affect our business, financial condition and results of operations.

If we are unable to meet our debt service obligations, we may be required to seek a waiver or amendment from our debt holders, refinance such debt obligations or sell assets or additional equity. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to meet our debt obligations could result in a default under our debt agreements. An event of default under our debt agreements will permit some of our lenders to declare all amounts borrowed from them to be due and payable. If we are unable to repay such indebtedness, lenders having secured obligations, such as the lenders under our New Credit Facility, could proceed against the collateral securing the indebtedness. Because the indenture governing the notes and the agreements governing our New Credit Facility have customary cross-default provisions, if the indebtedness under the notes or under our New Credit Facility is accelerated, we may be unable to repay or finance the amounts due.

Your right to receive payments on the notes is effectively subordinated to the rights of our and the guarantors’ existing and future priority lien secured creditors.

Holders of our priority lien secured indebtedness and the priority lien secured indebtedness of the guarantors will have claims that are prior to your claims as noteholders to the extent of the value of the assets securing that other priority lien indebtedness. Notably, we and the guarantors are parties to our New Credit Facility, which is secured by liens on substantially all of our assets and the assets of the guarantors. The notes will be effectively subordinated to any secured indebtedness incurred under the New Credit Facility to the

extent of the value of the assets securing the New Credit Facility. In the event of any distribution or payment of our or any guarantor’s assets in any foreclosure, dissolution,winding-up, liquidation, reorganization or other bankruptcy proceeding, holders of priority lien secured indebtedness will have a prior claim to those assets that constitute their collateral. Pursuant to the terms of the intercreditor agreement, holders of priority lien claims, including lenders under the New Credit Facility, are entitled to receive all proceeds from the sale or other disposition of the collateral until such claims are paid in full. As a result, the notes are effectively subordinated to all priority lien claims. If there is insufficient collateral to cover all claims, noteholders may receive less, ratably, than holders of priority lien secured indebtedness.

As of June 30, 2011, we had approximately $96.0 million of indebtedness and letters of credit outstanding under our New Credit Facility, and had approximately $74.0 million of availability remaining under our New Credit Facility. In addition, we are permitted to borrow additional priority lien secured indebtedness under the terms of the indenture. See “Description of Notes — Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” and “— Liens.”

There may not be sufficient collateral to pay all or any portion of the notes.

We cannot assure you that the value of the collateral securing the notes and the guarantees would be sufficient to pay any amounts due under the notes following their acceleration. The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral. The value of the assets pledged as collateral for the notes could be impaired in the future as a result of changing economic conditions, commodity prices, competition or other future trends.

In the event of a foreclosure, liquidation, bankruptcy or a similar proceeding, we cannot assure you that the proceeds from any sale or liquidation of the collateral will be sufficient to pay the obligations under the notes, in full or at all, after first satisfying the obligations in full under contractually senior claims, such as those under the New Credit Facility, or other claims that may have legal priority over the noteholders. If the proceeds of any sale of collateral are not sufficient to repay all amounts due on the notes, the noteholders (to the extent not repaid from the proceeds of the sale of the collateral) would have only an unsecured claim against the remaining assets and, in the context of a bankruptcy case by or against us, the noteholders may not be entitled to receive interest payments or reasonable fees, costs or charges due under the notes, and may be required to repay any such amounts already received by such holder.

In addition, we may not perfect the liens on all of the collateral that is to secure the notes and the guarantees on or prior to the closing of this offering. Accordingly, there may not be sufficient collateral to pay all or any of the amounts due on the notes.

We are a holding company and are dependent upon cash flow from subsidiaries to meet our obligations.

We currently conduct our operations through, most of our assets are owned by, and our operating income and cash flow are generated by, our subsidiaries. As a result, cash from these subsidiaries is the principal source of funds necessary to meet our obligations under the notes and any future debt service obligations. Contractual provisions or laws, as well as our subsidiaries’ financial condition and operating requirements, may limit our ability to obtain cash from subsidiaries that we require to meet our debt service obligations, including payments on the notes. Applicable tax laws may also subject such payments to us by our subsidiaries to further taxation. Though we may have sufficient resources on a consolidated basis to meet our obligations, the inability to transfer cash from our subsidiaries may mean that we may not be permitted to make the necessary transfers from our subsidiaries to meet such obligations.

The lien ranking provisions of the intercreditor agreement limits the ability of noteholders to exercise rights and remedies with respect to collateral securing the notes and related note guarantees.

The rights of the noteholders with respect to the collateral securing the notes on a second lien basis is substantially limited by the terms of the lien ranking provisions in the intercreditor agreement. Under the terms of the intercreditor agreement, almost any action that may be taken in respect of the collateral, including the rights to exercise remedies with respect to or challenge the liens on, the collateral securing the notes will

be at the direction of the administrative agent and lenders under the New Credit Facility and any other holders of priority lien obligations that may, from time to time, be outstanding. The collateral trustee and the trustee will not have the ability to control or direct such actions, even if the rights of noteholders are adversely affected.

In addition, the intercreditor agreement contains certain provisions benefiting holders of indebtedness under our New Credit Facility that prevent the collateral trustee from objecting to a number of important matters regarding the collateral following the filing of a bankruptcy. After such filing, the value of the collateral could materially deteriorate and noteholders would be unable to raise an objection. See “Description of Notes — The Intercreditor Agreement.”

Pursuant to the intercreditor agreement, in the event of bankruptcy the collateral trustee, on behalf of all noteholders, will be required to support and vote for certain plans of reorganization. This restriction may prevent the collateral agent from supporting plans of reorganization that propose more favorable recoveries with respect to parity lien claims, including claims with respect to the notes.

Pursuant to the intercreditor agreement, in the event of a bankruptcy filing, the collateral trustee, on behalf of all noteholders, and the holders of other parity lien indebtedness are required to support and vote for any plan of reorganization or disclosure statement of ours or any of the subsidiary guarantors that (a) is accepted by the class of holders of our priority lien secured indebtedness in accordance with Section 1126(c) of the U.S. Bankruptcy Code, (b) provides for the payment in full in cash of all of our priority lien secured indebtedness (including all post-petition interest, fees and expenses) on the effective date of such plan of reorganization or (c) provides for the retention by the collateral trustee of the liens on the collateral securing our priority lien secured indebtedness, and on all proceeds thereof, with the same relative priority with respect to the collateral or other property as provided in the intercreditor agreement with respect to the collateral. To the extent any such plan provides for deferred cash payments, or for the distribution of any other property of any kind or nature, on account of our priority lien secured indebtedness or the parity lien indebtedness, an acceptable plan must provide that any such deferred cash payments or other distributions in respect of the parity lien indebtedness is delivered to the collateral trustee and distributed in accordance with the priorities provided in the intercreditor agreement. These and other restrictions in our intercreditor agreement may prevent the collateral agent and holders of other parity lien claims from supporting plans of reorganizations that propose more favorable recoveries with respect to parity lien claims, including claims with respect to the notes. See “Description of Notes — Intercreditor Agreement — Agreement With Respect to Insolvency or Liquidation Proceedings.”

The collateral is subject to casualty risks.

We are obligated under the indenture governing the notes to maintain adequate insurance or otherwise insure against hazards as is customarily done by companies having assets of a similar nature in the same or similar localities. There are, however, certain losses that may be either uninsurable or not economically insurable, in whole or in part. As a result, it is possible that the insurance proceeds will not compensate us fully for our losses. If there is a total or partial loss of any of the pledged collateral, we cannot assure you that any insurance proceeds received by us will be sufficient to satisfy all of our secured obligations, including the notes.

The collateral securing the notes and related note guarantees may be diluted under certain circumstances.

The indenture governing the notes and agreements governing the New Credit Facility permit us to incur additional secured indebtedness, including additional notes, parity lien indebtedness and other priority lien indebtedness, subject to our compliance with the restrictive covenants in the indenture governing the notes and the agreements governing our New Credit Facility at the time we incur such additional secured indebtedness.

Any additional notes issued under the indenture governing the notes would be guaranteed by the same guarantors and would have the same security interests, with the same priority, as currently securing the notes. As a result, the collateral securing the notes would be shared by any additional notes we may issue under the

applicable indenture, and an issuance of such additional notes would dilute the value of the collateral compared to the aggregate principal amount of notes issued.

In addition, the indenture and our other security documents permit us and certain of our subsidiaries to incur additional priority lien indebtedness and parity lien indebtedness up to respective maximum priority lien and parity lien indebtedness threshold amounts by issuing additional debt securities under one or more new indentures or by borrowing additional amounts under new credit facilities. Any additional priority lien indebtedness or parity lien indebtedness secured by the collateral would dilute the value of the noteholders’ rights to the collateral.

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

The right of the collateral agent to repossess and dispose of the collateral securing the notes and the guarantees upon acceleration is likely to be significantly impaired by federal bankruptcy laws if bankruptcy proceedings are commenced by or against us 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, 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. Moreover, bankruptcy laws permit 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 agreements, 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 could be delayed following commencement of a bankruptcy case, whether or when the collateral agent would repossess or dispose of the collateral, and whether or to what extent noteholders would be compensated for any delay in payment of 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 noteholders would have “undersecured claims” as to the difference. U.S. 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. Additionally, the trustee’s ability to foreclose on the collateral on your behalf may be subject to the consent of third parties, prior liens and practical problems associated with the realization of the trustee’s security interest in the collateral. Moreover, the debtor or trustee in a bankruptcy case may seek to void an alleged security interest in collateral for the benefit of the bankruptcy estate. It may successfully do so if the security interest is not properly perfected or was perfected within a specified period of time (generally 90 days) prior to the initiation of such proceeding. Under such circumstances, a creditor may hold no security interest and be treated as holding a general unsecured claim in the bankruptcy case. It is impossible to predict what recovery (if any) would be available for such an unsecured claim if the issuer or parent became a debtor in a bankruptcy case. While U.S. bankruptcy laws generally invalidate provisions restricting a debtor’s ability to assumeand/or assign a contract, there are exceptions to this rule which could be applicable in the event that we become subject to a U.S. bankruptcy proceeding.

Rights of noteholders in the collateral may be adversely affected by the failure to perfect liens on the collateral or on collateral acquired in the future.

The failure to properly perfect liens on the collateral could adversely affect the collateral agent’s ability to enforce its rights with respect to the collateral for the benefit of the noteholders. In addition, applicable law requires that certain property and rights acquired after the grant of a general security interest or lien 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 trustee and the collateral agent for the notes 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 practical benefits of the liens thereon or of the priority of the liens securing the notes against third parties.

If we were to become subject to a U.S. bankruptcy proceeding after the issue date of the notes, any liens recorded or perfected 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 laws as if it were delivered to secure previously existing indebtedness. In U.S. bankruptcy proceedings commenced within 90 days of lien perfection, a lien given to secure previously existing indebtedness is materially more likely to be avoided as a preference by the bankruptcy court than if delivered and promptly recorded on the issue date of the notes. Accordingly, if we were to file for bankruptcy after the issue date of the notes and the liens had been perfected less than 90 days before commencement of such bankruptcy proceeding, the liens securing the notes 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 the collateral was intended to provide.

There are circumstances other than repayment or discharge of the notes under which the collateral securing the notes and guarantees will be released automatically, without holders’ consent or the consent of the trustee under the indenture governing the notes.

Under various circumstances, some of the collateral securing the notes will be released automatically, including:


	•	sale, transfer or other disposal of such collateral in a transaction not prohibited under the indenture governing the notes;

	•	with respect to the collateral held by a guarantor, upon the release of such guarantor from its guarantee;

	•	if the lenders under the New Credit Facility and the other holders of priority lien secured indebtedness release their lien on any collateral, the lien on such collateral securing the notes and other parity lien indebtedness will terminate and be released automatically and without further action;

	•	as otherwise required under the intercreditor agreement; and

	•	to the extent we have defeased or satisfied and discharged the indenture governing the notes.

In addition, a guarantee will be automatically released in connection with a sale of such guarantor or a sale of all or substantially all of the assets of that guarantor, in each case, in a transaction not prohibited under the indenture governing the notes.

The notes will be effectively subordinated to the indebtedness of our future non-guarantor subsidiaries, if any.

The notes will be fully and unconditionally guaranteed on a senior secured basis by all of our existing subsidiaries, as well as certain of our future domestic subsidiaries. However, they will not be guaranteed by any of our future subsidiaries outside the United States unless, subject to certain limited exceptions, these subsidiaries guarantee any of our other domestic indebtedness. The indenture also provides that the notes need not be guaranteed by certain subsidiaries with minimal net worth. The notes will be effectively subordinated to all indebtedness and other liabilities, including trade payables, of any future subsidiaries that do not guarantee the notes.

If we are unable to comply with the restrictions and covenants in the agreements governing the notes and our other indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on the notes.

Any default under the agreements governing our indebtedness, including a default under our New Credit Facility that is not cured or waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest, or special interest, if any, on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the agreements governing our indebtedness (including our New Credit Facility), we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our New Credit Facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to seek to obtain waivers from the required lenders under our New Credit Facility to avoid being in default. If we breach our covenants under our New Credit Facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our New Credit Facility, the lenders could exercise their rights and remedies as described above, and we could be forced into bankruptcy or liquidation. See “Description of New Credit Facility” and “Description of Notes.”

The value of the collateral securing the notes and related note guarantees may not be sufficient to secure post-petition interest.

In the event of a U.S. bankruptcy proceeding against us or the guarantors, noteholders will be entitled to post-petition interest under the U.S. Bankruptcy Code only if the value of their security interest in the collateral is greater than their pre-bankruptcy claim. Noteholders may be deemed to have an unsecured claim if our obligations under the notes equal or exceed the fair market value of the collateral securing the notes. Noteholders that have a security interest in the collateral with a value equal to or less than their pre-bankruptcy claim will not be entitled to post-petition interest under the U.S. Bankruptcy Code. The bankruptcy trustee, thedebtor-in-possession or competing creditors could possibly 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 a 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. Other consequences of a finding of under collateralization would be, among other things, a lack of entitlement on the part of noteholders 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 U.S. federal bankruptcy laws. In addition, if any payments of post-petition interest were made at the time of such a finding of under collateralization, such payments could be re-characterized by the bankruptcy court as a reduction of the principal amount of the secured claim with respect to notes. No appraisal of the fair market value of the collateral securing the notes has been prepared in connection with this offering of the notes and, therefore, the value of the collateral trustee’s interest in the collateral may not equal or exceed the principal amount of the notes. We cannot assure you that there will be sufficient collateral to satisfy our and the guarantors’ obligations under the notes.

We may not have the ability to raise the funds necessary to finance the change of control offer required by the indenture governing the notes.

Upon the occurrence of certain change of control events, we will be required to offer to repurchase all of the outstanding notes at 101% of the principal amount thereof plus accrued and unpaid interest, and special

interest, if any, to the date of repurchase, unless all notes have been previously called for redemption. The holders of other debt securities that we may issue in the future, which rank equally in right of payment with the notes, may also have this right. Our failure to purchase tendered notes would constitute an event of default under the indenture governing the notes, which in turn, would constitute a default under our New Credit Facility. In addition, the occurrence of a change of control would also constitute an event of default under our New Credit Facility. A default under our New Credit Facility would result in a default under the indenture if the lenders accelerate the indebtedness under our New Credit Facility.

Therefore, it is possible that we may not have sufficient funds at the time of the change of control to make the required repurchase of notes. Moreover, our New Credit Facility restricts, and any future indebtedness we incur may restrict, our ability to repurchase the notes, including following a change of control event. As a result, following a change of control event, we would not be able to repurchase notes unless we first repay all indebtedness outstanding under our New Credit Facility and any of our other indebtedness that contains similar provisions, or obtain a waiver from the holders of such indebtedness to permit us to repurchase the notes. We may be unable to repay all of that indebtedness or obtain a waiver of that type. Any requirement to offer to repurchase outstanding notes may therefore require us to refinance our other outstanding indebtedness, which we may not be able to do on terms acceptable to us, if at all. These repurchase requirements may also delay or make it more difficult for others to obtain control of us.

In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a “Change of Control” under the indenture. See “Description of Notes — Repurchase at the Option of Holders — Change of Control.”

The terms of our New Credit Facility may prevent us from complying with our obligation to offer to repurchase the notes upon the occurrence of a change of control or with the proceeds of certain asset sales.

The indenture requires that we offer to purchase outstanding notes upon the occurrence of a change of control. We are likewise required to make an offer to repurchase notes with the proceeds of certain asset sales. Our New Credit Facility contains covenants that will prevent us from offering to purchase outstanding notes upon the occurrence of a change of control or with the proceeds of asset sales. A failure by us to comply with the obligation to offer to repurchase notes in connection with a change of control or certain assets sales, even if prevented by the terms of the New Credit Facility, will result in a default under the indenture and the notes. See “— Description of the Notes — Repurchases at the Option of Holders — Change of Control” and “— Asset Sales.”

The definition of change of control set forth in the indenture with respect to the notes differs from the definition of change of control included in our New Credit Facility.

Depending on the circumstances, it is possible that a change of control may occur for purposes of our New Credit Facility without constituting a change of control for purposes of the indenture governing the notes. For example, a sale of less than a majority of the outstanding interests in any of our subsidiaries would constitute an event of default under the New Credit Facility but not under the indenture. We will not be required to offer to repurchase outstanding notes at a price equal to 101% of the principal amount thereof upon the occurrence of a change of control under the New Credit Facility that does not also constitute a change of control under the indenture with respect to the notes.

There is no established market for the notes.

The notes will not be listed on any securities exchange. Although the initial purchasers may make a market in the notes, they are not obligated to do so, and they may discontinue any market-making at any time without notice. We cannot assure you that an active market for the notes will develop or, if it does develop, that it will continue. Further, if a market for the notes does develop, then the notes could trade at prices that may be higher or lower than the initial offering price thereof depending upon a number of factors, including prevailing interest rates, our operating results, events in the United States and the market for similar securities.

If a market for the notes does not develop or continue, then noteholders may be unable to resell the notes for an extended period of time at their fair market value, if at all. Future trading prices of the notes will depend on many factors, including, among other things, prevailing interest rates, our operating results and the market for similar securities. Consequently, a purchaser of the notes may not be able to liquidate its investment readily, and the notes may not be readily accepted as collateral for loans.

Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from guarantors.

Creditors are protected by fraudulent conveyance laws that may apply to the issuance of the guarantees by our subsidiary guarantors. Under U.S. federal bankruptcy laws and comparable provisions of many state fraudulent transfer laws, a guarantee may be voided by a court, or subordinated to the claims of other creditors, if, among other things:


	•	the indebtedness evidenced by such guarantee was incurred by a subsidiary guarantor with actual intent to hinder, delay or defraud any present or future creditor of such subsidiary guarantor; or

	•	such subsidiary guarantor did not receive fair consideration or reasonably equivalent value for issuing the guarantee;

and the applicable subsidiary guarantor:


	•	was insolvent, or was rendered insolvent by reason of issuing the applicable guarantee;

	•	was engaged or about to engage in a business or transaction for which the remaining assets of the applicable subsidiary guarantor constituted unreasonably small capital; or

	•	intended to incur, or believed that we or it would incur, indebtedness beyond our or its ability to pay such debts as they matured.

In addition, any payment by such subsidiary guarantor pursuant to any guarantee could be voided and required to be returned to such subsidiary guarantor, or to a fund for the benefit of creditors of such subsidiary guarantor. A legal challenge to a guarantee on fraudulent conveyance grounds may focus on the benefits, if any, realized by the subsidiary guarantors as a result of their issuance of the guarantees. To the extent a subsidiary’s guarantee of the notes is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the noteholders would cease to have any claim in respect of that guarantee and would be creditors solely of us and the remaining guarantors. Because all of our significant assets are held by our subsidiary guarantors, the impact of a guarantee being voided under fraudulent transfer laws is higher. In addition, any future guarantees provided under the indenture governing the notes have a greater risk of being voided.

The measures of insolvency for purposes of fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if:


	•	the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;

	•	if the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

	•	it could not pay its debts as they become due.

Each subsidiary guarantee contains a provision intended to limit the subsidiary guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its subsidiary guarantee to be a fraudulent transfer. The U.S. bankruptcy court for the Southern District of Florida recently held a similar limitation on the amount of a subsidiary guarantor’s liability under a guarantee to be

unenforceable and concluded that the guarantee was a fraudulent transfer voidable under applicable bankruptcy laws.

We face risks related to rating agency downgrades.

We expect one or more rating agencies to rate the notes. If such rating agencies either assign the notes a rating lower than the rating expected by the investors, or reduce the rating in the future, the market price of the notes would be adversely affected. In addition, if any of our other outstanding indebtedness is rated and subsequently downgraded, raising capital will become more difficult, borrowing costs under our New Credit Facility and other future borrowings may increase and the market price of the notes may be adversely affected.

Risks Relating to Our Company and the Industry

Our acquisition, exploitation and development projects require substantial capital expenditures. We may have difficulty financing our planned capital expenditures, which could adversely affect our business, financial condition and results of operation.

The oil and natural gas industry is capital intensive. We make, and intend to continue to make, substantial capital expenditures in our acquisition, exploitation and development projects. While we intend to finance our future capital expenditures through a variety of sources, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. Additionally, we expect that future acquisitions will require funding, at least in part, from the issuance of equity securities. We may not be able to secure additional debt financing or the additional equity financing required for acquisitions on reasonable terms or at all. Financing may not continue to be available to us under our existing or new financing arrangements. If additional capital resources are unavailable, we may be forced to curtail our drilling, development and other activities or sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operations.

Oil and natural gas prices are volatile and we may not be able to meet our hedging goals. A substantial or extended decline in oil or natural gas prices could adversely affect our results of operations.

Our revenues, operating results and future rate of growth depend upon the prices we receive for our oil and natural gas production. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Although we will seek to enter into commodity price hedging contracts for additional volumes of our expected proved developed producing production, approximately 73% of our expected 2011 and 2012 proved developed producing production has been hedged as of June 30, 2011, based on forecasted production set forth in our most recent reserve report. We cannot assure you that we will be able to meet our goal of increasing the level of our hedges for expected proved developed producing production by any certain date or at all or that our level of hedges in 2011 and 2012 will remain the same if actual production is different from expected production. To the extent we are not hedged, we will sell our oil and natural gas at current market prices, which exposes us to the risks associated with volatile commodity prices. In addition, the prices that we receive for our oil and natural gas production generally trade at a discount to the relevant benchmark prices such as NYMEX. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials.

The markets and prices for oil and natural gas depend on numerous factors beyond our control. These factors include demand for oil and natural gas, which fluctuate with changes in market and economic conditions and other factors, including:


	•	worldwide and domestic supplies of oil and natural gas;

	•	actions taken by foreign oil and natural gas producing nations;

	•	political conditions and events (including instability or armed conflict) in oil producing or natural gas producing regions;


	•	the level of global and domestic oil and natural gas inventories;

	•	the price and level of foreign imports including liquefied natural gas imports;

	•	the level of consumer demand;

	•	the price and availability of alternative fuels;

	•	the availability of pipeline or other takeaway capacity;

	•	weather conditions;

	•	technological advances affecting energy consumption;

	•	domestic and foreign governmental regulations and taxes; and

	•	the overall worldwide and domestic economic environment.

Significant declines in oil and natural gas prices for an extended period may have the following effects on our business:


	•	adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;

	•	reduce the amount of oil and natural gas that we can produce economically;

	•	cause us to delay or postpone some of our capital projects;

	•	reduce our revenues, operating income and cash flow;

	•	reduce the carrying value of our oil and natural gas properties; and

	•	limit our access to sources of capital.

We have had losses in the past and there is no assurance of our profitability for the future.

We recorded a net loss for the years ended December 31, 2010, 2009 and 2008 of $70.6 million, $8.6 million and $318.9 million, respectively, and $19.4 million for the six months ended June 30, 2011. We cannot assure you that our current level of operating results will continue or improve. Our activities could require additional equity or debt financing. Our future operating results may fluctuate significantly depending upon a number of factors, including industry conditions, prices of oil and natural gas, rates of production, timing of capital expenditures and drilling success. Negative changes in these variables could have a material adverse effect on our business, financial condition and results of operations.

As a result of certain of our indebtedness becoming current, our financial statements for the year ended December 31, 2010 include a going concern qualification.

As a result of $244.6 million of indebtedness under our existing first lien credit agreement and our existing second lien term loan agreement becoming current as of November 30, 2010 and due as of November 30, 2011, we have included a going concern qualification in our financial statements for the year ended December 31, 2010. Because of this going concern qualification and the likelihood that a deferred tax asset will not be realized, we determined a 100% valuation allowance of the deferred tax asset was needed. Although we refinanced the indebtedness that has become current with the proceeds of the offering of the old notes and borrowings under our New Credit Facility, we cannot assure you that the going concern qualification will be eliminated from future audit reports. A failure to resolve this going concern qualification could materially and adversely affect our ability to secure additional financing. Our consolidated financial statements have been prepared assuming that we will continue as a going concern and do not include any adjustments that may be required if this assumption proves untrue.

Although our oil and natural gas reserve data is independently estimated, these estimates may still prove to be inaccurate.

Our proved reserve estimates are prepared each year by W.D. Von Gonten & Co., our independent consulting petroleum engineers. In conducting their evaluation, the engineers and geologists of W.D. Von Gonten & Co. evaluate our properties and independently develop proved reserve estimates. There are numerous uncertainties and risks that are inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and timing of development expenditures, and those estimates and projections are subject to many factors that are beyond our control. Factors and assumptions taken into account in our estimates and projections include:


	•	expected reservoir characteristics based on geological, geophysical and engineering assessments;

	•	future production rates based on historical performance and expected future operating and investment activities;

	•	future oil and natural gas prices and quality and location differentials; and

	•	future development and operating costs.

Although we believe the independent reserve estimates of W.D. Von Gonten & Co. are reasonable based on the information available to them at the time they prepare their estimates, our actual results could vary materially from these estimated quantities of proved oil and natural gas reserves (in the aggregate and for a particular location), production, revenues, taxes and development and operating expenditures. In addition, these estimates of net proved reserves may be subject to downward or upward revision based upon production history, results of future exploitation and development, prevailing oil and natural gas prices, operating and development costs and other factors.

Finally, recovery of proved undeveloped reserves generally requires significant capital expenditures and successful drilling operations. At December 31, 2010, approximately 33% of our estimated net proved reserves were classified as undeveloped. At December 31, 2010, we estimated that it would require additional capital expenditures of approximately $152.8 million to develop our proved undeveloped reserves. Our reserve estimates assume that we can and will make these expenditures and conduct these operations successfully, which may not occur, and as a result, we may not be able to recover or develop our proved undeveloped reserves.

Lower oil and natural gas prices may cause us to record ceiling limitation impairments, which would increase our stockholders’ deficit.

We use the full cost method of accounting for our oil and natural gas investments. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized cost of oil and natural gas properties may not exceed a “ceiling limit” that is based upon the present value of estimated future net revenues from net proved reserves, discounted at 10%, plus the lower of the cost or fair market value of unproved properties and other adjustments as required byRegulation S-X under the Securities Act. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation impairment.” The risk that we will experience a ceiling limitation impairment increases when oil and natural gas prices are depressed, if we have substantial downward revisions in estimated net proved reserves or if estimates of future development costs increase significantly. In 2008 we had a ceiling limitation impairment of approximately $429.9 million and in 2009 we had a ceiling limitation impairment of approximately $39.6 million. Although we did not have a ceiling limitation impairment in 2010, no assurance can be given that we will not experience a ceiling limitation impairment in future periods. For more information about our prior impairments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Critical Accounting Policies — Oil and Natural Gas Properties.”

We expect that it will be necessary to raise equity capital in order to finance most of our acquisitions. An inability to raise equity capital would limit our ability to acquire additional reserves.

As a result of our existing levels of indebtedness, we expect that it will be necessary to fund future acquisitions, at least in part, with the net proceeds of equity financings. Our ability to obtain equity financing will depend, among other things, on our level of success with our exploitation and development activities and general conditions in the capital markets at the time funding is sought. We may not be able to secure equity financing on reasonable terms or at all. If additional capital resources are unavailable, we may not be able to pursue acquisitions of additional reserves or otherwise execute our business strategy.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and our ability to raise capital.

The current reserve to production ratio (“R/P ratio”) of our properties is 11.1 years. As a result, unless we conduct successful development and exploitation activities or acquire properties containing net proved reserves, our net proved reserves will decline as those reserves are produced. Producing oil and natural gas are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. In particular, approximately 60% of our total net proved reserves and approximately 70% of our total production were in the Gulf Coast region. Reservoirs in the Gulf Coast region are characterized by high initial production rates followed by steep declines in production, resulting in a reserve life for wells in this area that is shorter than the industry average. Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. If we are unsuccessful in acquiring or developing additional producing reserves, our production and revenues will decline as our current reserves are depleted. We cannot assure you that we will be able to develop, exploit, find or acquire additional reserves sufficient to replace our current and future production on an economic basis or at all.

Economic uncertainty could negatively impact the prices for oil and natural gas, limit access to the credit and equity markets, increase the cost of capital, and may have other negative consequences that we cannot predict.

Economic uncertainty in the United States could create financial challenges if conditions do not improve. Most recently, Standard & Poor’s downgraded the U.S. credit rating to AA+ from its top rank of AAA, which has increased the possibility of other credit-rating agency downgrades which could have a material adverse effect on the financial markets and economic conditions in the United States and throughout the world. Our internally generated cash flow and cash on hand historically have not been sufficient to fund all of our expenditures, and we have relied on, among other things, bank financings and private equity to provide us with additional capital. Our ability to access capital may be restricted at a time when we would like, or need, to raise capital. If our cash flow from operations is less than anticipated and our access to capital is restricted, we may be required to reduce our operating and capital budget, which could have a material adverse effect on our results and future operations. Ongoing uncertainty may also reduce the values we are able to realize in asset sales or other transactions we may engage in to raise capital, thus making these transactions more difficult and less economic to consummate. Additionally, demand for oil and natural gas may deteriorate and result in lower prices for oil and natural gas, which could have a negative impact on our revenues. Lower prices could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.

We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

We currently operate approximately 55.1% of our properties, based on producing wells at December 31, 2010. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these

projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:


	•	the timing and amount of capital expenditures;

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

	•	the operator’s expertise and financial resources;

	•	approval of other participants in drilling wells;

	•	selection of technology; and

	•	the rate of production of the reserves.

In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

In an attempt to reduce our sensitivity to energy price volatility and in particular to downward price movements, we enter into hedging arrangements with respect to a portion of our expected production, such as the use of derivative contracts that generally result in a range of minimum and maximum price limits or a fixed price over a specified time period. Even if we are successful in our strategy to increase our hedging activities, such activities may expose us to the risk of financial loss in certain circumstances. For example, if we do not produce our oil and natural gas reserves at rates equivalent to our derivative position, we would be required to satisfy our obligations under those derivative contracts on potentially unfavorable terms without the ability to offset that risk through sales of comparable quantities of our own production. Additionally, because the terms of our derivative contracts are based on assumptions and estimates of numerous factors such as cost of production and pipeline and other transportation and marketing costs to delivery points, substantial differences between the prices we receive pursuant to our derivative contracts and our actual results could harm our anticipated profit margins and our ability to manage the risk associated with fluctuations in oil and natural gas prices. We also could be financially harmed if the counterparties to our derivative contracts prove unable or unwilling to perform their obligations under such contracts. Additionally, before our 2010 recapitalization (as described below under “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Overview”), some of our derivative contracts required us to deliver cash collateral or other assurances of performance to the counterparties if our payment obligations exceeded certain levels. Future collateral requirements are uncertain but will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and future rules and regulations to be promulgated by the Commodities Futures Trading Commission (“CFTC”), pursuant to the mandate of the United States Congress under the Dodd-Frank Wall Street Reform and Consumer Protection Act. See also “— Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.”

The lack of availability or high cost of drilling rigs, crews, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploitation and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, crews, equipment, supplies, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. If increasing levels of exploitation and

production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in our areas of operation, our results of operations could be materially and adversely affected.

We depend on our key management personnel and technical experts and the loss any of these individuals could adversely affect our business.

If we lose the services of our key management personnel or technical experts, or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could be adversely affected. We depend upon the knowledge, skill and experience of these experts to assist us in improving the performance and reducing the risks associated with our participation in oil and natural gas exploitation and development projects. The loss of the services of one or more members of our senior management or technical teams could have a negative effect on our business, financial condition, results of operations and future growth.

Our properties are located in regions which make us vulnerable to risks associated with operating in one major contiguous geographic area, including the risk and related costs of damage or business interruptions from hurricanes.

Our properties are primarily located onshore and in state and federal waters along the Texas and Louisiana Gulf Coast region of the United States. As a result of this geographic concentration, we are disproportionately affected by any delays or interruptions in production or transportation in these areas caused by governmental regulation, transportation capacity constraints, natural disasters, regional price fluctuations and other factors. This is particularly true of our inland water drilling and offshore operations, which are susceptible to hurricanes and other tropical weather disturbances. Such disturbances have in the past and will in the future have any or all of the following adverse effects on our business:


	•	interruptions to our operations as we suspend production in advance of an approaching storm;

	•	damage to our facilities and equipment, including damage that disrupts or delays our production;

	•	disruption to the transportation systems we rely upon to deliver our products to our customers; and

	•	damage to or disruption of our customers’ facilities that prevents us from taking delivery of our products.

For example, in 2008, Hurricanes Gustav and Ike disrupted our Gulf Coast operations forcing us to temporarily curtail production for approximately 30 days. Although we maintain property and casualty insurance, we cannot predict whether we will continue to be able to obtain insurance for hurricane-related damages or, if obtainable and carried, whether this insurance will be adequate to cover our liabilities. In addition, we expect any insurance of this nature to be subject to substantial deductibles and to provide for premium adjustments based on claims. Any future hurricane-related costs and work interruptions could adversely affect our operations and financial condition.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are extended.

Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production in paying quantities is established during their primary terms or we obtain extensions of the leases. Our drilling plans for our undeveloped leasehold acreage are subject to change based upon various factors, including factors that are beyond our control, such as drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Because of these uncertainties, we do not know if our undeveloped leasehold acreage will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations. If our leases expire, we will lose our right to develop the

related properties on this acreage. As of December 31, 2010, we had leases representing 8,192 net acres expiring in 2011, 1,761 net acres expiring in 2012, and 1,434 net acres expiring in 2013. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our exploitation, development and drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.

We require significant amounts of undeveloped leasehold acreage to further our development efforts. Exploitation, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon our initial investments. Additionally, we cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new wells drilled by us in areas that we pursue will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. Wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results is dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

Although we aim to control and reduce our drilling and production costs to improve our overall return, the cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:


	•	unexpected drilling conditions;

	•	low prices for oil and natural gas;

	•	title problems;

	•	pressure or irregularities in formations;

	•	delays by project participants;

	•	equipment failures or accidents;

	•	adverse weather conditions;

	•	compliance with governmental requirements;

	•	shortages or delays in the availability of drilling rigs and the delivery of equipment; and

	•	increases in the cost for equipment and services.

We may not drill all of our potential drilling locations and drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.

Our drilling locations are in various stages of evaluation, ranging from locations that are ready to be drilled to potential locations that will require substantial additional evaluation and interpretation. A decision to drill any specific well on our inventory of potential well locations may not be made for many years, if at all. If a decision is made to drill, we cannot conclusively predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover our drilling or completion costs or to be economically viable. Our 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 and natural gas will be present or, if present, whether oil and natural gas will be present in commercial quantities.

The analysis that we perform using data from other wells, more fully explored prospectsand/or analogous producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling locations. As a result, we may not find commercially viable quantities of oil and natural gas and, therefore, we may not achieve a targeted rate of return or have a positive return on investment.

The marketability of our oil and natural gas production depends on services and facilities that we typically do not own or control. The failure or inaccessibility of any such services or facilities could affect market based prices or result in a curtailment of production and revenues.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of oil and natural gas gathering and transportation systems, pipelines and processing facilities. We generally deliver oil at our leases under short-term trucking contracts. Counterparties to our short-term contracts rely on access to regional transportation systems and pipelines. If transportation systems or pipeline capacity is constrained, we would be required to find alternative transportation modes, which would impact the market based price that we receive, or temporarily curtail production. We generally sell our natural gas production at the wellhead. The transportation of our natural gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. If any of the pipelines or other facilities that we use to transport our natural gas production become unavailable, we would be required to find a suitable alternative to transport and process the natural gas, which could increase our costs and reduce the revenues we might obtain from the sale of the natural gas. For example, in 2008, Hurricanes Gustav and Ike disrupted our Gulf Coast operations forcing us to temporarily curtail production for approximately 30 days.

We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.

Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as:


	•	fires;

	•	natural disasters;

	•	formations with abnormal pressures;

	•	blowouts, mechanical failures and explosions; and

	•	pipeline ruptures and spills.

Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

We cannot predict all liabilities and costs related to expanding our geographic diversity. The incurrence of material unanticipated liabilities could have a material adverse effect on our business, financial condition and results of operation.

We intend to grow our reserve base primarily through asset acquisitions and the further exploitation and development of acquired and existing assets, with a focus on properties that are weighted towards oil or NGLs and provide greater geographic diversity. Historically we have operated properties only in the Gulf Coast region. We cannot assure you that we will be successful in expanding our operations into regions outside of our core areas. Operating in areas outside the Gulf Coast region may expose us to unanticipated liabilities and costs, some of which may be material. As a result, the anticipated benefits of moving into the region may not be fully realized, if at all, which could have a material adverse effect on our business, financial condition and results of operation.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use independent contractors to provide us with technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production. In addition, we rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.

We may be unable to successfully integrate the properties and assets we acquire with our existing operations.

Integration of the properties and assets we acquire may be a complex, time consuming and costly process. Failure to timely and successfully integrate these assets and properties with our operations may have a material adverse effect on our business, financial condition and results of operations. The difficulties of integrating these assets and properties present numerous risks, including:


	•	acquisitions may prove unprofitable and fail to generate anticipated cash flows;

	•	we may need to (i) recruit additional personnel, and we cannot be certain that any of our recruiting efforts will succeed and (ii) expand corporate infrastructure to facilitate the integration of our operations with those associated with the acquired properties, and failure to do so may lead to disruptions in our ongoing businesses or distract our management; and

	•	our management’s resources may be diverted from other business concerns.

We are also exposed to risks that are commonly associated with acquisitions of this type, such as unanticipated liabilities and costs, some of which may be material. As a result, the anticipated benefits of acquiring assets and properties may not be fully realized, if at all.

We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure.

We maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We may elect not to carry insurance if our management believes that the cost of insurance is excessive relative to the risks presented. If an event occurs that is not covered, or not fully covered, by insurance, it could harm our financial condition, results of operations and cash flows. In addition, we cannot fully insure against pollution and environmental risks.

The loss of a significant customer could in the short term have a material adverse impact on our financial results.

During 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues, with Enterprise Crude Oil LLC accounting for 11% and Shell Trading (US) Company accounting for 19%. During 2009, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 16%. During 2008, ten customers collectively accounted for 66% of our oil and natural gas revenues, with Plains Marketing LP accounting for 12% and Shell Trading (US) Company accounting for 17%. Although we believe that the availability of other potential purchasers would limit the effects of the loss of one or more of these customers, such a loss could in the short term have a material adverse effect on our results of operations.

Our future operating results may fluctuate and significant declines in them may limit our ability to invest in projects.

Our future operating results may fluctuate significantly depending upon a number of factors, including:


	•	industry conditions;

	•	prices of oil and natural gas;

	•	rates of drilling success;

	•	availability of capital resources;

	•	rates of production from completed wells; and

	•	the timing and amount of capital expenditures.

This variability could cause our business, financial condition and results of operations to suffer. In addition, any failure or delay in the realization of expected cash flows from operating activities could limit our ability to invest and participate in economically attractive projects.

We face significant competition and many of our competitors have resources in excess of our available resources.

We operate in the highly competitive areas of oil and natural gas exploitation, acquisition and production. We face intense competition from a large number of independent, technology-driven companies as well as both major and other independent oil and natural gas companies in a number of areas such as:


	•	seeking to acquire desirable producing properties or new leases for future exploitation;

	•	seeking to hire professional personnel;

	•	seeking to acquire the equipment and expertise necessary to operate and develop those properties; and

	•	marketing our oil and natural gas production.

Many of our competitors have financial and other resources substantially in excess of those available to us. This highly competitive environment could harm our business.

We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

From time to time, in varying degrees, political developments and federal, state and local laws and regulations affect our operations. In particular, price controls, taxes and other laws relating to the oil and natural gas industry, changes in these laws and changes in administrative regulations have affected and in the future could affect oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or what effect these adoptions and interpretations may have on our business or financial condition.

Our business is subject to laws and regulations promulgated by federal, state and local authorities, including but not limited to, the United States Congress, the Federal Energy Regulatory Commission, the Environmental Protection Agency (the “EPA”), the Bureau of Land Management, the Bureau of Ocean Energy Management Regulation and Enforcement, the Texas Railroad Commission, the Texas Commission on Environmental Quality, the Oklahoma Corporation Commission, the Oklahoma Department of Environmental Quality, the Louisiana Department of Natural Resources, the Louisiana Department of Environmental Quality, the Mississippi Department of Environmental Quality and the Mississippi Oil & Gas Board, relating to the exploitation for, and the development, production and marketing of, oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of oil,

natural gas or pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs for remediation.

Our operations are subject to complex federal, state and local environmental laws and regulations, including the federal Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act and the Clean Water Act. Administration of the federal laws is often delegated to the states. Environmental laws and regulations change frequently, and the implementation of new, or the modification of existing, laws or regulations could harm us. For example, legislation to amend the Safe Drinking Water Act (the “SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress and similar legislation could be introduced in the current or future sessions of Congress. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the initial results of which are anticipated to be available by late 2012. In addition, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board released a report on August 11, 2011, proposing recommendations to reduce the potential environmental impacts from shale gas production. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic fracturing process. Furthermore, in July 2011, the EPA proposed several new emissions standards to reduce volatile organic compound (“VOC”) emissions from several types of processes and equipment used in the oil and natural gas industry, including a 95 percent reduction in VOCs emitted during the construction or modification of hydraulically-fractured wells. Additionally, on August 23, 2011, the EPA published a proposed rule in the Federal Register that would establish new air emission controls for oil and natural gas production and natural gas processing operations. The EPA is currently receiving public comment and recently conducted public hearings regarding the proposed rules and must take final action on them by February 28, 2012.

If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. Compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if such legislation is enacted into law. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations orclean-ups or in the incurrence of other unexpected material costs or liabilities.

Failure to comply with environmental, health and safety laws or regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining or limiting our current or future operations. Compliance with these laws and regulations also increases the cost of our operations and may prevent or delay the commencement or continuance of a given operation.

Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws 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. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with environmental, health, or safety

laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations.

We do not know how the ongoing reorganization of the BOEMRE will impact potential future regulations or enforcement that may affect our business.

On May 19, 2010, the U.S. Department of the Interior announced that it would reorganize the Minerals Management Service by dividing its offshore oil and gas responsibilities among three separate agencies. Shortly thereafter, on June 18, 2010, the Minerals Management Service was renamed the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”). The BOEMRE currently regulates offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Outer Continental Shelf, and removal of facilities. On October 1, 2010, the first phase of reorganization took place when the revenue collection arm of the former Mineral Management Service became the Office of Natural Resources Revenue. On January 19, 2011, the U.S. Department of the Interior announced the structures and responsibilities of the two remaining agencies, with the reorganization of BOEMRE into these agencies to be completed in 2011. The U.S. Department of the Interior will create the Bureau of Ocean Energy Management, which will have responsibility for leasing, resource evaluation and environmental studies, and the Bureau of Safety and Environmental Enforcement, which will have responsibility for field operations, including inspections, regulatory compliance, permitting and oil spill response. Once the reorganization is completed, the BOEMRE will cease to exist. We have a non-operating interest in nine offshore fields in the Outer Continental Shelf off the coast of Louisiana which are subject to BOEMRE jurisdiction. At this time, we cannot predict the impact that this reorganization, or future regulations or enforcement actions taken by the new agencies, may have on our business.

Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which contains comprehensive financial reform legislation that establishes federal oversight and regulation of theover-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by President Obama on July 21, 2010 and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation. 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 Dodd-Frank Act contains significant derivatives regulation, including provisions requiring certain transactions to be cleared on exchanges and containing a requirement to post cash collateral (commonly referred to as “margin”) for such transactions as well as certain clearing and trade-execution requirements in connection with our derivative activities. The Dodd-Frank Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and to the parties to those transactions. However, we do not know the definitions that the CFTC will actually promulgate or how these definitions will apply to us. The Dodd-Frank Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities into a separate entity, which may not be as creditworthy as the current counterparty.

Depending on the rules and definitions adopted by the CFTC, we could be required to post collateral with our dealer counterparties for our commodities hedging transactions. The Dodd-Frank Act and any new regulations promulgated thereunder could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity, thereby reducing our ability to use cash for investment or other corporate purposes, or require us to increase our level of indebtedness), 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 Dodd-Frank Act and the regulations promulgated thereunder, 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 Dodd-Frank Act 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 Dodd-Frank Act and regulations promulgated thereunder is to lower commodity prices. In addition, a requirement for our counterparties to post collateral would likely result in additional costs being passed on to us, thereby decreasing the effectiveness of our hedges and our profitability. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

The adoption of climate change legislation by Congress could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities and result in reduced demand for the oil and natural gas we produce.

There are state, national and international efforts to regulate the emission of greenhouse gases including, most significantly, carbon dioxide. The United States Congress has previously considered legislation that seeks to control or reduce emissions of greenhouse gases from a variety of sources. In addition, several states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories or regionalcap-and-trade programs. It is uncertain at this time whether, and in what form, climate change legislation will ultimately be adopted in the United States.

In addition to the pending climate legislation, the EPA has implemented regulations pertaining to greenhouse gas emissions. In 2009, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations, and the EPA finalized a greenhouse gas emission standard for mobile sources. On September 22, 2009, the EPA finalized a greenhouse gas reporting rule that requires large sources of greenhouse gas emissions to monitor, maintain records on, and annually report their greenhouse gas emissions. On November 8, 2010, the EPA also issued greenhouse gas monitoring and reporting regulations that went into effect on December 30, 2010, specifically for petroleum and natural gas facilities, including onshore and offshore petroleum and natural gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule requires reporting of greenhouse gas emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for greenhouse gas emissions, beginning in 2011, under the Clean Air Act. Several of the EPA’s greenhouse gas rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce, depending on the applicability to our operations and the refining, processing, and use of oil and natural gas.

Our ability to use net operating losses to offset future taxable income may be subject to certain limitations.

As of December 31, 2010, we had federal net operating loss carryforwards (“NOLs”) of $17.4 million to offset future taxable income, which expire in various years beginning in 2030, if not utilized. As a result of the evaluation of the likelihood that the deferred tax asset will not be realized, we applied a valuation

allowance for this deferred tax asset along with all other deferred tax assets that are a result of normal differences in GAAP treatment and applicable tax laws. This valuation will be assessed in the future based on relevant financial data and projections. In addition, under Section 382 of the U.S. Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), a corporation that experiences a more-than 50 percent ownership change over a three-year testing period is subject to limitations on its ability to utilize its pre-change NOLs to offset future taxable income.

We must increase our staff and will incur increased costs as a result of being a reporting company.

As a result of the exchange offer contemplated by this prospectus, we will become subject to the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and as a result will be required to comply with the reporting obligations of a publicly traded company. We must hire additional personnel or engage third party providers to meet our obligations with respect to internal controls and disclosure requirements. We also expect to engage additional accounting resources. In addition, we anticipate that our director and officer liability insurance premiums will increase. These additional obligations and responsibilities will require us to incur significant legal, accounting and other expenses that we did not incur as a non-reporting private company.

We have identified material weaknesses in our internal control over financial reporting.

We have identified material weaknesses in our internal control over financial reporting related to inconsistent or ineffective financial statement review and preparation and insufficient financial reporting resources. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected and corrected on a timely basis.

Although we intend to take appropriate steps to remediate these material weaknesses, we cannot assure you that we will be able to do so in a timely manner, that our initiatives will prove to be successful or that additional material weaknesses will not be identified in the future. Failure to identify material weaknesses in our internal controls in a timely manner, or the identification of material weaknesses in the future, will impair our ability to record, process, summarize and report financial information accurately, timely and in accordance with SEC rules, when we become a SEC reporting company. The failure could also negatively affect the trading liquidity of our notes, cause investors to lose confidence in our reported financial information, subject us to civil and criminal investigations and penalties and adversely impact our business and financial condition.

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our historical consolidated ratio of earning to fixed charges for the periods shown:

Year Ended

Six Months Ended June 30,

December 31,

2011

2010

2009

2008

Ratio of earnings to fixed charges

—

1.24

—

THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

We sold $250,000,000 aggregate principal amount of the old notes in a private offering, which was completed on May 11, 2011. In connection with the offering of the old notes, we entered into a registration rights agreement with the initial purchasers of the old notes, pursuant to which we agreed to file a registration statement relating to an offer to exchange the old notes for the exchange notes. The registration statement of which this prospectus forms a part was filed in compliance with this obligation. We also agreed to use our commercially reasonable efforts to cause the registration statement to be declared effective by the SEC.

Pursuant to the exchange offer, we will issue the exchange notes in exchange for old notes. The terms of the exchange notes are identical in all material respects to those of the old notes, except that the exchange notes (1) have been registered under the Securities Act and therefore will not be subject to certain restrictions on transfer applicable to the old notes and (2) will not have registration rights or provide for any additional interest related to the obligation to register. Please read “Description of the Exchange Notes” for more information on the terms of the respective notes and the differences between them.

We are not making the exchange offer to, and will not accept tenders for exchange from, holders of old notes in any jurisdiction in which an exchange offer or the acceptance thereof would not be in compliance with the securities or blue sky laws of such jurisdiction. Unless the context requires otherwise, the term “holder” with respect to the exchange offer means any person in whose name the old notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder, or any person whose old notes are held of record by The Depository Trust Company (the “Depository”), who desires to deliver such old notes by book-entry transfer at the Depository.

We make no recommendation to the holders of old notes as to whether to tender or refrain from tendering all or any portion of their old notes pursuant to the exchange offer. In addition, no one has been authorized to make any such recommendation. Holders of old notes must make their own decision whether to tender pursuant to the exchange offer and, if so, the aggregate amount of old notes to tender after reading this prospectus and the letter of transmittal and consulting with the advisers, if any, based on their own financial position and requirements.

In order to participate in the exchange offer, you must represent to us, among other things, that:


	•	you are acquiring the exchange notes in the exchange offer in the ordinary course of your business;

	•	you are not engaged in, and do not intend to engage in, a distribution of the exchange notes;

	•	you have full power and authority to transfer old notes in exchange for the exchange notes and that we will acquire good and unencumbered title thereto free and clear of any liens, restrictions, charges or encumbrances and not subject to any adverse claims;

	•	you do not have and to your knowledge, no one receiving exchange notes from you has, any arrangement or understanding with any person to participate in the distribution of the exchange notes;

	•	you are not a broker-dealer tendering old notes acquired directly from us for your own account or if you are a broker-dealer, you will comply with the prospectus delivery requirements of the Securities Act in connection with any resale of the exchange notes; and

	•	you are not one of our “affiliates,” as defined in Rule 405 of the Securities Act.

Each broker-dealer that receives exchange notes for its own account 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, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. Please read “Plan of Distribution.”

Terms of the Exchange Offer

Upon the terms and conditions described in this prospectus and in the accompanying letter of transmittal, which together constitute the exchange offer, we will accept for exchange old notes that are properly tendered at or before the expiration time and not withdrawn as permitted below. As of the date of this prospectus, $250,000,000 aggregate principal amount of old notes are outstanding. This prospectus, together with the letter of transmittal, is first being sent on or about the date on the cover page of the prospectus to all holders of old notes known to us. Old notes tendered in the exchange offer must be in denominations of principal amount of $2,000 and any integral multiple of $1,000. The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

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.

Our acceptance of the tender of old notes by a tendering holder will form a binding agreement between the tendering holder and us upon the terms and subject to the conditions provided in this prospectus and in the accompanying letter of transmittal.

The form and terms of the exchange notes being issued in the exchange offer are the same as the form and terms of the old notes, except that:


	•	the exchange notes being issued in the exchange offer will have been registered under the Securities Act;

	•	the exchange notes being issued in the exchange offer will not bear the restrictive legends restricting their transfer under the Securities Act; and

	•	the exchange notes being issued in the exchange offer will not contain the registration rights contained in the old notes.

Expiration, Extension and Amendment

The expiration time of the exchange offer is 5:00 P.M., New York City time, on December 13, 2011. However, we may, in our sole discretion, extend the period of time for which the exchange offer is open and set a later expiration date for the exchange offer. The term “expiration time” as used herein means the latest time and date to which we extend the exchange offer. If we decide to extend the exchange offer period, we will then delay acceptance of any old notes by giving oral or written notice of an extension to the holders of old notes as described below. During any extension period, all old notes previously tendered will remain subject to the exchange offer and may be accepted for exchange by us. Any old notes not accepted for exchange will be returned to the tendering holder after the expiration or termination of the exchange offer.

Our obligation to accept old notes for exchange in the exchange offer is subject to the conditions described below under “— Conditions to the Exchange Offer.” We may decide to waive any of the conditions in our sole reasonable discretion. Furthermore, we reserve the right to amend or terminate the exchange offer, and not to accept for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified below under the same heading. We will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable. If we materially change the terms of the exchange offer, we will resolicit tenders of the old notes, file a post-effective amendment to the prospectus and provide notice to you. If the change is made less than five business days before the expiration of the exchange offer, we will extend the offer so that the holders have at least five business days to tender or withdraw. We will notify you of any extension by means of a press release or other public announcement no later than 9:00 A.M., New York City time, on the first business day after the previously scheduled expiration time.

Procedures for Tendering

Valid Tender

Except as described below, a tendering holder must, prior to the expiration time, transmit to Wells Fargo Bank, National Association, the exchange agent, at the address listed below under the caption “— Exchange Agent”:


	•	a properly completed and duly executed letter of transmittal, including all other documents required by the letter of transmittal; or

	•	if old notes are tendered in accordance with the book-entry procedures listed below, an agent’s message transmitted through the Depository’s Automated Tender Offer Program, referred to as ATOP.

In addition, you must:


	•	deliver certificates, if any, for the old notes to the exchange agent at or before the expiration time;

	•	deliver a timely confirmation of the book-entry transfer of the old notes into the exchange agent’s account at the Depository, the book-entry transfer facility, along with the letter of transmittal or an agent’s message; or

	•	comply with the guaranteed delivery procedures described below.

The term “agent’s message” means a message, transmitted by the Depository to, and received by, the exchange agent and forming a part of a book-entry confirmation, that states that the Depository has received an express acknowledgment that the tendering holder agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against such holder.

If the letter of transmittal is signed by a person other than the registered holder of old notes, the letter of transmittal must be accompanied by a written instrument of transfer or exchange in satisfactory form duly executed by the registered holder with the signature guaranteed by an eligible institution. The old notes must be endorsed or accompanied by appropriate powers of attorney. In either case, the old notes must be signed exactly as the name of any registered holder appears on the old notes.

If the letter of transmittal or any old notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless waived by us, proper evidence satisfactory to us of their authority to so act must be submitted.

By tendering, each holder will represent to us that, among other things, the person is not our affiliate, the exchange notes are being acquired in the ordinary course of business of the person receiving the exchange notes, whether or not that person is the holder, and neither the holder nor the other person has any arrangement or understanding with any person to participate in the distribution of the exchange notes. Each broker-dealer that receives exchange notes for its own account 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, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. Please read “Plan of Distribution.”

The method of delivery of old notes, letters of transmittal and all other required documents is at your election and risk, and the delivery will be deemed made only upon actual receipt or confirmation by the exchange agent. If the delivery is by mail, we recommend that you use registered mail, properly insured, with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery. Holders tendering through the Depository’s ATOP system should allow sufficient time for completion of the ATOP procedures during the normal business hours of the Depository on such dates.

No old notes, agent’s messages, letters of transmittal or other required documents should be sent to us. Delivery of all old notes, agent’s messages, letters of transmittal and other documents must be made to the exchange agent. Holders may also request their respective brokers, dealers, commercial banks, trust companies or nominees to effect such tender for such holders.

If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and wish to tender, you should promptly instruct the registered holder to tender on your behalf. Any registered holder that is a participant in the Depository’s ATOP system may make book-entry delivery of the old notes by causing the Depository to transfer the old notes into the exchange agent’s account. The tender by a holder of old notes, including pursuant to the delivery of an agent’s message through the Depository’s ATOP system, will constitute an agreement between such holder and us in accordance with the terms and subject to the conditions set forth herein and in the letter of transmittal.

All questions as to the validity, form, eligibility, time of receipt and withdrawal of the tendered old notes will be determined by us in our sole reasonable discretion or by the exchange agent, which determination will be final and binding. We reserve the absolute right to reject any and all old notes not validly tendered or any old notes which, if accepted, would, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of this exchange offer, including the instructions in 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 we shall determine. Although we intend to notify you of defects or irregularities with respect to tenders of old notes, none of us, the exchange agent, or any other person shall be under any duty to give notification of defects or irregularities with respect to tenders of old notes, nor shall any of them incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such irregularities have been cured or waived. Any old notes received by the exchange agent that are not validly tendered and as to which the defects or irregularities have not been cured or waived will be returned without cost to such holder by the exchange agent, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date of the exchange offer.

Although we have no present plan to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any old notes that are not tendered in the exchange offer, we reserve the right, in our sole discretion, to purchase or make offers for any old notes after the expiration date of the exchange offer, from time to time, through open market or privately negotiated transactions, one or more additional exchange or tender offers, or otherwise, as permitted by law, the indenture and our other debt agreements. Following consummation of this exchange offer, the terms of any such purchases or offers could differ materially from the terms of this exchange offer.

Signature Guarantees

Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed, unless the old notes surrendered for exchange are tendered:


	•	by a registered holder of the old notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal, or

	•	for the account of an “eligible institution.”

If signatures on a letter of transmittal or a notice of withdrawal are required to be guaranteed, the guarantees must be by an “eligible institution.” An “eligible institution” is an “eligible guarantor institution” meeting the requirements of the registrar for the notes within the meaning ofRule 17Ad-15 under the Exchange Act.

Book-Entry Transfer

The exchange agent will make a request to establish an account for the old notes at the Depository for purposes of the exchange offer. Any financial institution that is a participant in the Depository’s system may make book-entry delivery of old notes by causing the Depository to transfer those old notes into the exchange agent’s account at the Depository in accordance with the Depository’s procedure for transfer. The participant should transmit its acceptance to the Depository at or prior to the expiration time or comply with the guaranteed delivery procedures described below. The Depository will verify this acceptance, execute a book-entry transfer of the tendered old notes into the exchange agent’s account at the Depository and then send to

the exchange agent confirmation of this book-entry transfer. The confirmation of this book-entry transfer will include an agent’s message confirming that the Depository has received an express acknowledgment from this participant that this participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this participant.

Delivery of exchange notes issued in the exchange offer may be effected through book-entry transfer at the Depository. However, the letter of transmittal or facsimile of it or an agent’s message, with any required signature guarantees and any other required documents, must:


	•	be transmitted to and received by the exchange agent at the address listed under “— Exchange Agent” at or prior to the expiration time; or

	•	comply with the guaranteed delivery procedures described below.

Delivery of documents to the Depository in accordance with the Depository’s procedures does not constitute delivery to the exchange agent.

Guaranteed Delivery

If a registered holder of old notes desires to tender the old notes, and the old notes are not immediately available, or time will not permit the holder’s old notes or other required documents to reach the exchange agent before the expiration time, or the procedures for book-entry transfer described above cannot be completed on a timely basis, a tender may nonetheless be made if:


	•	the tender is made through an eligible institution;

	•	prior to the expiration time, the exchange agent receives by facsimile transmission, mail or hand delivery from such eligible institution a properly and validly completed and duly executed notice of guaranteed delivery, substantially in the form provided by us:

1. stating the name and address of the holder of old notes and the amount of old notes tendered,

2. stating that the tender is being made, and

3. guaranteeing that within three New York Stock Exchange trading days after the expiration time, the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and


	•	the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and all other documents required by the letter of transmittal, are received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery.

Determination of Validity

We will determine in our sole reasonable discretion all questions as to the validity, form and eligibility of old notes tendered for exchange. This discretion extends to the determination of all questions concerning the timing of receipts and acceptance of tenders. These determinations will be final and binding. We reserve the right to reject any particular old note not properly tendered or of which our acceptance might, in our judgment or our counsel’s judgment, be unlawful. We also reserve the right to waive any defects or irregularities or conditions of the exchange offer as to any particular old note either before or after the expiration time, including the right to waive the ineligibility of any tendering holder. Our interpretation of the terms and conditions of the exchange offer as to any particular old note either before or after the applicable expiration time, including the letter of transmittal and the instructions to the letter of transmittal, shall be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within a reasonable period of time.

Neither we, the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity in any tender of old notes. Moreover, neither we, the exchange agent nor any other person will incur any liability for failing to give notifications of any defect or irregularity.

Acceptance of Old Notes for Exchange; Issuance of Exchange Notes

Upon the terms and subject to the conditions of the exchange offer, we will accept, promptly after the expiration time, all old notes properly tendered. We will issue the exchange notes promptly after acceptance of the old notes. For purposes of an exchange offer, we will be deemed to have accepted properly tendered old notes for exchange when, as and if we have given oral or written notice to the exchange agent, with prompt written confirmation of any oral notice.

For each old note accepted for exchange, the holder will receive a new note having a principal amount equal to that of the surrendered old note. As a result, registered holders of exchange notes issued in the exchange offer on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid on the old notes or, if no interest has been paid on the old notes, from May 11, 2011. Old notes that we accept for exchange will cease to accrue interest from and after the date of completion of the exchange offer. Under the registration rights agreement, we may be required to make additional payments in the form of additional interest to the holders of the old notes under circumstances relating to the timing of the exchange offer.

In all cases, issuance of exchange notes for old notes will be made only after timely receipt by the exchange agent of:


	•	certificate for the old notes, or a timely book-entry confirmation of the old notes, into the exchange agent’s account at the book-entry transfer facility;

	•	a properly completed and duly executed letter of transmittal or an agent’s message; and

	•	all other required documents.

Unaccepted or non-exchanged old notes will be returned without expense to the tendering holder of the old notes. In the case of old notes tendered by book-entry transfer in accordance with the book-entry procedures described above, the non-exchanged old notes will be credited to an account maintained with the Depository as promptly as practicable after the expiration or termination of the exchange offer. For each old note accepted for exchange, the holder of the old note will receive an exchange note having a principal amount equal to that of the surrendered outstanding note.

Interest Payments on the Exchange Notes

The exchange notes will bear interest from the most recent date to which interest has been paid on the old notes for which they were exchanged. Accordingly, registered holders of exchange notes on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid. Old notes accepted for exchange will cease to accrue interest from and after the date of completion of the exchange offer and will be deemed to have waived their rights to receive the accrued interest on the old notes.

Withdrawal Rights

Tender of old notes may be properly withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.

For a withdrawal to be effective with respect to old notes, the exchange agent must receive a written notice of withdrawal before the expiration time delivered by hand, overnight by courier or by mail, at the address indicated under “— Exchange Agent” or, in the case of eligible institutions, at the facsimile number,

or a properly transmitted “Request Message” through the Depository’s ATOP system. Any notice of withdrawal must:


	•	specify the name of the person, referred to as the depositor, having tendered the old notes to be withdrawn;

	•	identify the old notes to be withdrawn, including certificate numbers and principal amount of the old notes;

	•	contain a statement that the holder is withdrawing its election to have the old notes exchanged;

	•	other than a notice transmitted through the Depository’s ATOP system, be signed by the holder in the same manner as the original signature on the letter of transmittal by which the old notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer to have the trustee with respect to the old notes register the transfer of the old notes in the name of the person withdrawing the tender; and

	•	specify the name in which the old notes are registered, if different from that of the depositor.

If certificates for old notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of these certificates the withdrawing holder must also submit the serial numbers of the particular certificates to be withdrawn and signed notice of withdrawal with signatures guaranteed by an eligible institution, unless this holder is an eligible institution. If old notes have been tendered in accordance with the procedure for book-entry transfer described below, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn old notes.

Any old notes properly withdrawn will be deemed not to have been validly tendered for exchange. Exchange notes will not be issued in exchange unless the old notes so withdrawn are validly re-tendered.

Properly withdrawn old notes may be re-tendered by following the procedures described under “— Procedures for Tendering” above at any time at or before the expiration time.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal.

Conditions to the Exchange Offer

Notwithstanding any other provisions of the exchange offer, or any extension of the exchange offer, we will not be required to accept for exchange, or to exchange, any old notes for any exchange notes, and, as described below, may terminate the exchange offer, whether or not any old notes have been accepted for exchange, or may waive any conditions to or amend the exchange offer, if any of the following conditions has occurred or exists:


	•	there shall occur a change in the current interpretation by the staff of the SEC which permits the exchange notes issued pursuant to the exchange offer in exchange for old notes to be offered for resale, resold and otherwise transferred by the holders (other than broker-dealers and any holder which is an affiliate) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such exchange notes are acquired in the ordinary course of such holders’ business and such holders have no arrangement or understanding with any person to participate in the distribution of the exchange notes;

	•	any action or proceeding shall have been instituted or threatened in any court or by or before any governmental agency or body seeking to enjoin, make illegal or delay completion of the exchange offer or otherwise relating to the exchange offer;

	•	any law, statute, rule or regulation shall have been adopted or enacted which, in our judgment, would reasonably be expected to impair our ability to proceed with such exchange offer;

	•	a banking moratorium shall have been declared by United States federal or New York State authorities;


	•	trading on the New York Stock Exchange or generally in the United Statesover-the-counter market shall have been suspended, or a limitation on prices for securities imposed, by order of the SEC or any other governmental authority;

	•	an attack on the United States, an outbreak or escalation of hostilities or acts of terrorism involving the United States, or any declaration by the United States of a national emergency or war shall have occurred;

	•	a stop order shall have been issued by the SEC or any state securities authority suspending the effectiveness of the registration statement of which this prospectus is a part or proceedings shall have been initiated or, to our knowledge, threatened for that purpose or any governmental approval has not been obtained, which approval we shall, in our sole reasonable discretion, deem necessary for the consummation of such exchange offer; or

	•	any change, or any development involving a prospective change, in our business or financial affairs or any of our subsidiaries has occurred which is or may be adverse to us or we shall have become aware of facts that have or may have an adverse impact on the value of the old notes or the exchange notes, which in our sole judgment in any case makes it inadvisable to proceed with such exchange offerand/or with such acceptance for exchange or with such exchange.

If any of the foregoing events or conditions has occurred or exists, we may, subject to applicable law, terminate the exchange offer, whether or not any old notes have been accepted for exchange, or may waive any such condition or otherwise amend the terms of such exchange offer in any respect. Please read “— Expiration, Extension and Amendment” above.

If any of the above events occur, we may:


	•	terminate the exchange offer and promptly return all tendered old notes to tendering holders;

	•	completeand/or extend the exchange offer and, subject to your withdrawal rights, retain all tendered old notes until the extended exchange offer expires;

	•	amend the terms of the exchange offer; or

	•	waive any unsatisfied condition and, subject to any requirement to extend the period of time during which the exchange offer is open, complete the exchange offer.

We may assert these conditions with respect to the exchange offer regardless of the circumstances giving rise to them. All conditions to the exchange offer, other than those dependent upon receipt of necessary government approvals, must be satisfied or waived by us before the expiration of the exchange offer. We may waive any condition in whole or in part at any time in our sole reasonable discretion. Our failure to exercise our rights under any of the above circumstances does not represent a waiver of these rights. Each right is an ongoing right that may be asserted at any time. Any determination by us concerning the conditions described above will be final and binding upon all parties.

If a waiver constitutes a material change to the exchange offer, we will promptly disclose the waiver by means of a prospectus supplement that we will distribute to the registered holders of the old notes, and we will extend the exchange offer for a period of five to ten business days, as required by applicable law, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the exchange offer would otherwise expire during the five to ten business day period.

Resales of Exchange Notes

Based on interpretations by the staff of the SEC, as described in no-action letters issued to third parties that are not related to us, we believe that exchange notes issued in the exchange offer in exchange for old notes may be offered for resale, resold or otherwise transferred by holders of the exchange notes without compliance with the registration and prospectus delivery provisions of the Securities Act, if:


	•	the exchange notes are acquired in the ordinary course of the holder’s business;


	•	the holders have no arrangement or understanding with any person to participate in the distribution of the exchange notes;

	•	the holders are not “affiliates” of ours within the meaning of Rule 405 under the Securities Act; and

	•	the holders are not a broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act.

However, the SEC has not considered the exchange offer described in this prospectus in the context of a no-action letter. The staff of the SEC may not make a similar determination with respect to the exchange offer as in the other circumstances. Each holder who wishes to exchange old notes for exchange notes will be required to represent that it meets the above four requirements.

Any holder who is an affiliate of ours or who intends to participate in the exchange offer for the purpose of distributing exchange notes or any broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act:


	•	cannot rely on the applicable interpretations of the staff of the SEC mentioned above;

	•	will not be permitted or entitled to tender the old notes in the exchange offer; and

	•	must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any secondary resale transaction.

Each broker-dealer that receives exchange notes for its own account in exchange for old notes must acknowledge that the old notes were acquired by it as a result of market-making activities or other trading activities and agree that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the exchange 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. Please read “Plan of Distribution.” A broker-dealer may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resales of exchange notes received in exchange for old notes that the broker-dealer acquired as a result of market-making or other trading activities. Any holder that is a broker-dealer participating in the exchange offer must notify the exchange agent at the telephone number set forth in the enclosed letter of transmittal and must comply with the procedures for broker-dealers participating in the exchange offer. We have not entered into any arrangement or understanding with any person to distribute the exchange notes to be received in the exchange offer.

In addition, to comply with state securities laws, the exchange notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification, with which there has been compliance, is available. The offer and sale of the exchange notes to “qualified institutional buyers,” as defined under Rule 144A of the Securities Act, is generally exempt from registration or qualification under the state securities laws. We currently do not intend to register or qualify the sale of exchange notes in any state where an exemption from registration or qualification is required and not available.

Exchange Agent

Wells Fargo Bank, National Association, has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal and any other required documents should be directed to the exchange agent at the address or facsimile number set forth below. Questions and requests for assistance, requests for

additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent addressed as follows:

WELLS FARGO BANK, NATIONAL ASSOCIATION


Delivery by Registered or Certified Mail:	Facsimile Transmissions: (Eligible Institutions Only)	Overnight Delivery or Regular Mail:
Wells Fargo Bank, National Association Corporate Trust Operations MAC N9303-121 P.O. Box 1517 Minneapolis, MN 55480	(612) 667-6282 To Confirm by Telephone or for Information Call: (800) 344-5128	Wells Fargo Bank, National Association Corporate Trust Operations MAC N9303-121 Sixth & Marquette Avenue Minneapolis, MN 55479

Delivery of the letter of transmittal to an address other than as set forth above or transmission of such letter of transmittal via facsimile other than as set forth above does not constitute a valid delivery of the letter of transmittal.

Fees and Expenses

We will pay the expenses of soliciting tenders pursuant to this exchange offer. We have agreed to pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonableout-of-pocket expenses in connection with the exchange offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonableout-of-pocket expenses incurred by them in forwarding copies of this prospectus and related documents to the beneficial owners of old notes, and in handling or tendering for their customers. We will not make any payment to brokers, dealers or others soliciting acceptances of the exchange offer.

Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes on the exchange. If, however, exchange notes are to be delivered to, or are to be issued in the name of, any person other than the registered holder of the old notes tendered, or if a transfer tax is imposed for any reason other than the exchange of old notes in connection with the exchange offer, then the amount of any such transfer taxes (whether imposed on the registered holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder.

Transfer Taxes

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.

Consequences of Failure to Exchange Outstanding Securities

Holders who desire to tender their old notes in exchange for exchange notes registered under the Securities Act should allow sufficient time to ensure timely delivery. Neither we nor the exchange agent are under any duty to give notification of defects or irregularities with respect to the tenders of old notes for exchange.

Old notes that are not tendered or are tendered but not accepted will, following the completion of the exchange offer, continue to be subject to the provisions in the indenture regarding the transfer and exchange of the old notes and the existing restrictions on transfer set forth in the legend on the old notes set forth in the indenture for the notes. Except in limited circumstances with respect to specific types of holders of old notes, we will have no further obligation to provide for the registration under the Securities Act of such old notes. In

general, old notes, unless registered under the Securities Act, may not be offered or sold except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws.

We do not currently anticipate that we will take any action to register the old notes under the Securities Act or under any state securities laws. Upon completion of the exchange offer, holders of the old notes will not be entitled to any further registration rights under the registration rights agreement, except under limited circumstances. Holders of the exchange notes issued in the exchange offer and any old notes which remain outstanding after completion of the exchange offer will vote together as a single class for purposes of determining whether holders of the requisite percentage of the class have taken certain actions or exercised certain rights under the indenture.

Accounting Treatment

We will record the exchange notes at the same carrying value as the old notes, as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. The expenses of the exchange offer will be amortized over the term of the exchange notes.

Other

Participation in the exchange offer is voluntary, and you should consider carefully 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.

USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any cash proceeds from the issuance of the exchange notes in the exchange offer. In consideration for issuing the exchange notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the exchange notes are identical in all respects to the form and terms of the old notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the old notes do not apply to the exchange notes. Old notes surrendered in exchange for the exchange notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the exchange notes will not result in any change in our outstanding indebtedness.

SELECTED CONSOLIDATED FINANCIAL DATA

The following table presents our selected historical financial data as of and for the one month ended December 31, 2007, the years 2008 through 2010 and for the six months ended June 30, 2010 and 2011. The statement of operations data for each of the years ended December 31, 2008 through 2010 and the balance sheet data as of December 31, 2009 and 2010 set forth below are derived from our audited financial statements and the notes thereto included elsewhere in this document. The balance sheet data as of December 31, 2007 and 2008 set forth below are derived from our audited financial statements. The statement of operations data for the one month ended December 31, 2007 is derived from our unaudited financial records. The consolidated statement of operations data for the six months ended June 30, 2010 and 2011 and the balance sheet data as of June 30, 2011 are derived from our unaudited financial statements included elsewhere in this document and, in the opinion of management, include all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the financial position and results of operations as of the dates and for the periods indicated. The results for periods of less than a full year are not necessarily indicative of the results to be expected for any interim period or for a full year. You should read this selected financial data in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited and unaudited financial statements and notes thereto included elsewhere in this document.

The table below does not include selected statements of operations and balance sheet data for our predecessor as of and for the year ended December 31, 2006 and for the eleven months ended November 30, 2007. A combination of factors results in our inability to provide the 2006 and 2007 selected historical financial data noted above without unreasonable effort and expense. These factors are: 1) our predecessor was not accounted for as a separate entity, subsidiary, or division by the previous owner, and as a result, the selected financial data for the predecessor for 2006 and the statement of operations data for the eleven months ended November 30, 2007 was not prepared and does not exist, and 2) we did not acquire the employees of the predecessor and as such the time and expense associated with preparing the applicable selected financial data for the predecessor would be unreasonable.


	Six Months Ended															One Month Ended
	June 30,						Years Ended December 31,									December 31,
	2011			2010			2010			2009			2008			2007
	(In thousands)

Operating data:
Revenues:
Oil and gas revenues	$	69,465		$	68,670		$	134,207		$	128,782		$	360,294		$	27,978
Hedge (loss)/gains		(3,564	)		22,018			22,943			25,606			50,259			(18,231	)

Total revenues	$	65,901		$	90,688		$	157,150		$	154,388		$	410,553		$	9,747
Costs and Expenses:
Operating costs	$	25,557		$	22,642		$	46,469		$	43,484		$	71,011		$	5,948
General and administrative(1)		7,122			8,689			17,469			18,849			19,499			3,549
Other		26,704			27,529			56,899			111,249			576,367			12,954

Total costs and expenses	$	59,383		$	58,860		$	120,837		$	173,582		$	666,877		$	22,451
Other (income) expense:
Other (income) expense	$	25,928		$	24,729		$	49,479		$	46,864		$	62,588		$	6,436

Total other (income) expense	$	25,928		$	24,729		$	49,479		$	46,864		$	62,588		$	6,436
Loss before income tax	$	(19,410	)	$	7,099		$	(13,166	)	$	(66,058	)	$	(318,912	)	$	(19,140	)

Income tax expense (benefit)(2)		—			57,422			57,422			(57,422	)		—			—

Net loss	$	(19,410	)	$	(50,323	)	$	(70,588	)	$	(8,636	)	$	(318,912	)	$	(19,140	)

Preferred dividends(4)		3,844			—			—			—			—			—
Net loss available to common stockholders	$	(23,254	)	$	(50,323	)	$	(70,588	)	$	(8,636	)	$	(318,912	)	$	(19,140	)


	As of			As of			As of			As of			As of
	June 30,			December 31,			December 31,			December 31,			December 31,
	2011			2010			2009			2008			2007
	(In thousands)

Balance sheet data:
Cash and cash equivalents	$	3,941		$	17,734		$	10,531		$	—		$	—
Net property, plant and equipment		456,934			453,185			392,904			515,822			895,426
Total assets		507,835			522,198			526,060			622,588			972,450
Long-term debt including current portion(3)		339,186			560,600			491,550			544,922			590,750
Mezzanine equity(4)		233,989			—			—			—			—
Stockholders’ (deficit) equity(5)		(155,240	)		(135,830	)		(67,032	)		(60,251	)		256,709
Total liabilities and stockholders’ deficit		507,835			522,198			526,060			622,588			972,450


(1)		Includes compensation expenses attributable to the issuance of Class C membership profits interests in our parent company, Milagro Holdings, LLC, to our officers and employees. For the six months ended June 30, 2011 and 2010, such expenses were zero and $894, respectively. For the years ended December 2010, 2009 and 2008, such expenses were $1,788, $1,951 and $1,951, respectively, and for the one month ended December 31, 2007, such expenses were zero. See “Security Ownership of Certain Beneficial Owners and Management” for more on the ownership of the Class C membership profits interests.

(2)		Effective on August 1, 2009, we converted from a limited liability company to a corporation under Sub Chapter C of the Internal Revenue Code of 1986, as amended.

(3)		On January 13, 2010, we entered into agreements to exchange a portion of our prior second lien debt and accrued interest for $205.5 million of our Series A Preferred Stock, consisting of 2,700,000 shares issued at $76.12 per share that were mandatorily redeemable in 2016. These shares were classified as a liability in the financial statements as they were mandatorily redeemable for cash.

(4)		On May 11, 2011, we amended the terms of our Series A Preferred Stock. The amendment made the Series A Preferred Stock a perpetual instrument and removed the mandatory redemption. The amended Series A Preferred Stock is redeemable at the option of the holder in 2016, and, as a result of the amendment, the Series A Preferred Stock was reclassified from long-term debt to mezzanine equity.

(5)		The stockholders’ deficit increase in 2010 as compared to 2009 is primarily a result of a deferred tax valuation allowance recorded in 2010. As a result of $244.6 million of indebtedness under our existing first lien credit agreement and our existing second lien term loan agreement becoming current as of November 30, 2010 and due as of November 30, 2011, we have included a going concern qualification in our financial statements for the year ended December 31, 2010. Because of this going concern qualification and the likelihood that a deferred tax asset will not be realized, we determined a 100% valuation allowance of the deferred tax asset was needed. We refinanced the indebtedness that has become current with the proceeds of the offering of the old notes and borrowings under our New Credit Facility. Since the offering of the old notes has been completed, we expect to re-evaluate this allowance and the deferred tax asset in connection with our annual evaluation performed during the year-end audit.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations together with our consolidated financial statements and the related notes and other financial information included elsewhere in this report. Some of the information contained in this discussion and analysis or set forth elsewhere in this report, including information with respect to our plans and strategy for our business and related financing, include forward-looking statements that involve risks and uncertainties. You should review the section entitled “Risk Factors” included elsewhere herein for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

For purposes of this Management’s Discussion and Analysis of Financial Condition and Results of Operation,” we refer to the old notes as the “Notes.”

Overview

We are an independent oil and gas company primarily engaged in the acquisition, exploitation, development and production of oil and natural gas reserves. We were formed as a limited liability company in 2005 with a focus on properties located onshore in the U.S. Gulf Coast. In November 2007, we acquired the Gulf Coast assets of Petrohawk Energy Corporation for approximately $825.0 million. The acquisition was funded through borrowings under our prior first lien credit agreement and our prior second lien credit agreement. The acquisition included properties primarily in the onshore Gulf Coast region in Texas, Louisiana and Mississippi. Since this acquisition, we have acquired additional proved producing reserves that we believe have upside potential, implemented an active drilling, workover and recompletion program and expanded our geographic diversity by moving into the Midcontinent area.

In 2010, in order to improve our liquidity and capital structure and to resolve the events resulting in forbearances under our prior first lien credit agreement and prior second lien credit agreement, we effected a recapitalization through, among other things, (i) the discharge of approximately $194.7 million of prior second lien indebtedness through the issuance of Series A preferred stock, (ii) the conversion of approximately $56.2 million of prior second lien indebtedness into indebtedness under our prior second lien PIK credit agreement, and (iii) the conversion of the remaining $30.0 million of prior second lien indebtedness to indebtedness under our existing second lien term loan agreement. In addition, as part of the recapitalization, we received $60.0 million in new capital though the funding of $25.0 million in term loans and $35.0 million delayed draw loan under our existing second lien term loan agreement.

In connection with the 2010 recapitalization, and in response to changes in the business environment, in 2010 we modified our business strategy by moving away from a primary focus on exploration to a more balanced approach of acquisition, exploitation, development and lower risk exploration. Our 2011 capital budget contemplates spending approximately $32.6 million in connection with the drilling of 12 additional wells, including three development wells in the Texas Gulf Coast, three development wells in the Southeast area, one development well in the South Texas area and five wells in the Midcontinent area, and spending approximately $5.0 million in connection with the workover and recompletion of existing wells. Our 2011 capital budget also includes approximately $36.0 million for acquisitions.

As described in more detail below, in May 2011, we completed an offering of an aggregate of $250.0 million of the Notes. We used the proceeds of this offering, together with borrowings under our amended and restated first lien credit agreement, to refinance substantially all of our existing indebtedness.

We intend to fund our future capital expenditures through a variety of means, including cash flow from operations, borrowings under our New Credit Facility, issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties.

Sources of Our Revenues

We derive our revenues from the sale of oil and natural gas that are produced from our properties. Our revenues are a function of the production volumes we sell and the prevailing market prices at the time of sale. Under the terms and conditions of our New Credit Facility, we are required to hedge at least 50%, but no more than 90%, of our monthly forecasted proved developed producing (“PDP”) production by product. We are permitted to use zero-cost collars and out-right swaps with approved counterparties to meet this requirement. The approved counterparties are limited to those financial institutions that participate in the New Credit Facility. We had until September 8, 2011 to meet the 50% and 90% hedging tests. As of June 30, 2011, we had the following hedged positions:

% of PDP Hedged


Year	Crude Oil			Natural Gas			NGLs

2011		104	%		68	%		71	%
2012		108	%		63	%		34	%
2013		78	%		55	%		0	%
2014		94	%		36	%		0	%

In our effort to achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. As of June 30, 2011, we had hedging contracts in place for 930,548 Boe from July 1, 2011, through the end of 2011, 1,386,736 Boe during 2012, 840,000 Boe during 2013 and 580,000 Boe during 2014. Based on the expected production set forth in our July 1, 2011 reserve report, we have hedged approximately 63% of our forecasted 2011, 2012, 2013 and 2014 PDP production as of June 30, 2011. In 2010, we realized commodity hedging gains of approximately $39.4 million, but we expect this to be significantly less in 2011. As of June 30, 2011, we have realized commodity hedging gains of approximately $10.7 million, offset by unrealized hedging losses of approximately $14.3 million. The use of certain types of derivative instruments may prevent us from realizing the benefit of upward price movements for the portion of the production that is hedged. As of the date of this prospectus, we have met the above stated hedging obligations.

Components of Our Cost Structure

Production Costs. Production costs represent theday-to-day costs we incur to bring hydrocarbons out of the ground and to the market, combined with the daily costs we incur to maintain our producing properties. These daily costs include lease operating expenses and taxes other than income.


	•	Lease operating expenses are generally composed of several components, including the cost of: labor and supervision to operate our wells and related equipment; repairs and maintenance; fluid treatment and disposal; related materials, supplies, and fuel; and insurance applicable to our wells and related facilities and equipment. Lease operating expenses also include the cost for workover expense and gathering and transportation. Lease operating expenses are driven in part by the type of commodity produced, the level of workover activity and the geographical location of the properties.

	•	Environmental remediation expenses are costs related to environmental remediation activity associated with our ongoing operations.

	•	In the U.S., there are a variety of state and federal taxes levied on the production of oil and natural gas. These are commonly grouped together and referred to as taxes other than income. The majority of our production tax expense is based on a percent of gross value realized at the wellhead at the time the production is sold or removed from the lease. As a result, our production tax expense increases when oil and natural gas prices rise.

	•	Historically, taxing authorities have from time to time encouraged the oil and natural gas industry to explore for new oil and natural gas reserves, or to develop high cost reserves, through reduced tax rates


		or tax credits. These incentives have been narrow in scope and short-lived. A number of our wells have qualified for reduced production taxes because they are high cost wells.


	•	Taxes other than income include production taxes and ad valorem taxes, which are imposed by local taxing authorities such as school districts, cities, and counties or boroughs. The amount of tax we pay is based on a percent of value of the property assessed or determined by the taxing authority on an annual basis. When oil and natural gas prices rise, the value of our underlying property interests increase, which results in higher ad valorem taxes.

Depreciation, Depletion and Amortization. As a full cost company, we capitalize all direct costs associated with our exploitation and development efforts, including a portion of our interest and certain general and administrative costs that are specific to exploitation and development efforts, and we apportion these costs to each unit of production sold through depletion expense. Generally, if reserve quantities are revised up or down, our depletion rate per unit of production will change inversely. When the depreciable capital cost base increases or decreases, the depletion rate will move in the same direction. Our full-cost depletion expense is driven by many factors, including certain costs spent in the exploration for and development of oil and natural gas reserves, production levels, and estimates of proved reserve quantities and future developmental costs.

Asset Retirement Accretion Expense. Asset retirement accretion expense represents the systematic, monthly accretion of future abandonment costs of tangible assets such as wells, service assets, flowlines and other facilities.

General and Administrative Expense. General and administrative expense includes payroll and benefits for our corporate staff, costs of maintaining our headquarters, managing our production and development operations and legal compliance. We capitalize general and administrative costs directly related to exploitation and development efforts.

Interest. We have relied on a series of debt financings to fund our short-term liquidity and a portion of our long-term financing needs. On December 31, 2010, we had approximately $337.0 million of LIBOR-based floating rate indebtedness outstanding under our prior first lien credit agreement and prior second lien credit agreements. In addition, our Series A preferred stock carries a non-cash cumulative coupon of 12% per annum.

As part of the Refinancing, we issued $250 million of the Notes and entered into the New Credit Facility which provides for a current borrowing base of $170 million. Interest on the New Credit Facility is calculated based on floating rates of LIBOR and Base Rate with a sliding margin that reflects usage under the facility. The higher the usage under this New Credit Facility, the higher the interest margin over the floating rate index. We expect to continue to utilize indebtedness to grow and, as a result, expect to continue to pay interest throughout the term of the Notes.

Income Taxes. We recorded no income tax benefit or expense for the six months ended June 30, 2011. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2010 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred tax assets as of June 30, 2011.

As of June 30, 2011, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2010. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to June 30, 2012.

Oil and Natural Gas Reserves

Our estimated total net proved reserves of oil and natural gas as of June 30, 2011 and 2010 were as follows:


	As of June 30,
	2011			% Chg			2010

Estimated Net Proved Reserves:
Oil and NGLs (MMBbls)		13.5			21	%		11.2
Natural Gas (Bcf)		133			(4	)%		138

Total oil equivalent (MMBoe)		35.7			4	%		34.2
Proved developed reserves as a percentage of net proved reserves		65	%					68	%

Our estimated total net proved reserves increased 4% in the period ended June 30, 2011 as compared to the same period in 2010. This increase in our estimated net proved reserves was primarily the result of additional reserves obtained through an acquisition completed in December 2010.

Results of Operations

The following discussion is of our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto contained elsewhere herein. Comparative results of operations for the periods indicated are discussed below.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Sales Volumes


	Six Months Ended June 30,
	2011		% Change			2010

Oil and NGLs (MBbls)		506		3	%		489
Natural gas (MMcf)		5,890		(17	)%		7,090

Total (MBoe)		1,488		(11	)%		1,671
Average daily production volumes (MBoe/d)(a)		8.2		(11	)%		9.2


(a)		Average daily production volumes calculated based on365-day year

For the six months ended June 30, 2011 and 2010, our net equivalent production volumes decreased by 11% to 1,488 MBoe (8.2 MBoe/d) from 1,671 MBoe (9.2 MBoe/d) in 2010. Our production volumes in 2011 as compared to 2010 decreased primarily due to natural decline in production and the shutting in of producing properties in Louisiana due to flooding from the Mississippi River. Natural gas represented approximately 66% and 71% of our total production in the six months ended June 30, 2011 and 2010, respectively.

Revenues. The following tables shows (1) our revenues from the sale of oil and natural gas and (2) the impact of changes in price and sales volumes on our oil and natural gas revenues during the six months ended June 30, 2011 and 2010. Our commodity hedges are accounted for usingmark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to our consolidated

statement of operations within a single income statement line item. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.


	Six Months Ended June 30,
				%
	2011			Change			2010
	(In thousands)

Oil revenues:
Oil revenues	$	45,033			27	%	$	35,352
Oil derivative settlements		(4,976	)		—			57

Oil revenues including oil derivative settlements		40,057			13	%		35,409
Natural gas revenues:
Natural gas revenues		24,432			(27	)%		33,318
Natural gas derivative settlements		15,709			(10	)%		17,387

Natural gas revenues including derivative settlements		40,141			(21	)%		50,705
Oil and natural gas revenues:
Oil and natural gas revenues		69,465			1	%		68,670
Oil and natural gas derivative settlements		10,733			(38	)%		17,444

Oil and natural gas revenues including derivative settlement gains (losses)		80,198			(7	)%		86,114
Oil and natural gas derivative unrealized gains (losses)		(14,297	)		(413	)%		4,574

Oil and natural gas revenues including derivative settlements and unrealized gains (losses)		65,901			(27	)%		90,688

Total revenues	$	65,901			(27	)%	$	90,688


	Change from Six Months
	Ended June 30, 2010 to Six
	Months Ended June 30, 2011
	(In thousands)

Change in revenues from the sale of oil :
Price variance impact	$	8,466
Sales volume variance impact		1,215

Total change		9,681
Change in revenues from the sale of natural gas:
Price variance impact	$	(3,247	)
Sales volume variance impact		(5,639	)

Total change		(8,886	)
Change in revenues from the sale of oil and natural gas:
Price variance impact	$	5,219
Volume variance impact		(4,424	)
Cash settlement of derivative hedging contracts		(6,711	)
Unrealized losses due to derivative hedging contracts		(18,871	)

Total change	$	(24,787	)

Our oil and natural gas revenues, including derivatives settlements and unrealized gains (losses), for the six months ended June 30, 2011 decreased by approximately $24.8 million, or 27%, when compared to the same period in 2010. The pre-hedged revenue increased by approximately $0.8 million. This increase related to higher prices of oil of approximately $8.5 million, which was partially offset by lower natural gas prices of

approximately $3.2 million and lower production, which decreased revenue by approximately $4.4 million. The decrease in hedged gains was due primarily to losses on realized commodity derivatives of approximately $6.7 million and unrealized losses due to commodity derivatives of approximately $18.9 million.

Production costs. Production volumes in the six months ended June 30, 2011 decreased 11% as compared to the same period in 2010 from 1.7 MMBoe to 1.5 MMBoe. Per unit production cost in 2011 increased by $3.63/Boe, or 27%, and total production costs in 2011 increased by $2.9 million, or 13%, as compared to 2010. Our per unit and total production costs for the six months ended June 30, 2011 and 2010 are as set forth below.


	Unit-of-Production
	(Per Boe Based on Sales Volumes)
	Six Months Ended June 30,
	2011		% Change			2010

Production costs:
Gathering & transportation	$	0.47		18	%	$	0.40
Operating & maintenance		11.62		33	%		8.75
Workover expenses		0.88		(17	)%		1.06

Lease operating expenses		12.97		27	%		10.21
Remediation expenses		1.33		100	%		—
Taxes other than income		2.88		(14	)%		3.34

Production costs	$	17.18		27	%	$	13.55


	Production Costs
	Six Months Ended June 30,
	2011		% Change			2010
	(In thousands)

Production costs:
Gathering & transportation	$	697		5	%	$	661
Operating & maintenance		17,289		18	%		14,626
Workover expenses		1,302		(27	)%		1,774

Lease operating expenses		19,288		13	%		17,061
Remediation expenses		1,984		100	%		—
Taxes other than income		4,285		(23	)%		5,581

Production costs	$	25,557		13	%	$	22,642

Operating and maintenance expenses for the six months ended June 30, 2011 were approximately $17.3 million, compared to approximately $14.6 million in the same period of 2010, an increase of approximately $2.7 million, or 18%. This increase in operating and maintenance expenses was due to overall increases in direct labor and benefit costs, insurance costs and repairs and maintenance and our 2010 acquisitions.

Workover expenses for the six months ended June 30, 2011 were approximately $1.3 million, compared to approximately $1.8 million for the same period in 2010, a decrease of approximately $0.5 million, or 27%. This decrease was due primarily to a decrease in the number and cost of our workovers in 2011 as compared to 2010.

Environmental remediation expenses for the six months ended June 30, 2011 were approximately $2.0 million and were incurred in 2011 as the result of our participation in a settlement involving environmental remediation in a field in which we have an ownership interest. There were no remediation costs incurred in the 2010 period.

Taxes other than income for the six months ended June 30, 2011 were $4.3 million, compared to $5.6 million in the same period of 2010, a decrease of $1.3 million or 23%. This decrease in taxes was due to lower actual ad valorem taxes incurred in the current year.

General and administrative expenses. We capitalize a portion of our general and administrative costs. Capitalized costs include the cost of technical employees who work directly on our exploration activities, a portion of our associated technical organization costs such as supervision, telephone and postage, and a portion of our interest on unproved capital projects. Our total general and administrative costs (gross, capitalized and net) and our per unit general and administrative costs for the six months ended June 30, 2011 and 2010 were as follows:


	Six Months Ended June 30,
	2011		% Change			2010
	(In thousands, except per unit measurements which are based on sales volumes)

General and administrative expenses — gross	$	9,513		(10	)%	$	10,532
Capitalized general and administrative costs		2,391		30	%		1,843

General and administrative costs — net	$	7,122		(18	)%	$	8,689

General and administrative expenses — gross $ per Boe	$	6.39		1	%	$	6.30

Our gross general and administrative expenses for the six months ended June 30, 2011 were approximately $9.5 million compared to approximately $10.5 million in the same period of 2010, a decrease of approximately $1.0 million, or 10%, primarily as a result of there being no stock based compensation expense in 2011, as compared to $0.9 million in 2010. After capitalization, our general and administrative costs decreased by approximately $1.6 million, or 18%, to approximately $7.1 million. Per unit general and administrative expense increased slightly due to a decrease in production volumes that was offset by the decrease in compensation expense and increase in capitalized costs.

Depletion of oil and natural gas properties.


	Six Months Ended June 30,
	2011		% Change			2010
	(In thousands, except per unit measurements which are based on sales volumes)

Depletion of oil and natural gas properties	$	24,779		(2	)%	$	25,261
Depletion of oil and natural gas properties (per Boe)	$	16.65		10	%	$	15.12

Our depletion expense for the six months ended June 30, 2011 was approximately $24.8 million compared to approximately $25.3 million in the same period of 2010, a decrease of approximately $0.5 million, or 2%. This decrease in depletion expense was largely the result of decreased production volumes, which resulted in lower depletion expense by approximately $2.8 million. This was partially offset by an increase in our depletion rate resulting in an increase in depletion expense of approximately $2.3 million.

Net interest expense. Our interest expense for the six months ended June 30, 2011 and June 30, 2010 was approximately $24.1 million for each period. Total interest expense for the six months ended June 30, 2011 benefited from our Refinancing that converted the Series A preferred from a debt instrument to mezzanine equity, offset by the increase in interest expense due to the assumption of a higher coupon on our $250 million Notes issued in May 2011.

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

Sales volumes


	Year Ended December 31,
	2010		% Change			2009

Oil (MBbls)		1,011		(9	)%		1,113
Natural gas (MMcf)		13,657		(26	)%		18,512
Total (MBoe)		3,287		(22	)%		4,198
Average daily production volumes (MBoe/d)(a)		9.0		(22	)%		11.5


(a)		Average daily production volumes calculated based on365-day year

Our net equivalent production volumes for 2010 decreased by 22% to 3,287 MBoe (9.0 MBoe/d) from 4,198 MBoe (11.5 MBoe/d) in 2009. Our production volumes for 2010 decreased primarily due to reduced production-enhancing capital expenditure activity in 2009 and in the first half of 2010, which was the result of a failure to offset the natural production decline of our properties. Natural gas represented 69% of our total production in 2010.

Revenues

The following tables shows (1) our revenues from the sale of oil and natural gas and (2) the impact of changes in price and sales volumes on our oil and natural gas revenues during the years ended 2010 and 2009. Our commodity hedges are accounted for usingmark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to our consolidated statement of operations within a single income statement line item. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.


	Year Ended December 31,
	2010			% Change			2009
	(In thousands, except per unit measurements)

Oil revenues:
Oil revenues	$	74,208			27	%	$	58,549
Oil derivative settlement gains (losses)		53			(98	)%		3,466

Oil revenues including oil derivative settlements	$	74,261			20	%	$	62,015
Natural gas revenues:
Natural gas revenues	$	59,999			(15	)%	$	70,233
Natural gas derivative settlement gains (losses)		39,302			(3	)%		40,661

Natural gas revenues including derivative settlements	$	99,301			(10	)%	$	110,894
Oil and natural gas revenues:
Oil and natural gas revenues	$	134,207			4	%	$	128,782
Oil and natural gas derivative settlement gains (losses)		39,355			(11	)%		44,127

Oil and natural gas revenues including derivative settlement gains (losses)	$	173,562			0.4	%	$	172,909
Oil and natural gas derivative unrealized gains (losses)		(16,412	)		11	%		(18,521	)

Oil and natural gas revenues including derivative settlements and unrealized gains (losses)	$	157,150			2	%	$	154,388

Total revenues	$	157,150			2	%	$	154,388


	2009
	to 2010

Change in revenues from the sale of oil
Price variance impact	$	20,451
Sales volume variance impact		(4,793	)

Total change	$	15,658

Change in revenues from the sale of natural gas
Price variance impact	$	8,185
Sales volume variance impact		(18,419	)

Total change	$	(10,234	)

Change in revenues from the sale of oil and natural gas
Price variance impact	$	28,636
Volume variance impact		(23,212	)
Cash settlement of derivative hedging contracts		(4,772	)
Unrealized gains (losses) due to derivative hedging contracts		2,109

Total change	$	2,761

Our oil and natural gas revenues, including derivatives settlements and unrealized gains for 2010 increased $2.7 million, or 2%, as compared to 2009. This increase in revenues was primarily due to a 33% increase in pre-hedge per Boe sales prices, which resulted in a $28.6 million increase in revenues, and a $2.1 million increase in unrealized gains on derivative hedge contracts from December 31, 2009 to December 31, 2010. This increase in revenues was offset by a 22% decrease in oil and natural gas volumes due to a natural decline in production, resulting in a $23.2 million decrease in revenues, and a $4.8 million decrease in derivative hedging gains on contracts settled.

Production costs. Although production volumes in 2010 decreased 22% as compared to 2009 from 4.2 MMBoe to 3.3 MMBoe in 2010, per unit production cost in 2010 increased by $3.78/Boe, or 36%, and total production costs in 2010 increased by $3.0 million, or 7%, as compared to 2009. Our per unit and total production costs for the years ended December 31, 2010 and 2009 are as set forth below.


	Unit-of-Production
	(Per Boe Based on Sales Volumes)
	Year Ended December 31,
	2010		% Change			2009

Production costs:
Gathering & transportation	$	0.39		(15	)%	$	0.46
Operating & maintenance		9.39		38	%		6.80
Workover expenses		1.04		9	%		0.95

Lease operating expenses	$	10.82		32	%	$	8.21
Taxes other than income		3.32		54	%		2.15

Production costs	$	14.14		36	%	$	10.36


	Year Ended December 31,
	2010		% Change			2009
	(In thousands)

Production costs:
Gathering & transportation	$	1,282		(33	)%	$	1,925
Operating & maintenance	$	30,865		8	%	$	28,546
Workover expenses		3,418		(14	)%		3,996

Lease operating expenses	$	35,565		3	%	$	34,467
Taxes other than income		10,904		21	%		9,017

Production costs	$	46,469		7	%	$	43,484

Our gathering and transportation costs in 2010 were approximately $1.3 million, compared to $1.9 million in 2009, a decrease of approximately $0.6 million, or 33%. This decrease was primarily due to a reduction in our natural gas production.

Operating and maintenance expenses in 2010 were $30.9 million, compared to $28.5 million in 2009, an increase of $2.4 million, or 8%. This increase in operating and maintenance expenses was due primarily to an increase in well service costs and treating and processing costs.

Workover expenses in 2010 were $3.4 million, compared to $4.0 million in 2009, a decrease of $0.6 million, or 14%. This decrease was due primarily to a decrease in the number and cost of our workovers in 2010 as compared to 2009.

Taxes other than income in 2010 were $10.9 million, compared to $9.0 million in 2009, an increase of $1.9 million or 21%. This increase in taxes other than income was due to utilized tight sands credits in 2009 that were unavailable to us in 2010 because the inventory of properties which became eligible for the credits declined.

We capitalize a portion of our general and administrative costs. Capitalized costs include the cost of technical employees who work directly on our prospect generation and exploration activities, a portion of our associated technical organization costs such as supervision, telephone and postage, and a portion of our interest on unproved capital projects. Our total general and administrative costs (gross, capitalized and net) and our per unit general and administrative costs for the years ended December 31, 2010 and 2009 are as follows:


	Year Ended December 31,
	2010		% Change			2009
	(In thousands, except per unit measurements which are based on sales volumes)

General and administrative expenses — gross	$	21,309		(13	)%	$	24,485
Capitalized general and administrative costs(a)		3,840		(32	)%		5,636

General and administrative costs — net	$	17,469		(7	)%	$	18,849
General and administrative expenses — gross $ per Boe	$	6.48		11	%	$	5.83


(a)		We capitalize a portion of our general and administrative costs. Capitalized costs include the cost of technical employees who work directly on our prospect generation and exploration activities and a portion of our associated technical organization costs such as supervision, telephone and postage.

Our gross general and administrative expenses in 2010 were $21.3 million compared to $24.5 million in 2009, a decrease of $3.2 million, or 13%. After capitalization, our general and administrative costs decreased by $1.4 million, or 7%, to $17.5 million. This decrease in our gross general and administrative expenses and our general and administrative costs after capitalization was largely attributable to certain fees and expenses we paid in 2009 in connection with the Recapitalization.

Depletion of oil and natural gas properties.


	Year Ended December 31,
	2010		% Change			2009
	(In thousands, except per unit measurements which are based on sales volumes)

Depletion of oil and natural gas properties	$	51,779		(23	)%	$	66,888
Depletion of oil and natural gas properties (per Boe)	$	15.75		(1	)%	$	15.93

Our depletion expense for 2010 was $51.8 million compared to $66.9 million in 2009, a decrease of $15.1 million, or 23%. The decrease in depletion expense was primarily attributable to a decrease in production volumes in 2010 resulting in an approximately $14.5 million decrease in depletion expense and a decrease in our depletion rate of approximately $0.6 million. The lower depletion rate was due to our 2009 ceiling limitation impairments.

Net interest expense. In 2010, our net interest expense increased by $7.4 million, or 18%, from $40.6 million in 2009 to $48.0 million in 2010. This increase in interest expense was the result of higher interest rates payable on loans under our existing second lien indebtedness as compared to the rates payable under our prior second lien credit agreement and the additional interest expense attributable to the dividends on our Series A preferred stock.

Income taxes. For the years ended December 31, 2010 and 2009, current tax expense (benefit) was zero and deferred tax expense (benefit) was approximately $57.4 million and ($57.4) million, respectively. In 2010, we provided a full valuation allowance with respect to our deferred tax assets given our history of operating losses, the going concern qualification included in our financial statements, and the expectation that future profitability will be impacted significantly by volatility in commodity prices for oil and natural gas. Our future profitability is heavily correlated to the volume of our proved reserves, and the price at which these reserves will be sold. The expected volatility in commodity prices creates significant uncertainty with respect to whether future profitability will be sufficient to realize deferred tax assets.

Effective August 1, 2009, we converted from a single member limited liability company to a corporation taxed undersub-chapter C of the Internal Revenue Code. As a result of the conversion, deferred tax assets and liabilities were recorded to reflect the future tax impacts associated with differences in tax basis as compared to net book value as of the date of conversion. Approximately $54.8 million of net deferred tax assets existed as of the conversion date, before consideration of any valuation allowance.

As of December 31, 2010 and 2009, we recorded valuation allowances against our net deferred tax assets of approximately $74.5 million and $16.2 million, respectively. The tax asset related to the NOL’s of $14.8 million will begin to expire in 2030. See “Note 12. Income Taxes” in our audited consolidated financial statements contained herein.

The federal statutory rate of 35% is different from our effective tax rate primarily because the dividends on our Series A preferred stock (recorded as interest expense) are not deductible for income tax purposes and as a result of the full valuation allowance against deferred income tax assets.

Year ended December 31, 2009 Compared to Year Ended December 31, 2008

Sales volumes


	Year Ended December 31,
	2009		% Change			2008

Oil (MBbls)		1,113		(28	)%		1,545
Natural gas (MMcf)		18,512		(26	)%		24,906
Total (MBoe)		4,198		(26	)%		5,696
Average daily production volumes (MBoe/d)(a)		11.5		(26	)%		15.6


(a)		Average daily production volumes calculated based on365-day year

For 2009, our net equivalent daily production volumes decreased by 26% to 4,198 MBoe (11.5 MBoe/d) from 5,696 MBoe (15.6 MBoe/d) in 2008. Our production volumes in 2009 as compared to 2008 decreased primarily due to our reduction in drilling, natural production decline and lower workover activity in response to low natural gas prices and tightening of the credit markets. Natural gas represented approximately 73% of our total production in 2009 and 2008.

Revenues

The following tables show (1) our revenues from the sale of oil and natural gas and (2) the impact of changes in price and sales volumes on our oil and natural gas revenues during the years ended 2009 and 2008. Our commodity hedges are accounted for usingmark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to our consolidated statement of operations within a single income statement line item. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.


	Year Ended December 31,
	2009			% Change			2008
	(In thousands, except per unit measurements)

Oil revenues:
Oil revenues	$	58,549			(59	)%	$	142,796
Oil derivative settlement gains (losses)		3,466			133	%		(10,400	)

Oil revenues including oil derivative settlements	$	62,015			(53	)%	$	132,396
Natural gas revenues:
Natural gas revenues	$	70,233			(68	)%	$	217,498
Natural gas derivative settlement gains (losses)		40,661			664	%		(7,205	)

Natural gas revenues including derivative settlements	$	110,894			(47	)%	$	210,293
Oil and natural gas revenues:
Oil and natural gas revenues	$	128,782			(64	)%	$	360,294
Oil and natural gas derivative settlement gains (losses)		44,127			351	%		(17,605	)

Oil and natural gas revenues including derivative settlement gains (losses)	$	172,909			(50	)%	$	342,689
Oil and natural gas derivative unrealized gains (losses)		(18,521	)		(127	)%		67,864

Oil and natural gas revenues including derivative settlements and unrealized gains (losses)	$	154,388			(62	)%	$	410,553

Total revenues	$	154,388			(62	)%	$	410,553


	2008
	to 2009

Change in revenues from the sale of oil
Price variance impact	$	(42,486	)
Sales volume variance impact		(41,761	)

Total change	$	(84,247	)

Change in revenues from the sale of natural gas
Price variance impact	$	(91,430	)
Sales volume variance impact		(55,835	)

Total change	$	(147,265	)

Change in revenues from the sale of oil and natural gas
Price variance impact	$	(133,916	)
Volume variance impact		(97,596	)
Cash settlement of derivative hedging contracts		61,732
Unrealized gains (losses) due to derivative hedging contracts		(86,385	)

Total change	$	(256,165	)

Our oil and natural gas revenues including derivatives settlements and unrealized gains (losses) for 2009 decreased $256.2 million, or 62%, when compared to 2008. This decrease in revenues was primarily due to a $134.0 million, or 52%, decrease in our pre-hedge per Boe sales prices to $30.68 in 2009 from $63.25 in 2008 and a $97.6 million decrease in revenues as a result of a 26% decrease in our natural gas and crude oil production volumes resulting from the natural production decline of our properties. We also recorded an unrealized loss on hedge contracts of $18.5 million in 2009 as compared to an unrealized gain of $67.9 million on hedge contracts in 2008. This decrease in revenues was partially offset by $61.7 million in realized hedging gains on derivative hedging contracts settled during 2009.

Production costs. Per unit production cost for 2009 as compared to 2008 decreased $2.11/Boe, or 17%, and total production costs for 2009, as compared to 2008, decreased by $27.5 million, or 39%. Our per unit and total production costs for the years ended December 31, 2009 and 2008 are as set forth below.


	Unit-of-Production
	(Per Boe Based on Sales Volumes)
	Year Ended December 31,
	2009		% Change			2008

Production costs:
Gathering & transportation	$	0.46		(39	)%	$	0.76
Operating & maintenance		6.80		7	%		6.36
Workover expenses		0.95		(8	)%		1.03

Lease operating expenses	$	8.21		1	%	$	8.15
Taxes other than income		2.15		(50	)%		4.32

Production costs	$	10.36		(17	)%	$	12.47


	Year Ended December 31,
	2009		% Change			2008
	(In thousands)

Production costs:
Gathering & transportation	$	1,925		(56	)%	$	4,348
Operating & maintenance		28,546		(21	)%		36,234
Workover expenses		3,996		(32	)%		5,844

Lease operating expenses	$	34,467		(26	)%	$	46,426
Taxes other than income		9,017		(63	)%		24,585

Production costs	$	43,484		(39	)%	$	71,011

For the year ended December 31, 2009, our gathering and transportation costs were approximately $1.9 million, a decrease of $2.4 million, or 56%, from the year ended December 31, 2008. This decrease was primarily related to improved terms for the gas marketing arrangements for our Lions field. In 2009, our natural gas from the Lions field was delivered directly into the TETCO pipeline with no third party transportation costs. Prior to that time, however, the natural gas from this field was transported on the Enterprise gathering system and delivered into the Tennessee Gas Pipeline.

Operating and maintenance expenses in 2009 were $28.5 million, compared to $36.2 million in 2008, a decrease of $7.7 million, or 21%. This decrease in operating and maintenance expenses was due primarily to decreases in well service costs, treating and processing costs and operational enhancements generally, as well as from the sale of the Winchester field properties in Mississippi.

Workover expenses in 2009 were $4.0 million, compared to $5.8 million in 2008, a decrease of $1.8 million, or 32%. This decrease in workover expenses was due primarily to a decrease in the number and cost of our workovers in 2009 as compared to 2008.

Taxes other than income in 2009 were $9.0 million, compared to $24.6 million in 2008, a decrease of $15.6 million, or 63%. This decrease in taxes other than income was due to the utilization of tight sands tax credits in 2009 which were applied for in 2008, but not approved by the Texas Railroad Commission and Texas State Comptroller until 2009.

Our total general and administrative costs (gross, capitalized and net) and our per unit general and administrative costs for the years ended December 31, 2009 and 2008 are as follows:


	Year Ended December 31,
	2009		% Change			2008
	(In thousands, except per unit measurements which are based on sales volumes)

General and administrative expenses — gross	$	24,485		2	%	$	23,989
Capitalized general and administrative costs(a)		5,636		26	%		4,490

General and administrative costs — net	$	18,849		(3	)%	$	19,499
General and administrative expenses — gross $ per Boe	$	5.83		38	%	$	4.21


(a)		We capitalize a portion of our general and administrative costs. Capitalized costs include the cost of technical employees who work directly on our prospect generation, exploration activities and a portion of our associated technical organization costs such as supervision, telephone and postage.

Our gross general and administrative expenses in 2009 decreased by $0.5 million, or 2%, as compared to 2008. After capitalization, general and administrative costs in 2009 decreased by $0.7 million, or 3%, as compared to 2008. This decrease in our gross general and administrative expenses and our general and administrative costs after capitalization was due to a decrease of $0.7 million from 2008 to 2009 resulting from the recovery of bad debts in 2009 and was partially offset by higher professional fees paid in connection with the Recapitalization.

Depletion of oil and natural gas properties.


	Year Ended December 31,
	2009		% Change			2008
	(In thousands, except per unit measurements which are based on sales volumes)

Depletion of oil and natural gas properties	$	66,888		(53	)%	$	142,190
Depletion of oil and natural gas properties (per Boe)	$	15.93		(36	)%	$	24.96

Our depletion expense in 2009 was $66.9 million compared to depletion expense in 2008 of $142.2 million, a decrease of $75.3 million, or 53%. This decrease in depletion expense was largely the result of decreased production volumes in 2009, which resulted in lower depletion expense by approximately $37.4 million, as well as a decrease in our depletion rate caused by our 2008 ceiling limitation impairments that resulted in a further decrease in depletion expense in 2009 of $37.9 million.

Impairment of oil and natural gas properties. For the year ended December 31, 2009, based on the average oil and natural gas prices in effect on the first day of each month during 2009 ($3.87 per MMBtu for Henry Hub gas and $61.18 per Bbl for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and natural gas properties exceeded the ceiling limit and we recorded a $39.6 million impairment to our oil and natural gas properties. For the year ended December 31, 2008, based on oil and natural gas prices in effect on December 31, 2008 ($5.71 per MMBtu for Henry Hub gas and $44.60 per Bbl for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and natural gas properties exceeded the ceiling limit and we recorded a $429.9 million impairment to our oil and natural gas properties.

Net interest expense. Our net interest expense for 2009 was $40.6 million, compared to $35.4 million in 2008, an increase of $5.2 million, or 15%. The increase in net interest expense in 2009 was attributable to $7.0 million in fees incurred in connection with the restructuring of prior first lien and second lien indebtedness, offset by a 7% decrease in weighted average debt outstanding.

Income taxes. Our net loss before taxes was $66.1 million for the twelve months ended December 31, 2009, as compared to a net loss before taxes of $318.9 million for the twelve months ended December 31, 2008. We recorded income tax benefit of $57.4 million for 2009. In 2009, we generated a regular tax NOL of $17.4 million, which is expected to be carried forward and applied against taxable income in future periods. Our effective tax rates differ from the statutory rate of 35% primarily because of state and local taxes, the tax effects of permanent book-tax differences, the deferred tax valuation allowance, and the recognition of the book and tax differences at the time of conversion. Taxes were not recorded in 2008 as we were a flow through entity for income purposes and income tax was responsibility of the unit holders.

Liquidity and Capital Resources

Historically, we have financed our acquisition, exploitation and development activities, and repayment of our contractual obligations, through a variety of means, including cash flow from operations, borrowings under our credit agreements, issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties. Our primary needs for cash are to fund our capital expenditure program and our working capital obligations and for the repayment of contractual obligations. In the future, we will also require cash to fund our capital expenditures for the exploitation and development of properties necessary to offset the inherent declines in production and proved reserves that are typical in an extractive industry like ours. We will also spend capital to hold acreage that would otherwise expire if not drilled. Future success in growing reserves and production will be highly dependent on our access to cost effective capital resources and our success in economically finding and producing additional oil and natural gas reserves.

At December 31, 2010, current liabilities exceeded current assets by $238.5 million, due primarily to the classification of our prior first lien debt and certain tranches of our prior second lien debt as current debt. All of these loans would have matured in November 2011. Our financial statements have been prepared assuming

we will continue as a going concern. In May 2011, we entered into the New Credit Facility and issued the Notes, which mature in 2014 and 2016, respectively.

Six Months Ended June 30, 2011 and 2010

Sources and Uses of Cash

The table below summarizes our sources and uses of cash during the periods indicated.


	Six Months Ended June 30,
	2011			% Change			2010
				(In thousands)

Net loss	$	(19,410	)		(61	)%	$	(50,323	)
Non-cash items		51,951			(44	)%		92,138
Changes in working capital and other items		(5,845	)		375	%		(1,231	)

Cash flows provided by operating activities		26,696			(34	)%		40,584
Cash flows used in investing activities		(33,080	)		1	%		(32,621	)
Cash flows provided by (used in) financing activities		(7,409	)		(137	)%		20,245

Net increase in cash and cash equivalents	$	(13,793	)		(149	)%	$	28,208

Analysis of cash flows provided by operating activities

Cash flows provided by operating activities for the six months ended June 30, 2011 were approximately $26.7 million, as compared to approximately $40.6 million for the same period in 2010, an approximately $13.9 million, or 34%, decrease. The decrease in cash flows provided by operating activities from 2010 to 2011 was primarily due to higher cash operating costs and lower revenues, which decreased operating cash flow activities by approximately $9.3 million and a change in working capital of approximately $4.6 million related primarily to the pay down of payables that was partly offset by the collection of receivables.

Analysis of cash flows used in investing activities

Net cash used in investing activities for the six months ended June 30, 2011 was $33.1 million, compared to $32.6 million in the same period in 2010, a $0.5 million, or 1%, increase. In 2011, we have focused on drilling and leasing to increase reserves. In 2010, we were focused on acquisitions to increase reserves.

Analysis of cash flows provided by and used in financing activities

Net cash used in financing activities for the six months ended June 30, 2011 was approximately $7.4 million as compared to cash provided by financing activities of approximately $20.2 million for the same period in 2010, a change of approximately $27.6 million, or 137%. This increase was the result of additional repayment of borrowings of approximately $321.4 million in 2011 as compared to 2010 and financing costs related to the debt offerings of approximately $9.2 million. This increase was partially offset by additional proceeds from new borrowings of $302.9 million in 2011 as compared to 2010.

Capital expenditures

The timing of most of our capital expenditures is discretionary because we operate the majority of our wells and we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. Our capital expenditure program also includes general and administrative costs allowed to be capitalized under full cost accounting, costs related to plugging and abandoning unproductive or uneconomic wells and the cost of acquiring and maintaining our lease acreage position and our seismic resources, drilling and completing new oil and natural gas wells, installing new production infrastructure and maintaining, repairing and enhancing existing oil and natural gas wells.

The capital that funds our drilling activities is allocated to individual prospects based on the value potential of a prospect, as measured by a risked net present value analysis. We re-evaluate our annual budget periodically throughout the year. The primary factors that affect our budget include forecasted commodity prices, drilling and completion costs, and a prospect’s risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of all our planned expenditures include the level of production from our existing oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. The outcome of our periodic analysis results in a reprioritization of our drilling schedule to ensure that we are optimizing our capital expenditure plan.

During the six months ended June 30, 2011, we spent approximately $29.1 million in capital expenditures to support our business plan. Of this amount, we spent approximately $11.6 million to drill five gross (3.05 net) wells and complete three gross (1.05 net) wells. We also recompleted approximately 34 gross (24.92 net) wells during 2011 at a capital cost of approximately $5.1 million, approximately $1.1 million was spent to plug and abandon wells, and spent approximately $8.0 million to continue lease acquisitions primarily in Oklahoma to support the future development of our Atoka Shale properties. The remaining approximately $3.3 million related primarily to acquisitions.

Capital resources

Cash. As of June 30, 2011 and 2010, we had $3.9 million and $38.7 million of cash and cash equivalents, respectively.

First Lien Credit. As part of the Refinancing, we entered into a $300 million Amended and Restated First Lien Credit Agreement that matures in November 2014. The initial borrowing base for the New Credit Facility was established at $170 million with semi-annual re-determinations to begin in November 2011. Amounts outstanding under the New Credit Facility bear interest at specified margins over the LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. Borrowings under the New Credit Facility are secured by all of our oil and gas properties. The lenders’ commitments to extend credit will expire, and amounts drawn under the New Credit Facility will mature, in November 2014.

The New Credit Facility contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused availability of the borrowing base under the New Credit Facility to current liabilities) of not less than 1.0 to 1.0 (which was 2.96 as of June 30, 2011), minimum interest coverage ratio, as defined, of not less than 2.25 to 1.0 (which was 4.12 as of June 30, 2011) and maximum leverage ratio, as defined, of debt balances as compared to EBITDA of not greater than 4.5 to 1.0 (which was 3.26 as of June 30, 2011). The interest coverage ratio, as defined, increases from 2.25 to 1.0 during 2011 and 2.5 to 1.0 thereafter. The leverage ratio reduces from 4.5 to 1.0 during 2011 to 4.25 to 1 during 2012 and 4.0 to 1 thereafter. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt and liens, changes of control and asset sales. At June 30, 2011, we are in compliance with the financial covenants governing the New Credit Facility.

Second Lien. As part of the 2010 recapitalization, the Borrowers entered into our prior second lien term loan agreement between the Borrowers, each of the lenders from time to time party thereto and Guggenheim Corporate Funding, LLC, as administrative agent. The prior second lien term loan agreement provided for three types of loans which were the Term Loans (new loans advanced in full on the closing date), the Delayed Draw Loans (term loans available to be drawn in the future based on certain terms and conditions), and the Converted Loans (existing loans converted from our prior second lien term loan agreement). In addition, as part of the 2010 recapitalization, the Borrowers and the certain of the prior second lien debt holders entered into our prior second lienpayable-in-kind (“PIK”) credit facility, in which the prior second lien debt holders which did not convert their loans under the prior second lien term loan agreement agreed to continue their existing loans consisting of principal and accrued interest totaling approximately $62.6 million.

Concurrently with the closing of the Refinancing, we repaid in full the approximately $152.6 million in aggregate principal amount outstanding under the prior second lien term loan agreement and the prior second lien PIK credit facility, together, in each case, with the accrued interest thereon to the date of such repayment.

Series A Preferred Stock. As part of the 2010 recapitalization, we entered into agreements to exchange a portion of prior second lien indebtedness for $205.5 million of Series A Preferred Stock, consisting of 2,700,000 shares issued at $76.12 per share redeemable in 2016 at the option of the holder subsequent to the maturity of certain qualified debt, including the New Credit Facility and the Notes. The preferred shareholders receive a 12% dividend each year paid in cash, or in-kind, which is determined solely at our option. There were no cash dividends paid during 2010 and we did not pay dividends in 2011. These preferred shares were classified as a liability in the financial statements as they were mandatorily redeemable for cash.

Upon completion of the Refinancing, including the amendment of the terms of our Series A Preferred Stock as described in Note 9 to the unaudited condensed consolidated financial statements included herein, we reclassified the Series A Preferred Stock as mezzanine equity for financial reporting purposes because there is no longer a mandatory redemption provision and the Series A Preferred Stock is redeemable at the option of the holder. There were no dividends declared or paid during the six months ended June 30, 2011.

Capitalization of Debt Costs. We capitalize certain direct costs associated with the issuance of long-term debt, which is then amortized over the lives of the respective debt using the straight-line method, which approximates the interest method.

Senior Secured Second Lien Notes. As part of the Refinancing, we issued Senior Secured Second Lien Notes due May 11, 2016 with a face value of $250 million, at a discount of $7.0 million. The Notes carry a face interest rate of 10.5%; interest is payable semi-annually each May 15 and November 15. The Notes are secured by a second priority lien on all of the collateral securing the New Credit Facility, and effectively rank junior to any existing and future first lien secured indebtedness, which includes the New Credit Facility. The balance is presented net of unamortized discount of $6.8 million at June 30, 2011.

The Notes contain an optional redemption provision allowing us to retire up to 35% of the principal outstanding with the proceeds of an equity offering, at 110.5% of par. Additional optional redemption provisions allow for the retirement of all or a portion of the outstanding senior secured second lien notes at 110.5%, 102.625% and 100.0% beginning on each of May 15, 2014, May 15, 2015 and November 15, 2015, respectively. If a change of control occurs, each noteholder may require us to repurchase all or a portion of its notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus any accrued and unpaid interest and special interest, if any, to, but not including, the date of repurchase. The indenture governing the Notes contains covenants that, among other things, limit our ability to incur or guarantee additional indebtedness or issue certain preferred stock; declare or pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; transfer or sell assets; make investments; create certain liens; consolidate, merge or transfer all or substantially all of its assets; engage in transactions with affiliates; and create unrestricted subsidiaries.

In connection with the offering of the Notes, we entered into a registration rights agreement with the initial purchasers. Under the terms of the registration rights agreement, we will file a registration statement within 180 days of the closing date to become effective no later than 300 days after the closing date, to allow for the registration of exchange notes with terms substantially identical to the Notes. The registration statement of which this prospectus is a part satisfies this obligation. The exchange notes are to be exchanged for the Notes within 30 days after the registration statement becomes effective. If we fail to file any of the registration statements required by the registration rights agreement on or before the date specified for such filing, then we will pay special interest to each holder of entitled securities until all registration defaults have been cured. With respect to the first90-day period immediately following the occurrence of the first registration default, special interest will be paid at the rate of 0.25% per annum. Such rate will increase by an additional 0.25% per annum with respect to each subsequent90-day period until all registration defaults have been cured, up to a maximum rate of special interest for all registration defaults of 1.0% per annum.

Twelve Months ended December 31, 2010, 2009 and 2008

Sources and Uses of Cash

The table below summarizes our sources and uses of cash during the periods indicated.


	Year Ended December 31,
	2010			% Change			2009			% Change			2008
	(In thousands)

Net loss	$	(70,588	)		717	%	$	(8,636	)		(97	)%	$	(318,912	)
Non-cash items		157,652			102	%		78,066			(86	)%		538,834
Changes in working capital and other items		8,253			(65	)%		23,801			329	%		5,544

Cash flows provided by operating activities	$	95,317			2	%	$	93,231			(59	)%	$	225,466
Cash flows used in investing activities	$	(101,071	)		247	%	$	(29,113	)		(85	)%	$	(197,473	)
Cash flows provided by (used in) financing activities		12,957			124	%		(53,587	)		91	%		(27,993	)

Net increase in cash and cash equivalents	$	7,203			(32	)%	$	10,531			100	%		—

Working capital

At December 31, 2010, we had a working capital deficiency of $238.5 million. This deficiency was primarily the result of reclassifying from long-term debt to current debt the approximately $244.6 million outstanding under our existing first lien credit agreement and our existing second lien term loan agreement that matures in November 2011. We notified the lenders that we were in violation of the minimum working capital level covenant in our existing first lien credit agreement as a result of this deficiency; however, we obtained a waiver from the lenders for such violations until June 30, 2011, at which time we were in compliance. Our working capital deficit at December 31, 2009 and 2008 was $11.0 million and $23.5 million, respectively, as a result of accrued interest of $20.1 million and derivative liabilities of $10.3 million in 2009 and accounts payable of $82.1 million in 2008.

Analysis of cash flows provided by operating activities

Cash flows provided by operating activities in 2010 were $95.3 million, as compared to $93.2 million in 2009, a $2.1 million, or 2%, increase.

Cash flows provided by operating activities in 2008 were $225.5 million. The $132.2 million, or 59%, decrease in cash flows provided by operating activities from 2008 to 2009 was primarily due to a 64% decrease in oil and natural gas sales during 2009, which resulted in a $231.5 million decrease in cash flow. This decrease was partially offset by a $61.7 million increase in realized hedge gains in 2009, lower operating costs, which increased operating cash flow activities by approximately $27.5 million, and a change in working capital, which increased operating cash flow in 2009 by $18.3 million.

Analysis of cash flows used in investing activities

Net cash used in investing activities in 2010 was $101.1 million, compared to $29.1 million in 2009, a $72.0 million, or 247%, increase. This increase was primarily due to our acquisition in 2010 of properties from TexCal Energy South Texas, L.P. for $22.4 million and of properties from RWG Energy, Inc. for $44.5 million.

Our net cash used in investing activities in 2009 was $29.1 million as compared to $197.5 million in 2008, a decrease of $168.4 million, or 85%. This decrease was primarily a result of our curtailment of drilling and leasing activity due to the decline in the economy as well as our lack of liquidity in 2009. Net cash used in investing activities in 2008 included drilling and leasing costs of approximately $201.4 million. Drilling and

leasing costs in 2009 were approximately $26.6 million, which were offset by the sale of the Winchester field properties in Mississippi in 2009 for approximately $32.0 million.

Analysis of cash flows provided by and used in financing activities

Net cash provided by financing activities in 2010 was $13.0 million as compared to $53.6 million used in financing activities in 2009, an increase of $66.6 million, or 124%. This increase was primarily the result of $35.0 million of borrowings under our existing second lien term loan agreement to fund our 2010 acquisitions and $25.0 million of borrowings under our second lien term loan agreement in connection with the Recapitalization. Our net cash used in financing activities in 2009 was $53.6 million as compared to $28.0 million in 2008, an increase in net cash used in financing activities of $25.6 million, or 91%. In 2009, we repaid $53.4 million of outstanding borrowings under our prior first lien credit agreement. In 2008, we paid $19.6 million more in loan payments than we received in borrowings. We also paid $10.6 million in financing fees associated with the restructuring of our prior second lien debt.

Outlook

We expect to fund our acquisition, exploitation and development activities from a variety of sources, including through cash flow from operations, borrowings under our New Credit Facility, issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties. However, we expect that future significant acquisitions will require funding, at least in part, from the proceeds of the issuance of equity securities.

As of June 30, 2011, we had approximately $74.0 million of available borrowing capacity under our New Credit Facility.

For the six months ended June 30, 2011, we realized approximately $10.7 million in gains under our hedging agreements. Based on the NYMEX strip pricing for oil and natural gas as of June 30, 2011, we expect to realize approximately $3.7 million of hedging revenues during the last six months of 2011.

For 2011, our capital program is approximately $85.3 million, which we believe is sufficient to maintain current operations and replace 110% of our annual production. Our 2011 capital budget contemplates spending approximately $32.6 million in connection with the drilling of 12 additional wells, including three development wells in the Texas Gulf Coast, three development wells in the Southeast area, one development well in the South Texas area and five wells in the Midcontinent area (including two wells which we are contractually obligated to drill in Oklahoma as described under “— Contractual Obligations”), and approximately $5.0 million in connection with the workover and recompletion of existing wells. We have also budgeted approximately $36.0 million for acquisitions.

The table below sets forth our 2011 capital budget activity.


			Amount Spent
	2011		Through June 30,		Amount
	Budget(a)		2011		Remaining(b)
			(In millions)

Drilling	$	32.6	$	11.6	$	21.0
Acquisitions		36.0		2.7		33.3
Workovers and recompletions		5.0		5.1		(0.1	)
Geological, geophysical, leasing and seismic		4.3		8.0		(3.7	)
Plugging and abandonment		2.6		1.1		1.5
Facilities, vehicles and other		4.8		0.6		4.2

Total operations capital budget	$	85.3	$	29.1	$	56.2


(a)		2011 capital budget approved by our Board of Directors in December 2010.

(b)		Calculated based upon the 2011 capital budget less amounts spent through June 30, 2011.

The final determination with respect to our 2011 budgeted capital expenditures will depend on a number of factors, including:


	•	changes in commodity prices;

	•	changes in service and materials costs, including from the sharing of costs through the formation of joint ventures with other oil and natural gas companies;

	•	production from our existing producing wells;

	•	the results of our current exploitation and development drilling efforts;

	•	economic and industry conditions at the time of drilling;

	•	our liquidity and the availability of financing; and

	•	properties for sale at an attractive price and rate of return.

Off Balance Sheet Arrangements

We currently do not have off balance sheet arrangements or other such unrecorded obligations, and we have not guaranteed the indebtedness of any other party.

Contractual Obligations

In the schedules below, we set forth our contractual obligations as of December 31, 2010 and June 30, 2011 and the effect those obligations are expected to have on our future cash flow and liquidity. The contractual obligation at June 30, 2011 reflects the completion of the Refinancing transactions.


	As of December 31, 2010
	Payments Due by Year
									2015 and
	Total		2011		2012		2013-2014		Thereafter
	(In thousands)

Debt:
Existing first lien credit agreement	$	184,580	$	184,580	$	—	$	—	$	—
Existing second lien term loan agreement		90,000		60,000		30,000		—		—	��
Existing second lien PIK credit agreement		62,390		—		62,390		—		—
Series A preferred stock		223,630		—		—		—		223,630

Total	$	560,600	$	244,580	$	92,390		—	$	223,630
Other Commitments:
Services(1)	$	1,000	$	1,000		—		—		—
Operating Leases(2)	$	12,461	$	1,765	$	1,798	$	3,797	$	5,101
Interest:
Existing first lien credit agreement	$	7,018	$	7,018	$	—	$	—	$	—
Existing second lien term loan agreement		11,677		8,824		2,853		—		—
Existing second lien PIK credit agreement		12,417		6,484		5,933		—		—
Series A preferred stock		213,835		—		—		—		213,835
Total	$	258,408	$	25,091	$	10,584	$	3,797	$	218,936

Total Commitments(3)	$	819,008	$	269,671	$	102,974	$	3,797	$	442,566


(1)		Consists of fees payable to UBS Securities LLC for advisory services related to acquisitions.


(2)		Consists primarily of leases for office space and office equipment.

(3)		This table does not include the liability for dismantlement, abandonment and asset retirement obligations (see Note 5 to the consolidated financial statements included herein).

As of December 31, 2010 and December 31, 2009, we had liabilities of $40.3 million and $30.1 million, respectively, related to asset retirement obligations, of which $2.9 million and $5.7 million, respectively, was current. Due to the nature of these obligations, we cannot determine precisely when payments will be made to settle these obligations. See “Note 5. Asset Retirement Obligations” in our audited consolidated financial statements contained in this prospectus.


Contractual Obligations
	As of June 30, 2011
	Payments Due by Year
			Less than						2015 and
	Total		1 Year		2012		2013-2014		Thereafter
	(In thousands)

Debt:
New Credit Facility	$	96,000	$	—	$	—	$	96,000	$	—
Notes		243,186		—		—		—		243,186

Total	$	339,186	$	—	$	—	$	96,000	$	243,186

Other Commitments:
Services(1)	$	700	$	700	$	—	$	—	$	—
Operating Leases(2)		11,578		882		1,798		3,797		5,101

Total	$	12,278	$	1,582	$	1,798	$	3,797	$	5,101

Interest:
New Credit Facility	$	13,943	$	1,783	$	3,846	$	8,314	$	—
Notes		129,574		13,417		26,615		53,229		36,313
Total	$	143,517	$	15,200	$	30,461	$	61,543	$	36,313

Total Commitments(3)	$	494,981	$	16,782	$	32,259	$	161,340	$	284,600


(1)		Consists of fees payable to UBS Securities LLC for advisory services related to acquisitions.

(2)		Consists primarily of leases for office space and office equipment.

(3)		This table does not include the liability for dismantlement, abandonment and asset retirement obligations (see Note 3 to the unaudited interim consolidated financial statements included herein), or the Series A Preferred Stock that is redeemable in 2016 at the option of the holder (See Note 9 to the unaudited interim consolidated financial statements included herein).

Pursuant to a drilling, exploration and development agreement with Trueblood Resources, Inc., we are obligated to drill two wells in our Midcontinent area by February 28, 2012. In the event we elect not to proceed with the drilling of these wells, our agreement calls for a liquidation payment to our partners not to exceed $4.5 million. We are also acquiring oil and gas leases within our budgeted capital for this project area, in support of the drilling of these wells. In the event we elect to cease our leasing activities prior to spending our budgeted capital, our agreement calls for an additional liquidation payment not to exceed $1.0 million on September 1, 2011. As of September 30, 2011, we have met the leasing obligation, but we have not met the drilling obligations.

Critical Accounting Policies

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our consolidated financial statements in accordance with GAAP, as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely

alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.

Use of Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. These estimates include oil and natural gas reserve quantities that form the basis for (i) the allocation of purchase price to proved and unproved properties; (ii) calculation of amortization of oil and natural gas properties; and (iii) the full cost ceiling impairment. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Other estimates include (a) estimated quantities and prices of oil and gas sold, but not collected, as of period-end; (b) accruals of capital and operating costs; (c) current plug and abandonment costs, settlement date, inflation rate and credit-adjusted risk-free rate used in estimating asset retirement obligations as detailed in “Note 3. Asset Retirement Obligation” in our unaudited interim consolidated financial statements contained herein; (d) those assumptions and calculation techniques that relate to the determination of the fair value of stock-based compensation, as detailed in “Note 4. Stock-Based Compensation” in our unaudited interim consolidated financial statements contained herein; and (e) those assumptions and calculation techniques used in estimating the fair value of derivative financial instruments, as considered in “Note 6. Fair Values of Financial Instruments” in our unaudited interim consolidated financial statements contained herein. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.

Oil and Natural Gas Properties

Full Cost Accounting — We utilize the full cost method to account for our investment in oil and natural gas properties. Under the full cost method, which is governed byRule 4-10 ofRegulation S-X, all costs of acquisition, exploration, and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. Direct internal costs that are capitalized are primarily the salary and benefits of geologists, landmen, and engineers directly involved in acquisition, exploration and development activities. There was approximately $2.4 million and $1.8 million of direct internal costs capitalized for the six months ended June 30, 2011 and 2010, respectively.

Depreciation, Depletion, and Amortization — The cost of oil and natural gas properties, the estimated future expenditures to develop proved reserves, and estimated future abandonment, site remediation and dismantlement costs are depleted and charged to operations using theunit-of-production method based on the ratio of current production to proved oil and natural gas reserves as estimated by independent engineering consultants.

Impairment — Full cost ceiling limitation impairment is calculated quarterly, whereby net capitalized costs related to proved and unproved properties less related deferred income taxes may not exceed a ceiling limitation. The ceiling limitation is the amount equal to the present value discounted at 10% of estimated future net revenues from estimated proved reserves plus the lower of cost or fair value of unproved properties less estimated future production and development costs and net of related income tax effect. As of June 30, 2011 and December 31, 2010 and 2009, the full cost ceiling limitation is calculated using the12-month average price of oil and natural gas as of the first day of each month for the period ending as of the balance sheet date and is adjusted for “basis” or location differentials. For 2008, the price is based on the spot price as of December 31, 2008. Price is held constant over the life of the reserves. If net capitalized costs related to proved properties less related deferred income taxes exceed the ceiling limitation, the excess is impaired and a permanent write-down is recorded in the consolidated statements of operations.

Unproved Property Costs — Costs directly associated with the acquisition and evaluation of unproved properties, including leasehold, acreage, seismic data, wells in progress and capitalized interest, are excluded from the full cost pool until it is determined whether or not proved reserves can be assigned to the individual prospects or whether impairment has occurred.

We assess all items classified as unproved property on a quarterly basis for possible impairment or reduction in value. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Such unproved property costs fall into four broad categories:


	•	projects that are in the last one to two years of seismic evaluation;

	•	leasehold costs for projects not yet evaluated;

	•	drilling and completion costs for projects in progress at period end that have not resulted in the recognition of reserves for that period; and

	•	interest costs related to financing such activities.

As of December 31, 2010, we made the decision to focus on developing the proved undeveloped reserves acquired in the TexCal Energy South Texas, L.P. and RWG Energy, Inc. acquisitions made during 2010, therefore, $26.9 million of unproved lease costs remaining from the Petrohawk Energy Corporation acquisition in 2007 was reclassified into the full cost pool to be amortized as there are no future plans to evaluate this acreage.

Revenue Recognition and Natural Gas Imbalances

Revenues are recognized and accrued as production occurs and physical possession and title pass to the customer.

We use the sales method of accounting for revenue. Under this method, oil and natural gas revenues are recorded for the amount of oil and natural gas production sold to purchasers. Natural gas imbalances are created, but not recorded, when the sales amount is not equal to our entitled share of production unless there are insufficient reserves. Our entitled share is calculated as gross production from the property multiplied by our net revenue interest in the property. No provision is made for an imbalance unless the oil and natural gas reserves attributable to a property have depleted to the point that there are insufficient reserves to satisfy existing imbalance positions. At that point, a payable or a receivable, as appropriate, is recorded equal to the net value of the imbalance. As of both June 30, 2011 and December 31, 2010, we had recorded a liability of approximately $0.7 million.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before being deductible in the income tax returns or when income items are recognized in the income tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset future taxable income. Deferred tax liabilities arise when income items are recognized in the financial statements before the income tax returns or when expenses are deducted in the tax return prior to recognition in the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change

in tax rates is recognized in operations in the period that includes the date when the change in the tax rate was enacted.

We routinely assess the realizability of our deferred tax assets. If it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax asset is reduced by a valuation allowance.

As a result of the conversion to a corporation effective August 1, 2009, which pursuant to Section 351 of the Internal Revenue Code was a tax-free reorganization, we stepped into the “shoes” of our parent as to the tax value of the net assets. Therefore, the income tax years of 2007 through the conversion date, as well as through the current year, remain open and subject to examination by federal tax authoritiesand/or the tax authorities in each of Texas, Oklahoma, Mississippi, and Louisiana which are our principal operating jurisdictions. These audits could result in adjustments of taxes due or adjustments of the NOLs that are available to offset future taxable income.

ASC 740, Income Taxes prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities.

Our policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in our consolidated statement of operations. For the years ended December 31, 2010 and 2009, respectively, no interest expense or penalties related to unrecognized tax benefits associated with uncertain tax positions have been recognized in the provision for income taxes.

The total amount of unrecognized tax benefit if recognized that would affect the effective tax rate was zero.

Unrecognized tax benefits are not expected to significantly change due to the settlement of audits or the expiration of statute of limitations prior to December 31, 2011. However, due to the complexity of the application of tax law and regulations, it is possible that the ultimate resolution of these positions may result in liabilities which could be materially different from these estimates.

Our parent files a unified tax return in Texas for the Texas Margin Tax, and is the legally responsible party for such taxes. Therefore, any income tax associated with the Texas Margin Tax has not been recognized in our consolidated financial statements. There are no income tax sharing agreements between us and our parent.

See “Note 12. Income Taxes” in our audited consolidated financial statements and “Note 11. Income Taxes” in our unaudited consolidated interim financial statements contained herein for further information.

Derivative Financial Instruments

We purchase derivative financial instruments, specifically, commodity swaps and collars and interest rate collars. Commodity swaps and collars are used to manage market price exposures associated with sales of oil and natural gas. Interest rate collars are used to manage interest rate risk arising from interest payments associated with floating rate debt. Such instruments are entered into for non-trading purposes.

Derivative contracts have not been designated nor do they qualify for hedge accounting. The valuation of these instruments is determined using valuation techniques, including discounted cash flow analysis on the expected cash flows of each derivative. This analysis reflects the contractual terms of the derivatives, including the period to maturity, and uses observable market-based inputs, including price volatility and interest rate curves, as appropriate.

We incorporate credit valuation adjustments to appropriately reflect both our nonperformance risk and the respective counterparty’s nonperformance risk in the fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, any impacts of netting and any applicable credit enhancements, such as collateral postings, thresholds, and guarantees, are considered.

Asset Retirement Obligation

We record a liability for the estimated fair value of our asset retirement obligations, primarily comprised of plugging and abandonment liabilities, in the period in which it is incurred. The liability is accreted each period through charges to accretion expense. The asset retirement cost is included in the full cost pool. If the liability is settled for an amount other than the recorded amount, the difference is recognized in oil and natural gas properties in our consolidated balance sheet.

Recently Issued Accounting Pronouncements

In January 2010, the FASB issued Accounting Standards Update (ASU)2010-06, “Improving Disclosures About Fair Value Measurements” (ASU2010-06), which amends the Fair Value Measurements and Disclosures Topic of the ASC (ASC Topic 820). Among other provisions, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. This amendment requires new disclosures on the value of, and the reason for, transfers in and out of Levels 1 and 2 of the fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements. ASU2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques. ASU2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements, which is effective for interim and annual reporting periods beginning after December 15, 2010. See “Note 5. Derivative Financial Instruments” in our unaudited interim consolidated financial statements contained herein. We adopted the applicable provisions of the rule effective January 1, 2010 and January 1, 2011, respectively.

Controls and Procedures

We have identified certain material weaknesses in our internal control over financial reporting related to (1) inconsistent or ineffective financial statement review and preparation; (2) insufficient financial reporting resources and insufficient resources allocated to information technology. To remediate these issues, our management intends to retain the services of additional third party accounting personnel as well as to modify existing internal controls in a manner designed to ensure future compliance. Our management currently believes the additional accounting resources expected to be retained for purposes of becoming a SEC reporting company will remediate the weakness with respect to insufficient personnel. See “Risk Factors — We have identified material weaknesses in our internal control over financial reporting.”

Quantitative and Qualitative Disclosures About Market Risk

As of December 31, 2010

Commodity Price Risk

Changes in commodity prices significantly affect our capital resources, liquidity and operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of capital available we have to reinvest in our exploitation and development activities. Commodity prices are impacted by many factors that are outside of our control. Over the past few years, commodity prices have been highly volatile. We expect that commodity prices will continue to fluctuate significantly in the future. As a result, we cannot accurately predict future oil and natural gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues.

The prices we receive for our oil production are based on global market conditions. Our average pre-hedged sales price for oil in 2010 was $73.40 per Bbl, which was 40% higher than the prices we received in 2009. Significant factors that impacted 2010 oil prices included the pace at which the domestic and global

economies recovered from the current recession, theDeepwater Horizon incident in the U.S. Gulf of Mexico and the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations were able to manage oil supply through export quotas and developments in the Middle East countries.

Natural gas prices are primarily driven by North American market forces. However, global LNG shipments can impact North American markets to the extent cargoes are diverted from Asia or Europe to North America. Factors that can affect the price of natural gas include changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Over the past three years, natural gas prices have been volatile. Our average pre-hedged sales price for natural gas in 2010 was $4.39 per Mcf, which was 16% higher than the price we received in 2009. Natural gas prices in 2010 were dependent upon many factors including the balance between North American supply and demand.

We have utilized swaps and costless collars to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans. The following table details derivative contracts that settled during 2010 and includes the type of derivative contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain/(loss) upon settlement.


	2010

*Oil collars*
Volumes (Bbls)		626,276
Average floor price (per Bbl)	$	73.53
Average ceiling price (per Bbl)	$	90.24

Gain/(loss) upon settlement	$	52,803
*Oil swaps*
Volumes (Bbls)		—
Average swap price (per Bbl)		—

Gain/(loss) upon settlement		—
*Total oil gain/(loss) upon settlement*	$	52,803

*Natural gas collars*
Volumes (Mcf)		1,761,338
Average floor price (per Mcf)	$	7.60
Average ceiling price (per Mcf)	$	11.20

Gain/(loss) upon settlement	$	3,828,572
*Natural gas swaps*
Volumes (Mcf)		7,812,997
Average swap price (per Mcf)	$	7.74
Gain/(loss) upon settlement	$	35,473,540

*Total natural gas gain/(loss) upon settlement*	$	39,302,112

Interest Rate Risk

We are exposed to changes in interest rates that affect the interest paid on borrowings under our existing first lien credit agreement, the borrowings under our existing second lien loan agreements and the interest that we will pay on borrowings under our New Credit Facility. To manage our interest rate risk and reduce our sensitivity to volatile interest rates, we entered into a series of zero-cost interest rate collars in 2008 that effectively set a LIBOR ceiling of 4.90% for approximately $375.0 million of our LIBOR-based indebtedness. As of December 31, 2010, we were still contractually covered by $150.0 million of these interest rate collars, and themarked-to-market value (deficit) of these swaps was approximately $3.5 million which we owe to the

counterparties. Based on our debt structure at December 31, 2010, a 1% increase in interest rates, excluding interest rate hedges, would increase interest expense by approximately $1.85 million per year, based on the approximately $184.6 million of floating rate indebtedness outstanding under our existing first lien credit agreement that would be affected by such a movement in interest rates.

Concentration of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of temporary cash investments, trade accounts receivable and derivative instruments. We believe that we place our excess cash investments with strong financial institutions. Our receivables generally relate to customers in the oil and natural gas industry, and as such, we are directly affected by the economy of the industry. During 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues and during 2009, ten customers collectively accounted for 70% of our oil and natural gas revenues. This concentration increases our credit risk. We seek to mitigate our credit risk by, among other things, monitoring customer creditworthiness.

Counterparty Risk

We have exposure to financial institutions in the form of derivative transactions in connection with our hedges. These transactions are with counterparties in the financial services industry, specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. In addition, we also have exposure to financial institutions which are lenders under our credit facilities. If any lender under our existing first lien credit agreement, or under our New Credit Facility, is unable to fund its commitment, our liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitment under the New Credit Facility.

As of June 30, 2011

Commodity Price Risk

Changes in commodity prices significantly affect our capital resources, liquidity and operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of capital we have available to reinvest in our exploitation and development activities. Commodity prices are impacted by many factors that are outside of our control. Over the past few years, commodity prices have been highly volatile. We expect that commodity prices will continue to fluctuate significantly in the future. As a result, we cannot accurately predict future oil and natural gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues.

The prices we receive for our oil production are based on global market conditions. Significant factors that impacted oil prices in the first half of 2011 included the pace at which the domestic and global economies recovered from the current recession, the ongoing tensions and uprisings in the Middle East and North Africa, and the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations were able to manage oil supply through export quotas.

Natural gas prices are primarily driven by North American market forces. However, global LNG shipments can impact North American markets to the extent cargoes are diverted from Asia or Europe to North America. Factors that can affect the price of natural gas include changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials, and other factors. Over the past several years, natural gas prices have been volatile. Our average pre-hedged sales price for natural gas in the first half of 2011 was $4.15 per Mcf, which was 12% lower than the price of $4.70 per Mcf that we received in the first half of 2010. Natural gas prices in the first half of 2011 were dependent upon many factors including the balance between North American supply and demand.

We have utilized swaps and costless collars to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure that we can execute at least a portion of our capital spending plans with internally generated funds.. The following table details derivative contracts that settled during 2011 and includes the type of derivative

contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain/(loss) upon settlement.


	As of
	June 30, 2011

*Oil collars*
Volumes (Bbls)		394,943
Average floor price (per Bbl)	$	76.00
Average ceiling price (per Bbl)	$	86.73
Gain/(loss) upon settlement	$	(4,885,993	)
*Oil swaps*
Volumes (Bbls)		29,289
Average swap price (per Bbl)	$	98.28
Gain/(loss) upon settlement	$	(89,615	)

*Total oil gain/(loss) upon settlement*	$	(4,975,608	)

*Natural gas collars*
Volumes (Mcf)
Average floor price (per Mcf)	$	—
Average ceiling price (per Mcf)	$	—
Gain/(loss) upon settlement	$	—
*Natural gas swaps*		—
Volumes (Mcf)		1,388,794
Average swap price (per Mcf)	$	8.22
Gain/(loss) upon settlement	$	15,708,144

*Total natural gas gain/(loss) upon settlement*	$	15,708,144

The following derivatives contracts were in place as of September 30, 2011.


			MMbtu/ Mo. or
Natural Gas	Type		Avg. MMbtu/Mo.		Price/MMbtu

Oct-11 to Oct -11		Collar		300,000	$4.50 - $5.25
Oct-11 to Oct-11		Swap		174,525	$7.93
Oct-11 to Dec-11		Collar		100,000	$3.50 - $5.30
Nov-11 to Dec-11		Collar		380,082	$7.00 - $10.60
Nov-11 to Dec-11		Swap		170,128	$8.43
Jan-12 to Dec-12		Collar		150,000	$6.50 - $8.10
Jan-12 to Dec-12		Swap		133,076	$5.00
Jan-12 to Dec-12		Collar		50,000	$4.25 - $5.35
Jan-12 to Dec-12		Swap		75,000	$5.15
Jan-13 to Dec-14		Swap		100,000	$5.20
Jan-13 to Dec-13		Collar		40,000	$5.00 - $5.85
Jan-13 to Dec-13		Collar		90,000	$4.75 - $5.75
Jan-13 to Dec-13		Collar		40,000	$4.70 - $5.75
Jan-14 to Dec-14		Collar		40,000	$5.10 - $6.20
Jan-14 to Nov-14		Collar		73,820	$4.50 - $6.15


			Bbl/Mo. or
Crude Oil	Type		Avg. Bbl/Mo.		Price/Bbl

Oct-11 to Dec-11		Collar		26,107	$68.00 - $80.71
Oct-11 to Dec-11		Collar		3,000	$80.00 - $89.25
Oct-11 to Oct-11		Swap		1,181	$101.60
Oct-11 to Dec-11		Swap		8,667	$99.85
Oct-11 to Dec-12		Collar		10,000	$80.00 - $93.24
Jan-12 to Aug-12		Collar		25,000	$80.00 - $91.60
Sep-12 to Dec-12		Collar		25,391	$80.00 - $86.00
Jan-12 to Aug-12		Swap		3,628	$101.60
Jan-12 to Dec-12		Collar		5,000	$90.00 - $96.50
Jan-13 to Dec-13		Collar		6,000	$90.00 - $111.85
Jan-13 to Dec-13		Collar		8,000	$92.00 - $102.95
Jan-13 to Dec-13		Collar		2,000	$93.00 - $102.00
Jan-13 to Dec-14		Collar		3,000	$91.00 - $98.00
Jan-13 to Dec-14		Collar		2,000	$90.00 - $97.00
Jan-13 to Dec-14		Collar		2,000	$91.00 - $97.00
Jan-13 to Dec-14		Collar		2,000	$92.00 - $98.00
Jan-13 to Dec-14		Collar		2,000	$92.00 - $100.00
Jan-13 to Dec-14		Collar		2,000	$93.00 - $101.00
Jan-13 to Dec-14		Swap		1,000	$91.00
Jan-13 to Dec-14		Swap		1,000	$91.50
Jan-14 to Dec-14		Collar		10,000	$93.00 - $100.25


			Bbl/Mo. or
Natural Gas Liquids	Type		Avg. Bbl/Mo.		Price/Bbl

Oct-11 to Dec-11		Swap		15,000	$56.79
Jan-12 to Dec-12		Swap		5,000	$51.00
Jan-12 to Dec-12		Swap		6,000	$51.25
Jan-13 to Dec-13		Swap		3,300	$46.25
Jan-13 to Dec-13		Swap		4,000	$47.00
Jan-14 to Dec-14		Swap		6,500	$43.75

Interest Rate Risk

We are exposed to changes in interest rates that affect the interest paid on borrowings under our New Credit Facility, and the interest settlement that we will pay or receive on the $100 million fixed rate to floating rate interest swap that we entered into in June 2011. To manage our interest rate risk and reduce our sensitivity to volatile interest rates, we entered into a series of zero-cost interest rate collars in 2008 that effectively set a LIBOR ceiling of 4.90% for approximately $375.0 million of our LIBOR-based indebtedness. As of December 31, 2010, we were still contractually covered by $150.0 million of these interest rate collars. As of June 30, 2011, we had approximately $112.5 million of these interest rate collars on our books. These remaining collars expired on September 5, 2011. In June 2011, we entered into an interest rate derivative arrangement whereby we swapped the fixed 10.5% per annum interest payment stream on $100 million worth of our Notes for floating rate interest payments based on3-month LIBOR plus a fixed margin applied to on $100 million of notional floating rate debt.

As a result of unprecedented turmoil in the capital markets themarked-to-market value of the reverse interest rate swap increased to a level close to our forecasted value for the instrument for the five year life of

the instrument. As a result, we terminated this arrangement with our counter-party and realized a $2.0 million cash gain on the transaction.

Based on our debt structure at June 30, 2011, a 1% increase in interest rates, excluding interest rate hedges, would increase interest expense by approximately $960,000 per year, based on the approximately $96.0 million of floating rate indebtedness outstanding under our New Credit Facility that would be affected by such a movement in interest rates.

Concentration of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of temporary cash investments, trade accounts receivable and derivative instruments. We believe that we place our excess cash investments with strong financial institutions. Our receivables generally relate to customers in the oil and natural gas industry, and as such, we are directly affected by the economy of the industry. During the six months ended June 30, 2011, ten customers collectively accounted for 71% of our oil and natural gas revenues and during the six months ended June 30, 2010, ten customers collectively accounted for 73% of our oil and natural gas revenues. This concentration increases our credit risk. We seek to mitigate our credit risk by, among other things, monitoring customer creditworthiness.

Counterparty Risk

We have exposure to financial institutions in the form of derivative transactions in connection with our commodity and interest rate hedges. These transactions are with counterparties in the financial services industry, specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. In addition, we also have exposure to financial institutions which are lenders under our credit facilities. If any lender under our New Credit Facility is unable to fund its commitment, our liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitment under the credit facility.

BUSINESS

Overview

As of December 31, 2010, we owned interests in 1,522 gross (858.3 net) wells and had average daily net production in December 2010 of approximately 9,048 Boe/d and approximately 9,005 Boe/d for the year ended December 31, 2010. The wells that we operate provided approximately 78% of our average daily production for 2010. Through December 31, 2010, we spent approximately $15.8 million to drill or complete 12 gross (9.4 net) wells, of which 10 were successful adding approximately 143 net Boe/d to our 2010 average daily production, and spent approximately $3.3 million to acquire new leases in Texas and Oklahoma.

As of December 31, 2010, our estimated net proved reserves, as prepared by our independent reserve engineering firm, W.D. Von Gonten & Co., were 36.7 MMBoe, consisting of 134.7 Bcf of natural gas, 9.9 MMBbl of oil, and 4.3 MMBbl of NGLs. As of December 31, 2010, approximately 61% of our net proved reserves were natural gas and approximately 39% were oil and NGLs, and approximately 67% of our reserves were proved developed. Our estimated reserve to production ratio as of December 31, 2010 was 11.1 years.

As a result of our exploitation and development activities, since January 1, 2008, we have drilled 83 gross (58.7 net) wells, consisting of 50 exploratory and 33 development wells with an average completion rate of 75%. During 2008, we drilled 69 gross (48.8 net) wells, consisting of 43 exploratory wells and 26 development wells with an average completion rate of 78%. In 2009, we drilled two gross (0.5 net) wells, consisting of one exploratory well, which was not successful, and one development well, which was completed, for an average completion rate of 50%. Our lower drilling and completion rate in 2009 as compared to 2008 was attributable to capital constraints and a lower pricing environment. In addition, we sold the Winchester field properties in Mississippi in April 2009 for $32.0 million. During 2010, we drilled 12 gross (9.4 net) wells, consisting of six gross (3.6 net) exploratory wells and six gross (5.8 net) development wells with an average completion rate of 58%. Three of the 12 wells drilled in 2010 will not be completed until 2011.

During 2008 through December 2010, we have spent approximately $185.5 million on drilling and approximately $37.9 million on leasing and seismic. In 2008, we spent a total of approximately $163.4 million on drilling and approximately $28.5 million on leasing and seismic. In 2009, we spent a total of approximately $6.3 million on drilling and approximately $5.1 million to acquire additional leases and seismic data. Our 2009 spending on drilling, leasing and seismic acquisitions represented a 94% decrease from that in 2008, as we curtailed our operated drilling and completion activity through 2009. The decline in operated activity was a result of reduced commodity prices and the unavailability of capital resources. For 2010, we spent approximately $20.1 million on exploitation and development activities, which included approximately $15.8 million on drilling and approximately $4.3 million to acquire additional leases and seismic data. The increase in our 2010 capital expenditure budget as compared to that for 2009 was made possible because of increased commodity prices and an increase in available capital as a result of our 2010 recapitalization. Our 2011 capital budget contemplates spending approximately $32.6 million in connection with the drilling of 12 additional wells, including three development wells in the Texas Gulf Coast, three development wells in the Southeast area, one development well in the South Texas area and five wells in the Midcontinent area (including two wells which we are contractually obligated to drill in Oklahoma as described under “— Core Areas — Midcontinent”), and approximately $5.0 million in connection with the workover and recompletion of existing wells. We have also budgeted approximately $36.0 million for acquisitions.

During 2010, we spent approximately $95.9 million in capital expenditures to support our business plan. Of this amount, we spent $15.8 million to drill or complete 12 gross (9.4 net) wells, 10 of which were successful, adding approximately 143 net Boe/d to our 2010 average daily production. During 2010, we worked-over or recompleted 85 gross (76 net) wells at a capital cost of $9.9 million through the end of the year. These efforts added approximately 700 Boe/d to our average daily production for 2010. We also spent approximately $66.9 million to complete two acquisitions of additional proved reserves in our core areas of the onshore Texas Gulf Coast and the Midcontinent area, adding approximately 7.6 MMBoe, and $3.3 million to acquire leases in Oklahoma and Texas as part of our strategy to develop one of our new focus areas, the Atoka Shale.

The following table provides information with respect to our estimated net proved reserves as of December 31, 2010, as prepared by W.D. Von Gonten & Co., and our average daily production for 2010.


								NYMEX									2010
			% of					Strip									Average		% of 2010
	Net Proved		Total			SEC Pricing		Pricing					Total				Daily		Average
	Reserves		Proved			PV-10		PV-10					Wells				Production		Daily
Area	(MMBoe)(a)		Reserves(a)			(Millions)(a)		(Millions)(b)		% Gas			Gross		Net		(Boe/d)(c)		Production

Texas Gulf Coast		12.5		34.1	%	$	204.1	$	255.4		62	%		507		302.1		3,721		41	%
Southeast		9.0		24.5	%		154.3		204.7		53	%		456		253.7		2,634		29	%
South Texas		9.4		25.6	%		98.4		131.0		77	%		414		212.4		2,569		29	%
Midcontinent		5.8		15.8	%		36.1		52.7		47	%		145		90.1		81		1	%

Total		36.7		100	%	$	492.9	$	643.8		61	%		1,522		858.3		9,005		100	%


(a)		Our “SEC Pricing” net proved reserves as of December 31, 2010 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on average prices as of the first day of each of the twelve months ended on such date. These average prices were $79.43 per Bbl for oil and $4.38 per MMBtu for natural gas for December 31, 2010. Pricing was adjusted for basis differentials by field based on our historical realized prices.

(b)		Our “NYMEX Strip Pricing” net proved reserves as of December 31, 2010 were calculated using oil and natural gas prices based on average annual NYMEX forward-month contract pricing in effect on such dates. For December 31, 2010, the assumed oil prices were $93.61 per Bbl in 2011, $93.95 per Bbl in 2012, $92.95 per Bbl in 2013, $92.40 per Bbl in 2014 and $92.55 per Bbl held constant thereafter and the assumed natural gas prices were $4.59 per MMBtu in 2011, $5.08 per MMBtu in 2012, $5.33 per MMBtu in 2013, $5.49 per MMBtu in 2014 and $5.64 per MMBtu held constant thereafter. Pricing was adjusted for basis differentials by field based on our historical realized prices. The “NYMEX Strip Price” net proved reserves are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with the “SEC Pricing” net proved reserves as outlined above and do not comply with SEC pricing assumptions.

(c)		Average daily production volumes are calculated by summing volumes produced during a given time period, then dividing the sum by the number of days in that time period.

Business Strategy

The key elements of our business strategy include:

Pursue asset acquisitions that leverage our exploitation capabilities and are weighted towards oil or NGLs

We plan to continue to pursue asset acquisitions which offer exploitation and development opportunities. Drawing on our management team’s experience, we seek targeted acquisitions of relatively lower risk properties that have further exploitation and development potential as well as opportunities for increased production through recompletions, workovers and cost efficiencies. In addition, we seek to acquire properties that we can operate with a strong proved developed producing component, such as our May 2010 acquisition for $22.4 million of onshore Texas Gulf Coast properties with net proved reserves of approximately

1.7 MMBoe. We intend to focus on properties that are weighted towards oil or NGLs, provide greater geographic diversity, such as our recent acquisitions in the Midcontinent, and contribute towards extending our current R/P ratio of 11.1 years.

Continue our lower risk development drilling program

We intend to continue our lower risk development drilling program aimed at converting proved undeveloped reserves to proved developed producing reserves in order to help offset the annual production declines that are typical in the onshore Gulf Coast region. We have an inventory of 95 proved undeveloped locations, which we believe, if completed, will provide significant production replacement. We also plan to continue our focus on the workover and recompletion of existing wells. We further seek to grow our production through drilling in unconventional resource plays. We intend to drill three wells in this play in 2011. Should these wells be successful, we expect our Atoka Shale properties will provide an additional source of lower risk development drilling locations.

Grow our proved reserves and production

In 2010, we drilled six gross (5.8 net) development wells, all of which were successful, adding approximately 94 Boe/d to our average daily production for 2010. During 2010, our production replacement strategy and various drilling activity enabled us to maintain a relatively flat daily production profile of approximately 9,005 Boe/d from existing reserves. We believe that our lower risk development drilling program, combined with our ongoing acquisition strategy, will assist us in meeting our goal to grow our net proved reserves and production.

Continue our focus on cost control

We intend to continue our focus on cost control while acquiring properties, growing our reserves and seeking exploitation and development opportunities. We seek to control costs at all levels including through driving down lease operating expense by maximizing compression, efficiently handling water disposal, carefully coordinating drilling and workover activity in the field and reducing overall company general and administrative costs. Although we will seek to improve our current leverage position, our future levels of indebtedness are largely dependent on a variety of factors, including our future performance. We cannot assure you that we will be able to improve our current leverage position. See “Risk Factors — We cannot assure you that we will be able to improve our leverage position.”

Actively manage our hedging program to reduce sensitivity to commodity prices

We employ the use of swaps and costless collar derivative instruments to limit our exposure to commodity price volatility. As of June 30, 2011, we had hedging contracts in place for 930,548 Boe from July 1, 2011 through the end of 2011 and 1,386,736 Boe during 2012. Based on the forecasted production set forth in our most recent reserve report, we have hedged approximately 73% of our expected 2011 and 2012 proved developed producing production as of June 30, 2011. In the future, we will seek to enter into commodity price hedging contracts for additional volumes of our expected proved developed producing production.

Our Strengths

Our competitive strengths include:

Substantial undeveloped or prospective acreage to support future exploitation and development efforts

As of December 31, 2010, we had 113,510 gross (60,841 net) acres of undeveloped leasehold acreage and have identified 95 proved undeveloped drilling locations on our properties. We anticipate identifying additional locations on these properties as we pursue our exploitation and development activities. We believe the successful development of this acreage will provide us an opportunity to augment our net acreage position with additional leasing during 2011 adjacent to, or on trend with, our exploitation and development efforts.

Balanced capital expenditure strategy coupled with proactive focus on cost control positions us to maintain positive cash flow and liquidity

We intend to implement a capital expenditure program sized to be in line with our operating cash flow. We have implemented a comprehensive program of cost controls and have a proactive hedging strategy intended to provide more predictable levels of revenues. In addition, we currently operate approximately 55.1% of our properties, based on producing wells at December 31, 2010, which gives us the ability to control operations and associated costs on a majority of our properties. We believe our capital expenditure strategy, cost control plan and proactive hedging strategy will allow us to fund our growth while maintaining liquidity for our operations.

Substantial internal capability and capacity to manage and absorb additional acquisitions

Our management and technical teams have significant acquisition experience in our core areas. In the last twelve months, we have successfully completed two acquisitions in our core areas of the onshore Texas Gulf Coast and the Midcontinent area for an aggregate cost of $66.9 million which added approximately 7.6 MMBoe of proved reserves. After completion of the offering of the old notes and the Refinancing transactions, we believe that we have sufficient personnel and infrastructure to facilitate additional acquisitions and the integration of operations associated with any acquired properties.

Ownership of a substantial inventory of reprocessed seismic data to help us identify future development and exploitation opportunities

Since 2007, we have spent approximately $19.3 million on seismic data acquisitions and have a library of approximately 30,000 square miles of3-D data in our core areas. We believe that3-D seismic data is a valuable tool that can improve drilling results, reduce exploration risks and ultimately enhance production and returns. In the areas in which we operate, we also believe that3-D seismic data provides opportunities to discover additional infield drilling locations. We believe that utilizing this technology in exploring for, developing and exploiting natural gas and oil properties has helped us reduce drilling risks, lower finding costs, lower lease operating expenses and provide for more efficient production from our properties.

Experienced management and technical team

Our management team has an average of more than 25 years of industry experience, including international and domestic public company experience, and has been involved in numerous acquisitions. Our management team has also developed relationships with major and independent industry partners, land and mineral owners, service providers, and independent prospect generators. We believe these relationships will help us to identify new acquisition opportunities, as well as provide information about new trends, prospects and technologies.

We employ 11 operational and technical professionals, including geophysicists, geologists, petroleum, drilling, production and reservoir engineers who have more than 23 years of industry expertise in their specialized, technical fields. The diversity of experience of our engineering, land, geological and geophysical teams in a wide range of settings, combined with various technical specializations, provides us with valuable technical and intellectual resources. We have assembled our teams with backgrounds that complement the areas where we focus our exploitation and development activities. By integrating their various expertise within our project teams, we believe we possess a competitive advantage in our acquisition, exploitation and development strategies.

Support from our existing sponsors

Our current equity investors include ACON Investments, Guggenheim Capital and West Coast Partners, each of whom made substantial investments in us to fund our acquisition of the Gulf Coast assets of Petrohawk Energy Corporation, and to further our exploitation and development efforts. These investors also made significant investments in connection with the discharge of our prior second lien indebtedness in

connection with the issuance of our Series A preferred stock. We believe that our equity sponsors provide us with management expertise and increased exposure to acquisition opportunities.

Oil and Gas Reserves

W.D. Von Gonten & Co. prepared the estimates of our net proved reserves and future net cash flows (and present value thereof) attributable to such net proved reserves at December 31, 2010. Our internal controls include a bottom up approach to preparing reserves. Our area geologists and engineers provide information to our director of engineering who reviews the information against historical performance and who maintains and prepares our reserves database semi-annually. W.D. Von Gonten & Co. then generates an independent third party reserve report using our reserve database as a starting point. Our director of engineering then cross checks the independent reserve report for accuracy and reviews the results with W.D. Von Gonten & Co. Phillip R. Hunter, the registered professional engineer responsible for the reports generated by W.D. Von Gonten & Co., has over ten years of industry experience, including data analysis and project management.

Our director of engineering, Don Hausen, who is a certified petroleum engineer licensed in the State of Texas with ten years of experience in oil and natural gas reserve estimation, is also responsible for preparing our internal semi-annual reserve report. The reserve estimates for producing properties are based on production trends, material balance calculations, analogy to comparable properties,and/or volumetric analysis. Performance methods are preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on volumetric analysis or analog to offset production in the same field.

The following table sets forth certain information about our estimated proved reserves as of December 31, 2010.


			Natural
	Oil		Gas		NGL		Total
	(MBbls)		(MMcf)		(MBbls)		MBoe

Proved Developed		5,098.1		53,233.9		1,740.2		15,710.6
Proved Developed Non-Producing		2,201.8		37,166.8		316.9		8,713.2
Proved Undeveloped		2,625.6		44,321.0		2,247.9		12,260.3

Total Proved		9,925.5		134,721.7		4,305.0		36,684.1

As of December 31, 2010, our proved undeveloped reserve locations totaled 12.3 MMBoe, a 64% increase from our proved undeveloped reserve locations at December 31, 2009. During 2010, we spent $2.7 million converting four locations at December 31, 2009 to proved developed at December 31, 2010. The majority of the increase in our proved undeveloped reserves was the result of our acquisitions in 2010 and new locations identified by internally generated field studies. We expect all of our proved undeveloped reserve locations at December 31, 2010 to be developed over the next five years. Estimated future costs related to the development of these locations are expected to total $152.8 million.

The estimated cash flows from our proved reserves at December 31, 2010 were as follows:

Proved

Developed

Proved

Non-

Proved

Total

Developed

Producing

Undeveloped

Proved

(M$)

Estimated pre-tax future net cash flows(1)

395,329

234,307

221,073

850,709

Discounted pre-tax future net cash flows(PV-10)(1)

264,888

116,144

111,897

492,929


(1)		PV-10 is a non-GAAP financial measure which is derived from the standardized measure of discounted future net cash flows which is the most directly comparable GAAP financial measure. Our management believes that the presentation ofPV-10 is useful to investors because it is based on prices, costs and discount factors which are consistent from company to company, while the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company.PV-10


		presents the discounted future net cash flows attributable to our net proved reserves before taking into account future corporate income taxes and our current tax situation. As a result, we believe that investors can use these non-GAAP measures as a basis for comparison of the relative size and value of our reserves to other companies. The following table reconciles undiscounted and discounted future net cash flows to the standardized measure of discounted cash flows as of December 31, 2010 using “SEC Pricing.”


Estimated pre-tax future net cash flows	$	850,709
10% annual discount		(357,780	)
Discounted pre-tax future net cash flows(PV-10)	$	492,929
Future income taxes discounted at 10%		(43,894	)
Standardized measure of discounted future net cash flows	$	449,035

We have not filed any reports with other federal agencies that contain an estimate of total proved net oil and natural gas reserves.

Core Areas

Texas Gulf Coast

Our Texas Gulf Coast properties are principally located onshore in Lavaca, Colorado, Goliad, Wharton and Matagorda Counties, with concentrated efforts in the Frio, Miocene and Yegua trends. Our two core areas within our Texas Gulf Coast region are the Magnet Withers and Lions fields. Since January 1, 2008, we have drilled 42 gross (30.6 net) wells on our Texas Gulf Coast properties and we have completed 34 of those wells. As of December 31, 2010, we had interests in 507 gross (302.1 net) wells in this area, with an average net working interest of 59.6% and average daily net production in December 2010 of approximately 3,242 Boe/d. We operate approximately 59.1% of our properties in the Texas Gulf Coast based on producing wells at December 31, 2010. In 2010, we drilled five development wells and two exploratory wells in the Texas Gulf Coast area, as well as performed 49 production enhancing workovers. We currently anticipate drilling three development wells in this area in 2011, all of which will be at the Magnet Withers field.

At December 31, 2010, net proved reserves attributable to the Magnet Withers field were approximately 5.6 Bcf of natural gas and 4.0 MMBbl of oil and NGLs. Our properties within the Magnet Withers field account for 13% of our total net proved reserves. During 2010, our average daily net production from Magnet Withers averaged 1,170 Boe/d, including approximately 3.8 MMcf of natural gas and approximately 533 Bbl of oil and NGLs, down from 1,707 Boe/d during 2009.

Magnet Withers is a regional sized low relief four way closure created by rolling into an up to the basin fault. The field is located in the Frio trend of Upper Gulf Coast of Texas and was discovered in the 1930s. Production to date is approximately 134 MMBbl of oil and 1,417 Bcf of natural gas. Shallow Miocene production, above 4,800 feet, is dry gas that produces by depletion and water drive. The deeper Frio production from 4,800 feet to a depth of 7,400 feet is oil that produces dominantly by strong water drive. The field is non-pressured, although pressure does develop below the base of the Frio in the Vicksburg Shale section. Magnet Withers is largely un-faulted except along its eastern flank and reservoirs are generally continuous with some stratigraphic restrictions. The main field oil play, the Frio 1, was originally an associated oil reservoir with a large gas cap that produced by water drive. Blow down of the gas cap in this interval has resulted in a lowered reservoir pressure but has left significant volumes of un-drained oil in off-structure accumulations which have been targeted by recent drilling.

At December 31, 2010, net proved reserves attributable to the Lions field were approximately 7.0 Bcf of natural gas. Lions accounts for 3% of our total net proved reserves. During 2010, our daily net production from Lions averaged 727 Boe/d, including approximately 4.4 MMcf of natural gas, down from 1,195 Boe/d during 2009.

The Lions field is a structurally controlled three way fault accumulation with strong stratigraphic influence. The leading fault creates the predominant trap with associated en-echelon faulting as a fault system providing additional complexity and compartmentalization. Production is from sands in the Lower Wilcox

intervals between 13,500 feet down to the Cretaceous Glide Plane at 16,000 feet. The section is over-pressured and produces essentially dry gas. The main field pay is the Upper Corona Sand which was discovered in 2004. Field development relies on seismic interpretation. Multiple wells have been drilled since discovery of the field, targeting high structural positions along the several trapping faults mapped within the field. Production from Lions field to date is approximately 81 Bcf of natural gas.

Southeast

Our Southeast properties are principally located in St. Martin, Vermilion and Cameron Parishes of Louisiana, Covington, Jefferson Davis, Marion and Wayne Counties of Mississippi and Jefferson, Chambers and Liberty Counties of Texas. Our two core areas are the Gueydan Dome and West Lake Verret field in Louisiana. Since 2008, we have drilled 14 gross (8.7 net) wells on our Southeast properties and have completed 10 of those wells. As of December 31 2010, we had interest in 456 gross (253.7 net) wells in this area, with an average working interest of 55.6% and average net daily production in December 2010 of approximately 2,680 Boe/d. We operate approximately 43.6% of our properties in the Southeast area based on producing wells at December 31, 2010. In 2010, we drilled one development well and performed 21 production enhancing workovers. We currently anticipate drilling three development wells in this area in 2011, including one development well at the Gueydan Dome and one development well at West Lake Verret.

At December 31, 2010, net proved reserves attributable to the Gueydan Dome were approximately 1.3 Bcf of natural gas with 0.6 MMBbl of oil and NGLs. The Gueydan Dome accounts for 2% of our total net proved reserves. During 2010, our average daily net production from the Gueydan Dome averaged 333 Boe/d, including approximately 0.1 MMcf of natural gas and approximately 317 Bbl of oil, down from 403 Boe/d during 2009.

The Gueydan Dome is a piercement salt dome located in the Salt Dome Province of Louisiana. First discovered in the 1930s, the field is located on dry land. Production is predominantly oil with associated gas that produces by a strong water drive. The field produces from both the Miocene and Frio sections. Shallow Miocene and Upper Frio intervals between 1,800 feet and 4,000 feet produce in an overall four way faulted structure that drapes across a deeper seated salt piercement. The deeper production, and the main Alliance Sand oil play, while stratigraphic, are trapped by salt piercement and associated radial faulting. The bulk of production is from normally pressured reservoirs in the field although some pressured reservoir production is found below 10,000 feet to 11,000 feet. Production to date on Gueydan Dome totals approximately 15 MMBbl of oil and 29 Bcf of natural gas.

At December 31, 2010, net proved reserves attributable to the West Lake Verret field were approximately 0.6 Bcf of natural gas with 1.3 MMBbl of oil. West Lake Verret accounts for approximately 4% of our total net proved reserves. During 2010, our average daily net production from West Lake Verret averaged 436 Boe/d, including approximately 0.4 MMcf of natural gas and approximately 374 Bbl of oil, down from 533 Boe/d during 2009.

West Lake Verret was discovered in the 1930s and is a large structurally trapped accumulation located in the Miocene Trend of Louisiana. It is located in the waters of the Atchafalaya Basin. The field is an overall faulted four way closure which resulted from salt evacuation, leaving a central graben with rimming faults. Production is predominantly oil and associated gas that produces with a water drive from stacked pay intervals between 800 feet and 12,500 feet. The bulk of the production is from the non-pressured section above 11,500 feet. In the main field pays, the J through R section, the field produces high side to faults that are down to the central basin graben which in itself produces as a faulted four way trap. Shallow production, above 2,800 feet, is restricted to faulted high side and low relief four way traps on the western flank of the overall field closure that are structurally detached from the deeper field pays. Overpressured production is predominantly gas with associated liquids in the AA through PP Sands and is limited to the central portion of the field. Since discovery at the West Lake Verret field, overall field production to date has totaled approximately 77 MMBbl of oil and 307 Bcf of natural gas.

In addition to our properties in Louisiana, Mississippi and Texas, our Southeast area includes a non-operating interest in nine offshore fields in the Outer Continental Shelf off the coast of Louisiana which are subject to BOEMRE jurisdiction.

South Texas

Our South Texas properties are principally located in Starr, Hidalgo, Live Oak and Bee Counties, with concentrated efforts in the Vicksburg and Wilcox trends. Our two core areas are the Nabors and La Reforma fields. Since January 1, 2008, we have drilled 25 gross (17.4 net) wells on our South Texas properties and have completed 18 of those wells. As of December 31, 2010, we had interests in 414 gross (212.4 net) producing wells in this area, with an average working interest of 51.3% and average daily net production in December 2010 of approximately 2,287 Boe/d. We operate approximately 51.2% of our properties in the South Texas area based on producing wells at December 31, 2010. In 2010, we drilled two exploratory wells in the South Texas area and performed 15 production enhancing workovers. We currently anticipate drilling one development well in this area in 2011, but it will be not be in either of the core areas of the South Texas properties.

At December 31, 2010, net proved reserves attributable to the Nabors field were approximately 9.5 Bcf of natural gas with 0.6 MMBbl of oil and NGLs. Nabors accounts for 6% of our total net proved reserves. During 2010, our average daily net production from Nabors averaged 891 Boe/d, including approximately 4.0 MMcf of natural gas, 230 Bbl of oil and NGLs, down from 1,432 Boe/d during 2009.

Nabors is a high side closure with several inter-field faults breaking up the productive reservoirs. Production is overpressured and from numerous Vicksburg sands, ranging from 9,200 feet to 11,300 feet. First production began in 2000 and to date the field has produced 11 Bcf of natural gas and 106 MMBbl of oil. The Vicksburg reservoirs at Nabors are complex. We have been developing these reservoirs using seismic and stratigraphic interpretations to define locations that target un-depleted high structural prospects.

At December 31, 2010, net proved reserves attributable to La Reforma were approximately 5.3 Bcf of natural gas with 0.7 MMBbl of oil and NGLs. La Reforma accounts for 4% of our total net proved reserves. During 2010, our average daily production from La Reforma averaged 204 Boe/d, including approximately 0.7 MMcf of natural gas, 80 Bbl of oil and NGLs, down from 280 Boe/d during 2009.

The La Reforma fields are located in the Vicksburg and Frio trends of South Texas. La Reforma is a broad faulted four way feature that is productive in multiple high side fault traps on both the upthrown and downthrown portions of a large down to the coast fault. Production is from the Frio and Vicksburg sections and is stratigraphically complex. The Frio formation was discovered in 1938, while the Vicksburg formation was discovered later in 1949. The Frio produces both oil and natural gas while the Vicksburg only produces gas and condensate. Oil, gas and condensate ratios vary greatly between reservoirs. Drainage areas in the Vicksburg and Frio are small. Both produce in multiple intervals from depths ranging between 4,500 feet to 6,500 feet in the Frio and from 7,400 feet to 11,200 feet in the Vicksburg. Production to date from both reservoirs totals approximately 4 MMBbl of oil and 292 Bcf of natural gas and numerous wells remain to be drilled in each reservoir.

Midcontinent

On December 8, 2010, we completed an approximately $44.5 million purchase of certain North Texas assets from RWG Energy, Inc., a subsidiary of RAM Energy Resources, Inc. The assets acquired in the transaction include 143 gross (89.1 net) wells in Jack and Wise Counties, Texas, focused on the Barnett Shale and Bend Conglomerate trend in the Fort Worth Basin, with net proved reserves of approximately 5.9 MMBoe as of December 31, 2010 and an average working interest of 62.3% through the year ended December 31, 2010. The acquisition covers approximately 27,000 gross acres (6,500 net), all of which is held by production. For the month ended December 31, 2010, average daily net production from the acquired assets was approximately 841 Boe/d, including 2.2 MMcf of natural gas, 41 Bbl of oil and 437 Bbl of NGLs. We are the operator of the Boonesville Bend Conglomerate properties, which account for approximately 76.7% of the properties, based on producing wells at December 31, 2010, and EOG Resources, Inc. and Devon Energy

operate the deeper Barnett Shale properties. We have an average working interest of 34.21% with a corresponding average net revenue interest of 27.72% in the Barnett Shale and an average working interest of 72% with a corresponding net revenue interest of 52% in the Boonesville properties. We are currently accumulating leases in this trend.

The Fort Worth Basin is a gas prone region with multiple pay zones ranging in depth from 1,000 feet to 9,000 feet. The Fort Worth Basin has experienced a drilling boom in the last several years as natural gas prices increased along with advances in fracturing technology that have unlocked natural gas reserves from the Barnett Shale. The Barnett Shale is a thick blanket type formation covering the entire Basin. The natural gas reserves in place are significant; however, due to the extremely low permeability of the shale, it has been technically difficult to recover these reserves. Recent advances in hydraulic fracturing and horizontal well technology have enabled economic recovery of additional natural gas reserves in the Fort Worth Basin.

According to the U.S. Geological Survey, an estimated 26.7 trillion cubic feet of undiscovered natural gas, 98.5 MMBbl of undiscovered oil and 1.1 BBbl of undiscovered NGLs remain within the 54,000 square mile Bend Arch-Fort Worth Basin Province. According to the U.S. Geological Survey, more than 98%, or approximately 26.2 trillion cubic feet of this undiscovered natural gas, is contained in the Barnett Shale.

Over the last several years, we have developed a potential resource play in the Atoka Shale of Oklahoma. The Atoka Shale is an emerging horizontal non-conventional oil and gas play located in the Anadarko Basin in the panhandles of Oklahoma and Texas and is one of several non-conventional plays active in this area. The trend has been under development in Texas since 2006 when EOG Resources drilled a number of horizontal gas completions in a twenty-five mile fairway in the overall Atoka Shale (targeting the Novi Lime and Thirteen Fingers Shale intervals in the trend). Recently, the development has been extended north into Oklahoma where some companies have had success with several high rate oil completions in 2010. Vertical depth of these wells is 6,000 to 9,000 feet and the overall thickness in the prospective interval is approximately 200 feet. The Atoka Shale is a Pennsylvanian shale and lime section that has many characteristics similar to the Barnett and Eagle Ford Shales of Texas and the Bakken Shale of North Dakota and Montana. These attributes include high total organic content and hydrocarbon maturity with shale and lime reservoir rock.

As part of our activity in the Oklahoma portion of the play, we drilled two gross/net wells in 2010 as petrophysical evaluation wells. We sidetracked and completed one of the evaluation wells by September 1, 2011 to satisfy our obligations pursuant to an amended Drilling, Exploration and Development Agreement with Trueblood Resources, Inc. In addition, we drilled and completed two other horizontal wells outside of this Agreement during 2011 in the Midcontinent area. In the event we elect not to proceed with the drilling of additional wells within the Agreement, a liquidation payment to our partners, not to exceed $4.5 million, is required.

Markets and Customers

We sell our oil and natural gas under fixed or floating market contracts. Customers purchase all of our oil and natural gas at current market prices. The terms of the arrangements generally require customers to pay us within 30 days after the production month ends. As a result, if our customers were to default on their payment obligations to us, near-term earnings and cash flows would be adversely affected. However, due to the availability of other markets and pipeline connections, we do not believe that the loss of these customers, or any other single customer, would adversely affect our ability to market our production.

Our ability to market oil and natural gas from our wells depends upon numerous factors beyond our control, including:


	•	the extent of domestic production and imports of oil and natural gas;

	•	the proximity of our natural gas production to pipelines;

	•	the availability of capacity in such pipelines;

	•	the demand for oil and natural gas by utilities and other end users;


	•	the availability of alternative fuel sources;

	•	the effects of inclement weather;

	•	state and federal regulation of oil and natural gas production; and

	•	federal regulation of natural gas sold or transported in interstate commerce.

We cannot assure you that we will be able to market all of the oil or natural gas we produce or that favorable prices can be obtained for the oil and natural gas we produce. We do not currently maintain any commitments to deliver a fixed and determinable quantity of oil or natural gas in the near future under existing contracts or agreements.

In view of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we are unable to predict future oil and natural gas prices and demand or the overall effect such prices and demand will have on our business and results of operations. During 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues, with Enterprise Crude Oil LLC accounting for 11% and Shell Trading (US) Company accounting for 19%. During 2009, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 16%. During 2008, ten customers collectively accounted for 66% of our oil and natural gas revenues, with Plains Marketing LP accounting for 12% and Shell Trading (US) Company accounting for 17%. These percentages do not consider the effects of commodity hedges. We do not believe that the loss of any of our oil or natural gas purchasers would have a material adverse effect on our operations due to the availability of other potential purchasers. None of our agreements has fixed volume delivery requirements and we have not failed to meet any delivery obligation over the last three years.

Sales Volumes, Prices and Production Costs

The following table sets forth our sales volumes, the average prices we received before hedging, the average prices we received including hedging settlement gains (losses), the average prices we received including hedging settlements and unrealized gains (losses) and average production costs associated with our sale of oil and natural gas for the periods indicated. We account for our hedges usingmark-to-market accounting, which requires that we record both derivative settlements and unrealized gains (losses) in our consolidated statement of operations within a single income statement line item. We have elected to include both derivative settlements and unrealized gains (losses) within revenues.


	Year Ended December 31,
	2010		2009		2008

Sales volumes:
*Oil volumes (MBbls)*
Texas Gulf Coast		277		216		310
Southeast		496		611		843
South Texas		223		286		392
Midcontinent		15		0		0

Total oil		1,011		1,113		1,545
*Natural gas volumes (MMcf)*
Texas Gulf Coast		6,486		9,133		12,236
Southeast		2,799		3,398		4,279
South Texas		4,286		5,932		8,391
Midcontinent		86		49		—

Total natural gas		13,657		18,512		24,906
Total oil equivalent (MBoe)		3,287		4,198		5,696


	Year Ended December 31,
	2010		2009		2008

Average oil prices based on sales volumes:
Oil price (per Bbl)	$	73.40	$	52.60	$	92.42
Oil price including derivative settlement gains (losses) (per Bbl)	$	73.48	$	55.72	$	85.69
Average natural gas prices based on sales volumes:
Natural gas price (per Mcf)	$	4.39	$	3.79	$	8.73
Natural gas price including derivative settlement gains (losses) (per Mcf)	$	7.27	$	5.99	$	8.44
Average equivalent prices based on sales volumes:
Oil equivalent price (per Boe)	$	40.83	$	30.68	$	63.25
Oil equivalent price including derivative settlement gains (losses) (per Boe)	$	52.80	$	41.19	$	60.16
Oil equivalent price including derivative settlements and unrealized gains (losses) (per Boe)	$	47.81	$	36.78	$	72.08
Average production costs (per Boe) based on sales volumes:
Lease operating expenses (including costs for operating and maintenance and workover expense)	$	10.43	$	7.75	$	7.39
Taxes other than income	$	3.32	$	2.15	$	4.32

Oil and Gas Drilling Activity

The following table sets forth the wells drilled and completed by us during the periods indicated:


	2010(1)				2009				2008
	Gross		Net		Gross		Net		Gross		Net

Exploration:
Productive		4		2.1		0		0		33		22.7
Non-productive		2		1.5		1		0.5		10		6.4

Total		6		3.6		1		0.5		43		29.1

Development:
Productive		6		5.8		1		0.03		21		16.8
Non-productive		0		0		0		0		5		2.9

Total		6		5.8		1		0.03		26		19.7


(1)		Includes two evaluation wells drilled in the Atoka Shale along with a development well in the South Louisiana region. All three wells are budgeted for completion in 2011.

Productive Wells

The following table shows the number of producing wells we owned by location at December 31, 2010:


	Oil				Natural Gas
	Gross		Net		Gross		Net

Texas Gulf Coast		81		56.4		259		129.2
Southeast		113		76.5		121		29.1
South Texas		47		32.2		252		115.9
Midcontinent		44		31.4		72		40.3

Total		285		196.5		704		314.5

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage by location as of December 31, 2010:


	Leasehold Acreage
	Developed				Undeveloped
	Gross		Net		Gross		Net

Texas Gulf Coast		75,231		37,338		64,816		19,634
Southeast		75,841		18,351		5,382		3,275
South Texas		53,240		31,957		13,092		7,712
Midcontinent		28,280		7,780		30,220		30,220

Total		232,592		95,426		113,510		60,841

Undeveloped Acreage Expirations

The table below summarizes by year our undeveloped acreage scheduled to expire.


	Acres Expiring
Twelve Months Ending:	Gross		Net

December 31, 2011		12,359		8,192
December 31, 2012		1,809		1,761
December 31, 2013		1,435		1,434
December 31, 2014		—		—
December 31, 2015		—		—

Total		15,603		11,387

We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. As is customary in the oil and natural gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the primary term of such a lease. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and may allow additional acreage to expire in the future.

Title to Properties

We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and natural gas industry, subject to such exceptions which, in our

opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:


	•	royalties and other burdens and obligations, express or implied, under oil and gas leases;

	•	overriding royalties and other burdens created by us or our predecessors in title;

	•	a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;

	•	back-ins and reversionary interests existing under purchase agreements and leasehold assignments;

	•	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements, pooling, unitization and communitization agreements, declarations and orders; and

	•	easements, restrictions,rights-of-way and other matters that commonly affect property.

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for properties of the kind that we own.

Federal Regulations

Sales and Transportation of Natural Gas. Historically, the transportation and sales for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”) and Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated the price for all “first sales” of natural gas. Thus, all of our sales of natural gas may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. Since 1985, FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. We cannot predict what further action FERC will take on these matters. Some of FERC’s more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that FERC’s actions will have a materially different effect on us as compared to other natural gas producers, gatherers and marketers with which we compete.

The Outer Continental Shelf Lands Act (the “OCSLA”) requires that all pipelines operating on or across the Outer Continental Shelf provide open-access, non-discriminatory service. There are currently no regulations implemented by FERC under its OCSLA authority on gatherers and other entities outside the reach of its NGA jurisdiction. Therefore, we do not believe that any FERC or BOEMRE action taken under OCSLA will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

Our natural gas sales are generally made at the prevailing market price at the time of sale. Therefore, even though we sell significant volumes to major purchasers, we believe that other purchasers would be willing to buy our natural gas at comparable market prices.

Natural gas continues to supply a significant portion of North America’s energy needs and we believe the importance of natural gas in meeting this energy need will continue. The impact of the ongoing economic downturn on natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue.

On August 8, 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. This comprehensive act contains many provisions that will encourage oil and natural gas exploration and development in the United States. The 2005 EPA directs FERC, BOEMRE and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA to make it

unlawful for “any entity,” including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. On January 20, 2006, FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. Therefore the rules reflect a significant expansion of FERC’s enforcement authority. We do not anticipate that these rules will affect us any differently than other producers of natural gas.

Sales and Transportation of Crude Oil. Our sales of crude oil, condensate and NGLs are not currently regulated, and are subject only to applicable contract provisions negotiated by us and out counterparties. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.

The regulation of pipelines that transport oil, condensate and NGLs is generally less restrictive than FERC’s regulation of gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate and NGLs are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of FERC under the ICA, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus 1%. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through acost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline.

Federal Offshore Leases. We have an ownership interest in facilities on the Outer Continental Shelf located on federal oil and gas leases, which are administered by BOEMRE pursuant to the OCSLA. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed BOEMRE regulations and orders that are subject to interpretation and change by BOEMRE.

For offshore operations, lessees must obtain BOEMRE approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the EPA, lessees must obtain a permit from BOEMRE prior to the commencement of drilling. In 2010, BOEMRE adopted changes to its regulations to impose a variety of new measures intended to help prevent a disaster similar to theDeepwater Horizonincident in the future. Offshore operators, including those operating in deepwater, outer continental shelf waters and shallow waters, where we have operations, must now comply with strict new safety and operating requirements. For example, before being allowed to resume drilling in deepwater, outer continental shelf operators must certify compliance with all applicable operating regulations found in 30 C.F.R. Part 250, including those rules recently placed into effect, such as rules relating to well casing and cementing, blowout preventers, safety certification, emergency response, and worker training. Operators of all offshore waters also must demonstrate the availability of adequate spill response and blowout containment resources.

To cover the various obligations of lessees on the Outer Continental Shelf, BOEMRE generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. Under some circumstances, BOEMRE may require operations on federal leases to be suspended or terminated. We have a non-operating interest in nine offshore fields in the Outer Continental Shelf off the coast of Louisiana which are subject to BOEMRE jurisdiction. Any such suspension or termination of operations by BOEMRE could materially and adversely affect our financial condition, cash flows and results of operations.

The Office of Natural Resources Revenue (the “ONRR”) in the U.S. Department of the Interior administers the collection of royalties under the terms of the OCSLA and the oil and gas leases issued under the OCSLA. The amount of royalties due is based upon the terms of the oil and gas leases as well as of the regulations promulgated by ONRR. ONRR regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases provide that ONRR will collect royalties based upon the market value of oil produced from federal leases. On September 30, 2010, the Royalty in Kind program, which accepted oil and gas in lieu of cash as royalty payments, was terminated. These regulations are amended from time to time, and the amendments can affect the amount of royalties that we are obligated to pay to BOEMRE. However, we do not believe that these regulations or any future amendments will affect our business in a way that materially differs from the way it affects other oil and gas producers, gatherers and marketers.

On May 19, 2010, the U.S. Department of the Interior announced it would reorganize the former Minerals Management Service by dividing its offshore oil and gas responsibilities among three separate agencies. Shortly thereafter, on June 18, 2010, the Minerals Management Service was renamed the Bureau of Ocean Energy Management, Regulation and Enforcement. On October 1, 2010, the first phase of reorganization took place when the revenue collection arm of the former Mineral Management Service became the Office of Natural Resources Revenue. On January 19, 2011, the U.S. Department of the Interior announced the structures and responsibilities of the two remaining agencies, with the reorganization of BOEMRE into these agencies to be completed in 2011. Interior will create the Bureau of Ocean Energy Management, which will have responsibility for leasing and environmental studies, and the Bureau of Safety and Environmental Enforcement, which will have responsibility for field operations, including inspections, regulatory compliance, and oil spill response. Once the reorganization is completed, the BOEMRE will cease to exist. At this time, we do not know the impact that this reorganization may have on our business.

Federal, State or American Indian Leases. Operations on federal, state or American Indian onshore oil and gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, certainon-site security regulations and must also obtain permits issued by the Bureau of Land Management (the “BLM”) or other appropriate federal or state agencies.

The Mineral Leasing Act of 1920 (the “Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s lease can be cancelled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous federal onshore oil and gas leases. It is possible that holders of our equity interests may be citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act. If any of our equity holders is deemed to be a citizen of a non-reciprocal country, then our interests in federal onshore oil and gas leases may be cancelled. Any such cancellation could have a material adverse effect on our financial condition, cash flows and results of operations.

State Regulations

Most states regulate the production and sale of oil and natural gas, including:


	•	requirements for obtaining drilling permits;


	•	the method of developing new fields;

	•	the spacing and operation of wells;

	•	the prevention of waste of oil and gas resources; and

	•	the plugging and abandonment of wells.

The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both.

We may enter into agreements relating to the construction or operation of a pipeline system for the transportation of natural gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the jurisdiction of such state’s administrative authority charged with the responsibility of regulating intrastate pipelines. In such event, the rates that we could charge for gas, the transportation of gas, and the construction and operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative authority.

Legislative Proposals

In the past, governments at both the federal and state level have been very active in the area of natural gas regulation. New legislative proposals in the United States Congress and the various state legislatures, if enacted, could significantly affect the petroleum industry. At the present time it is impossible to predict what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, such proposals might have on our operations.

Environmental Regulations

General. Our activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, regulations and rules regulating the release of materials in the environment or otherwise relating to the protection of human health, safety and the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

Our activities with respect to exploration and production of oil and natural gas, including the drilling of wells, are subject to stringent environmental regulation by state and federal authorities, including the EPA. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities are inherent in oil and gas production operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover it is possible that other developments, such as spills or other unanticipated releases, stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production, would result in substantial costs and liabilities to us.

Solid and Hazardous Waste. We own or lease numerous properties that have been used for production of oil and gas for many years. Although we have utilized operating and disposal practices standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed of or released on or under these properties. In addition, many of these properties have been operated by third parties. We had no control over the treatment of hydrocarbons or other solid wastes by such third parties and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have become more strict over time. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future contamination.

We generate wastes, including hazardous wastes, which are subject to regulation under the federal Resource Conservation and Recovery Act (the “RCRA”) and state statutes. The EPA has limited the disposal options for certain hazardous wastes. Furthermore, it is possible that certain wastes generated by our oil and gas operations that are currently exempt from regulation as “hazardous wastes” may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes, and therefore may become subject to more rigorous and costly disposal requirements.

Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release or threatened release of a “hazardous substance” into the environment. These persons include the owner and operator of a site and persons that disposed or arranged for the disposal of hazardous substances at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible persons the costs of such action. Certain state statutes impose similar liability. Neither we nor, to our knowledge, our predecessors have been designated as a potentially responsible party by the EPA or by a state under CERCLA or by any state under a similar state law.

Oil Pollution Act. The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA.

The OPA currently establishes a liability limit for onshore facilities of $350 million and for offshore facilities of all removal costs plus $75 million, and lesser limits for some vessels depending upon their size. The regulations promulgated under OPA impose proof of financial responsibility requirements that can be satisfied through insurance, guarantee, indemnity, surety bond, letter of credit, qualification as a self-insurer, or a combination thereof. The amount of financial responsibility required depends upon a variety of factors including the type of facility or vessel, its size, storage capacity, oil throughput, proximity to sensitive areas, type of oil handled, history of discharges and other factors. We believe we currently have established adequate financial responsibility.

While financial responsibility requirements under OPA may be amended to impose additional costs on us, the impact of any change in these requirements should not be any more burdensome to us than to other similarly situated companies.

Clean Water Act. The Clean Water Act (the “CWA”) regulates the discharge of pollutants into waters of the United States and adjoining shorelines, including wetlands, and requires a permit for the discharge of pollutants, including petroleum, into such waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain facilities that store or otherwise handle oil are required to prepare and implement Spill Prevention, Control and Countermeasure Plans and Facility Response Plans relating to the possible discharge of oil to surface waters. We are required to prepare and comply with such plans and to obtain and comply with discharge permits. We believe we are in substantial compliance with these requirements and that any noncompliance would not have a material adverse effect on us. The CWA also prohibits spills of oil and hazardous substances to waters of the United States in excess of levels set by regulations and imposes liability in the event of a spill. State laws further provide civil and criminal penalties and liabilities for spills to both surface and groundwater and require permits that set limits on discharges to such waters.

Safe Drinking Water Act. The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control Program, authorized by the SDWA. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In Oklahoma, Louisiana and Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to comply with our permits could subject us to civiland/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits and authorizations.

Our operations employ hydrofracturing techniques to stimulate natural gas production from unconventional geological formations, which entails the injection of pressurized fracturing fluids. The 2005 EPA amended the Underground Injection Control (“UIC”) provisions of the SDWA to exclude hydraulic fracturing from the definition of “underground injection” under certain circumstances. However, the repeal of this exclusion has been advocated by certain organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress and similar legislation could be introduced in the current of future sessions of Congress.

Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the initial results of which are anticipated to be available by late 2012. Last year, a committee of the U.S. House of Representatives commenced investigations into hydraulic fracturing practices. The U.S. Department of the Interior has announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production. For example, New York has imposed a de facto moratorium on the issuance of permits for certain hydraulic fracturing practices until an environmental review and potential new regulations are finalized. Significant controversy has surrounded drilling operations in Pennsylvania. In Arkansas, concern over a possible correlation between a swarm of earthquakes and use of injection wells for disposal of hydraulic fracturing waste in the Fayetteville Shale has led to an emergency request from the Arkansas Oil & Gas Commission to stop injection activities in a limited area and a six-month moratorium on new injections wells in the area. In addition, Wyoming has adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemicals used in the fracturing process, and Colorado requires recordkeeping and disclosure of fracturing fluid constituents to officials in certain circumstances.

Additionally, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board released a report on August 11, 2011, proposing recommendations to reduce the potential environmental impacts from shale gas production. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic fracturing process. Furthermore, in July 2011, the EPA proposed several new emissions standards to reduce VOC emissions from several types of processes and equipment used in the oil and natural gas industry, including a 95 percent reduction in VOCs emitted during the construction or modification of hydraulically-fractured wells. Additionally, on August 23, 2011, the EPA published a proposed rule in the Federal Register that would establish new air emission controls for oil and natural gas production and natural gas processing operations. The EPA is currently receiving public comment and recently conducted public hearings regarding the proposed rules and must take final action on them by February 28, 2012.

difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations orclean-ups or in the incurrence of other unexpected material costs or liabilities.

Air Emissions. Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits may be resolved by payment of monetary finesand/or correction of any identified deficiencies. Alternatively, regulatory agencies could impose civil and criminal liability for non-compliance. Any such regulatory agency could require us to forego construction or operation of certain air emission sources. We believe that we are in substantial compliance with air pollution control requirements and that, if a particular permit application were denied, we would have enough permitted or permittable capacity to continue our operations without a material adverse effect on any particular producing field.

Climate Change. According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17% compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

In the U.S., legislative and regulatory initiatives are underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act (the “CAA”) definition of an “air pollutant,” and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The EPA has also promulgated rules requiring large sources to report their GHG emissions. On September 22, 2009, EPA finalized a GHG reporting rule that requires large sources of greenhouse gas emissions to monitor, maintain records on, and annually report their GHG emissions. On November 8, 2010, the EPA also issued GHG monitoring and reporting regulations for petroleum and natural gas facilities, including offshore petroleum and natural gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year which went into effect on December 30, 2010. The rule requires reporting of GHG emissions by regulated facilities to EPA by March 2012 for emissions during 2011 and annually thereafter. In 2010, EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and newer modification projects subject to permitting requirements for GHG emissions under the CAA. Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. In addition to these regulatory developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Due to their location, our operations in the Gulf of Mexico are vulnerable to operational and structural damages resulting from

hurricanes and other severe weather systems and our insurance may not cover all associated losses. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Coastal Coordination. There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act (the “CZMA”) was passed to preserve and, where possible, restore the natural resources of the coastal zone of the United States. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development.

The Louisiana Coastal Zone Management Program (the “LCZMP”) was established to protect, develop and, where feasible, restore and enhance coastal resources of the State of Louisiana. Under the LCZMP, coastal use permits are required for certain activities, even if the activity only partially infringes on the coastal zone. Among other things, projects involving use of state lands and water bottoms, dredge or fill activities that intersect with more than one body of water, mineral activities, including the exploration and production of oil and gas, and pipelines for the gathering, transportation or transmission of oil, gas and other minerals require such permits. General permits, which entail a reduced administrative burden, are available for a number of routine oil and gas activities. The LCZMP and its requirement to obtain coastal use permits may result in our having to satisfy additional permitting requirements and could potentially cause project schedule constraints.

The Texas Coastal Coordination Act (the “CCA”) provides for coordination among local and state authorities to protect coastal resources through regulating land use, water and coastal development and establishes the Texas Coastal Management Program (the “CMP”) that applies in the 19 Texas counties that border the Gulf of Mexico and its tidal bays. The CCA provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the CMP. This review process may affect agency permitting and may add a further regulatory layer to some of our projects.

OSHA. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. OSHA hazard communication standards, the EPA communityright-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organizeand/or disclose information about hazardous materials used or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens.

Competition

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, and obtaining purchasers and transporters for the oil and natural gas we produce. There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislationand/or regulation considered from time to time by the government of the United States and various state governments; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effect upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

Operating Hazards and Uninsured Risks

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts,

not only from dry wells, but also from wells that are productive, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including unexpected drilling conditions, low oil and natural gas prices, title problems, pressure or irregularities in formations, delays by project participants, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements, shortages or delays in the delivery of equipment and services and increases in the cost for such equipment and services. Our future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, mechanical failures, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and those of others. We maintain insurance against some but not all of the risks described above. In particular, the insurance we maintain does not cover claims relating to failure of title to oil and natural gas leases, loss of surface equipment at well locations, trespass or surface damage attributable to seismic operations, business interruption, loss of revenues due to low commodity prices or loss of revenues due to well failure. Furthermore, in certain circumstances in which insurance is available, we may not purchase it. The occurrence of an event that is not covered, or not fully covered by insurance, could have a material adverse effect on our business, financial condition, results of operations and cash flows in the period such event may occur.

Legal Proceedings

There are currently various suits and claims pending against us that have arisen in the ordinary course of our business, including contract disputes, personal injury and property damage claims and title disputes. Management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material effect on our consolidated financial position, results of operations or cash flow. We records reserve for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Employees

As of December 31, 2010, we had 115 employees. We have a land department staff that includes four landmen, an exploration staff that includes three geologists, one geophysicist, one computer applications specialists and one geological technician and an operations staff that includes seven engineers. We believe that our relationships with our employees are satisfactory.

Offices

We currently lease and sublease, through Hydro Gulf Of Mexico, L.L.C., 49,230 square feet of executive and corporate office space located at 1301 McKinney in Houston, Texas. Rent related to this office space for the twelve months ended December 31, 2010 was approximately $2.1 million. The lease term extends to August 31, 2017.

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MANAGEMENT

Officers and Directors

The following is a list of our executive officers and directors as of November 14, 2011. Our directors hold office until the expiration of their term or until their successors are duly elected and qualified.


Name	Age		Position

James G. Ivey		60	President, Chief Executive Officer and Director
Gary Mabie		68	Chief Operating Officer
Marshall Munsell		54	Senior Vice President of Business Development
Tom Langford		56	Senior Vice President and General Counsel
Robert LaRocque		56	Vice President of Finance and Treasurer
Lloyd Armstrong		53	Vice President of Production Logistics
Mark Stirl		56	Vice President and Controller
Jonathan Ginns		46	Director
Mo Bawa		35	Director
Thomas J. Hauser		31	Director
Adam Cohn		40	Director

James G. Iveyhas served as our President and Chief Executive Officer, and has served on our board of directors, since January 2011. Prior to this he served as Executive Vice President and Chief Financial Officer from 2009 through 2010. Prior to joining us, Mr. Ivey served as Executive Vice President and Chief Financial Officer of Cobalt International Energy, L.P. from 2006 through 2008, Chief Financial Officer of MarkWest Hydrocarbon, Inc. from 2004 to 2006, and as Treasurer and Acting Chief Financial Officer of The Williams Company from 1995 through 2004, and as Treasurer for Tenneco Gas and Arkla, Inc. from 1989 through 1994. Mr. Ivey began his career as an engineer, first with Fluor Corp. and later with Conoco, Inc. He earned his undergraduate degree from Texas A&M University and his MBA from the University of Houston. He is also a graduate of the Army Command and General Staff College and the Duke University Advanced Management Program. Mr. Ivey has served on the Board of Directors of Milagro Exploration since 2011. Mr. Ivey also serves on the boards of MachGen, LLC, an operator of gas-fired generation plants, and National Energy & Gas Transmission, Inc.

Gary Mabiehas served as our Chief Operating Officer since February 2010. Prior to joining us, Mr. Mabie worked as President for GM Oil & Gas Company, an industry provider of consulting services, Vice President of Operations at Comet Ridge Resources from 2006 to 2009, President of CDX West, a subsidiary of CDX Gas, LLC, from 2005 to 2006, President and Chief Operating Officer of SunCoast Energy Corporation from 2000 to 2005, General Manager and Senior Vice President of Onshore of Pennzoil/PennzEnergy from 1997 to 1999, and Vice President of Exploration and Production for Hunt Petroleum from 1990 to 1997. Mr. Mabie served in various management positions with Tenneco Oil, E&P with the last position being Operations Manager of the International Division. Mr. Mabie began his career as a petroleum engineer with Gulf Oil Corporation. He graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering.

Marshall Munsellis one of our original founders and as our Senior Vice President of Business Development has been responsible for our Land and Business Development departments since our formation in 2005. Prior to joining us, Mr. Munsell worked for Mission Resources Corporation as Senior Vice President of Land and Land Administration from 2002 to 2005, and has served in various management and staff roles with DDD Energy, Presidio Oil Company and Sun Oil Company. Mr. Munsell is a Certified Professional Landman and earned his Bachelor’s degree in Petroleum Land Management from the University of Texas.

Tom Langfordis one of our original founders and is our Senior Vice President and General Counsel responsible for our Legal, Environmental and Human Resources departments since our formation in 2005. Prior to joining us, Mr. Langford worked as Senior Vice President and General Counsel for Mission Resources

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Corporation from 2004 to 2005, and Vice President and General Counsel of El Paso Production Company from 1999 to 2004. Mr. Langford earned his BA from Stephen F. Austin University and graduated from South Texas College of Law.

Robert LaRocquehas served as our Vice President of Finance and Treasurer since October 2010. Prior to joining us, Mr. LaRocque served as a Managing Director for Credit Lyonnais from 1997 to 2003, Vice President of Corporate Development for Aquila Energy from 1995 to 1997 and Director of International Finance at Tenneco Gas. Mr. LaRocque earned his undergraduate degree from Queen’s University and his MBA from Dalhousie University.

Lloyd Armstronghas served as our Vice President of Production Logistics since January 2008. Prior to joining us, Mr. Armstrong served as Vice President of Operational Accounting for Goodrich Petroleum Corporation from August 2005 until December 2007, Vice President of Revenue Administration for Mission Resources Corporation from November 2002 to July 2005 and as Director of Operational Accounting for El Paso Production Company from 1999 to 2002. Mr. Armstrong has also served as Accounting Manager for El Paso Field Services and as Project Manager of a gas plant accounting system implementation for Andersen Consulting from 1997 to 1998. Mr. Armstrong began his career at Amerada Hess Corporation where he held several accounting positions from 1980 to 1997. Mr. Armstrong earned his BS in Accounting and Business Administration from Northeastern State University in Oklahoma.

Mark Stirlhas served as our Vice President and Controller since December 2007. Prior to joining us, Mr. Stirl served as the Vice President and Controller of Peoples Energy Production Company from 2006 to 2007. He also held various accounting and finance positions at BHP Billiton from 2004 to 2006, worked for Dunhill Resources as their Controller during 2003, and worked for CMS Oil and Gas as their Vice President and Controller 1997 to 2002. Mr. Stirl worked for Sonat Exploration Company from 1980 through 1997 in various accounting and financial functions, and as their Controller the last seven years of his service. Mr. Stirl began his career in public accounting working for Melton and Melton, CPAs. He received both a BSBA degree in Accounting and a MBA degree in Finance from the University of Houston.

Jonathan Ginnsis a Founder and Managing Partner of ACON Investments and has served on our board of directors since 2007. Founded in 1996, ACON is an international private equity investment firm managing capital through varied investment funds and special purpose partnerships. Prior to founding ACON, he was a Senior Investment Officer at the GEF Funds Group. Previously, Mr. Ginns was a Management Consultant at Booz Allen & Hamilton. Mr. Ginns received an MBA from the Harvard Business School, and a BA from Brandeis University. He also serves on the Boards of Directors of Chroma Oil & Gas, Northern Tier Energy and Signal International.

Mo Bawais a Principal of ACON Investments and has served on our board of directors since 2007. He is responsible for sourcing, evaluating, executing and monitoring transactions principally in the energy sector for ACON. Previously, he was an Associate with Constellation Commodities Group where he was responsible for origination, structuring, evaluation, and negotiation of the firm’s principal investments. Mr. Bawa has also held corporate finance and principal investing positions with Houlihan Lokey Howard & Zukin, Enron Capital & Trade Resources, and Banc of America Securities. Mr. Bawa holds a B.A. in Economics, Management and Public Policy from Rice University and MBA from The Anderson School at UCLA. He also serves on the Boards of Directors of Chroma Oil & Gas and Signal International.

Thomas J. Hauseris a Director of Guggenheim Partners, LLC and has served on our board of directors since April 11, 2011. Guggenheim is an asset management firm with over $120 billion of assets under management. Mr. Hauser joined Guggenheim in 2002 as an analyst on the leveraged credit investing team. During his tenure at Guggenheim, he has covered multiple industries including gaming, leisure, transportation, utilities, energy and real estate. He currently leads an industry team that focuses on investing across the capital structure in the energy, power and transportation sectors. Mr. Hauser earned his Bachelor of Science degree in Finance from St. John’s University and is a member of the Association for Corporate Growth.

Adam Cohnis a Principal at Knowledge Universe Limited, LLC where he has worked since 2000 and has served on our board of directors since 2007, as a representative of West Coast Energy Partners. Prior to

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Knowledge Universe, Mr. Cohn worked at Whitney & Co., a private equity firm. Prior to Whitney & Co., Mr. Cohn was an investment banker in the Financial Sponsors Group at Bankers Trust Company and Deutsche Bank. He has a Bachelor’s Degree in Business from Skidmore College and a MBA from Columbia University. He also serves on the boards of Knowledge Learning Corporation, Busy Bees Holdings Limited, and Embanet-Compass Knowledge Group Inc.

Board of Directors

Our board of directors is composed of five members, each of whom is elected annually by our stockholders. Under the Stockholders’ Agreement dated January 13, 2010, as subsequently amended (the “Stockholders’ Agreement”), which is effective for so long as we are a subsidiary of our parent company, Milagro Holdings, LLC (“Holdings”), holders of our Series A preferred stock have the right to appoint four of the five members of our board of directors.

Currently, we do not have any board committees, including an audit, compensation or corporate governance and nominating committee, and our full board performs the functions typically designated to these committees. In connection with the registration of the notes with the SEC, we intend to establish an audit committee to, among other things, review our external financial reporting, engage our external auditors and oversee our internal audit activities and procedures and the adequacy of our internal accounting controls. Further, we intend to adopt a code of ethics for our directors, officers and employees, as well as corporate governance guidelines.

Compensation Information

Compensation Discussion and Analysis

General

The following discussion describes and analyzes our compensation for our named executive officers for 2010, which include our principal executive officer, principal financial officer, and the three most highly compensated executive officers other than the principal executive and principal financial officers as set forth in the “Summary Compensation Table” below, or our “named executive officers.” On February 9, 2010, Mr. Robert L. Cavnar, our then President and Chief Executive Officer, resigned. Effective that date, Mr. James G. Ivey, our then Chief Financial Officer, also became our principal executive officer. Effective January 1, 2011, he was named our President and Chief Executive Officer. The compensation summaries below reflect that change.

We are an independent oil and gas company primarily engaged in the acquisition, exploitation, development and production of oil and natural gas reserves. We were formed as a limited liability company in 2005 with a focus on properties located onshore in the U.S. Gulf Coast. In November 2007, we acquired the Gulf Coast assets of Petrohawk Energy Corporation for approximately $825.0 million. The acquisition included properties primarily in the onshore Gulf Coast region in Texas, Louisiana and Mississippi. Since this acquisition, we have acquired additional proved producing reserves that we believe have upside potential, implemented an active drilling, workover and recompletion program and expanded our geographic diversity by moving into the Midcontinent region. During 2010, we modified our business strategy by moving away from a focus on exploration to a more balanced approach of acquisition, exploitation, development and lower risk exploration. While several of our founders continue to serve us in key capacities, we have added a number of executive officers since our formation, including our principal executive officer and principal financial officer. These additional officers have joined us at various times from 2005 through 2010.

Compensation Philosophy and Objectives and Elements of Compensation

Our intent and philosophy in designing compensation packages at the time of hiring new executives has been based in part on providing compensation that we thought was sufficient to enable us to attract the talent necessary to further develop our business while at the same time being prudent in the management of our cash and equity. Compensation of our executive officers after the initial period following their hiring has been

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influenced by the amounts of compensation that we initially agreed to pay them as well as by our evaluation of their subsequent performance, changes in their levels of responsibility, prevailing market conditions, our financial condition and prospects.

We have compensated our executives with a combination of salaries, cash bonuses and awards under our profits interest plan, or the Plan. We also believe that it provides an appropriate blend of compensation to retain our executives, reward them for performance in the short term and induce them to contribute to the creation of value in the company over the long term.

We view the different components of our executive compensation as distinct. We believe we must maintain a sufficiently competitive salary to position us to attract the executives that we need and that it is important that our executives perceive that over time they will continue to have the opportunity to earn a salary that they regard as competitive.

The ability to earn cash bonuses should incentivize executives to effectively pursue goals established by our Board of Directors and should be regarded by executives as appropriately rewarding effective performance against these goals. In the past we have sought to establish target bonus levels and performance goals for executives at the beginning of the year to help ensure that our performance goals, and the bonus attainable for achieving these goals, were well understood by executives.

The Plan is a profits interest incentive program in which we issue to employees profits interests in a limited partnership which owns Class C membership interests in our parent company, Holdings, which is a holding company and the holder of record of 100% of our issued and outstanding common stock. The participants’ profits interests represent the right to receive a percentage of the distributions made by Holdings when such distributions exceed specified internal rate of return thresholds. This Plan is designed to recognize the need for current profitability as well as building long-term value. In addition, the Plan is designed to aid us in retaining the services of key executives and employees by requiring vesting conditions on each grant, which provide that the participant would forfeit the unvested portion of the grant upon their termination of service with us. Vested units may also be forfeited in certain circumstances, including certain termination events, a personal bankruptcy or other specified conditions.

We have used awards under the Plan as the form of equity award for executives. The size of the award is determined based on the executive’s position with us and takes into consideration the executive’s base salary and other compensation as well as an analysis of the grant and compensation practices of other companies in our industry. Typically, our Plan awards to executive officers vest and become exercisable over five years. Our Board of Directors believes that these awards align the interests of our named executive officers with those of the stockholders, because they create the incentive to build stockholder value over the long-term. In addition, our Board of Directors believes the vesting provision of our equity awards improves our ability to retain our executives.

Compensation Decision Process

Since our formation, our Board of Directors has overseen the compensation of our executive officers and our executive compensation programs and initiatives. While we have had an Executive Compensation Committee which administers the Plan, the ultimate compensation decisions have been made by the full Board of Directors. The Board of Directors has also sought, and received, significant input from our principal executive officer with regard to the performance and compensation of executives other than himself.

Certain of our directors have significant experience with privately held private equity-backed companies such as ours and the executive compensation practices of such companies, and have applied this knowledge and experience to their judgments regarding our compensation decisions.

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2010 Compensation

Salary

The salaries of our named executive officers are reflected below and were determined by our Board of Directors. Compensation is reviewed annually against salaries being paid by other companies of a like size and scope.

Bonus

Bonus compensation is based on the discretion of our Board of Directors and upon achievement of performance objectives established by our Board of Directors annually. Criteria making up the bonus objectives in 2010 included a weighting of the following criteria: annual EBITDA, total production expressed on a per Bcfe basis, reserve replacement, lease operating expense expressed on a per Mcfe basis and gross general and administrative expenses. These criteria were chosen, in the case of EBITDA, lease operating expense and gross general and administrative expense, as the most significant measure of our cash flows and profitability, and, in the case of total production and reserve replacement, as the most significant measures of success during the year in our business. Each category has an annual threshold of 75% of the approved budget, a target of 100% of the approved budget and a stretch goal of 125% of the approved budget. We believe that all goals, while intentionally presenting a significant challenge, are realistic and achievable by our executives in most instances, if they perform their duties with the degree of care and diligence that we expect of them.

Target, threshold and stretch criteria in the table below were established by our Board of Directors and are the same for each of the named executive officers.


													Bonus
	Threshold			Target			Stretch			Results			Achievement			Weighting			Contribution

EBITDA (in millions)	$	75.0		$	99.0		$	112.0		$	107.7			117	%		30	%		35	%
Total Production (in Bcfe)		19.5			21.0			25.0			19.7			79	%		30	%		24	%
Reserve Replacement		90	%		100	%		110	%		150	%		120	%		30	%		36	%
Lease operating expense (per Mcfe)	$	1.87		$	1.55		$	1.25		$	1.80			80	%		5	%		4	%
Gross general & administrative expense (in million)	$	25.0		$	21.0		$	18.0		$	19.4			113	%		5	%		6	%
							Total weighted-average bonus													104	%

Equity Compensation

On February 9, 2010, in connection with his departure from serving as our Chief Executive Officer, Mr. Cavnar resigned as general partner of the limited partnership which maintains the Class C membership interests in the Plan. Upon such departure, such general partner interests that were then vested converted to vested limited partnership units in the Plan. In addition, effective the date, Mr. Langford and Mr. Munsell were appointed as co-general partners of the limited partnership were issued general partner interests.

There were no limited partnership awards made under the Plan to our named executive officers in 2010.

Severance and Change of Control Agreements

We have entered into employment letters with each of our named executive officers providing for certain payments upon termination of their employment with us without cause and upon termination without cause following a change of control. These payments, and the definition for this purpose of change of control, are described in detail below under “Potential Payments upon Termination and Change in Control.”

We believe that these agreements appropriately balance our needs to offer a competitive level of severance protection to our executives and to induce our executives to remain in our employ through the potentially disruptive conditions that may exist around the time of a change in control, while not unduly rewarding executives for a termination of their employment. We note that our change in control terms include

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so-called “double trigger” provisions, so that the executive is not entitled to the severance payment by the mere occurrence of the change in control. We believe this feature will be an incentive to the executive to remain in our employ if such continuation is required by our partner in a change in control transaction. We also believe that it is appropriate that our executives’ equity awards be treated, in the event of a change of control, like those of other employees and not accelerated if the executive’s employment continues following the change in control event.

Other Executive Benefits and Perquisites

We provide the following benefits to our executive officers on the same basis as other eligible employees:


	•	health insurance;

	•	vacation, personal holidays and sick days;

	•	life insurance and personal accident insurance;

	•	short-term and long-term disability; and

	•	a 401(k) plan.

We believe these benefits are generally consistent with those offered by other companies with which we compete for executive talent.

Other Compensation Practices and Policies

Policy regarding the timing of equity awards. As a privately-owned company, there is no market for our capital stock. Accordingly, in fiscal year 2010, we had no program, plan or practice pertaining to the timing of stock option grants to executive officers coinciding with the release of material non-public information. We do not, as of yet, have any plans to implement such a program, plan or practice after becoming a reporting company.

Policy regarding restatements. We do not have a formal policy regarding adjustment or recovery of awards or payments if the relevant performance measures upon which they are based are restated or otherwise adjusted in a manner that would reduce the size of the award or payment. Under those circumstances, our Board of Directors or a committee thereof, would evaluate whether adjustments or recoveries of awards were appropriate based upon the facts and circumstances surrounding the restatement.

Stock Ownership Policies. We have not established stock ownership or similar guidelines with regards to our executive officers. All of our executive officers currently have an indirect equity interest in our company through their Plan awards and we believe that they regard the potential returns from these interests as a significant element of their potential compensation for services to us.

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Summary Compensation Table

The following table summarizes the compensation earned by our principal executive officer, principal financial officer and each of our three other most highly compensated executive officers during the year ended December 31, 2010. The table also includes one former executive officer for whom disclosure would have been required but for the fact that he was not serving as an executive officer at the end of the fiscal year ended December 31, 2010. In this prospectus, we refer to these officers as our named executive officers.

2010 Summary Compensation Table


											Non-
											Equity		Nonqualified
											Incentive		Deferred
							Stock		Option		Plan		Compensation		All Other
			Salary		Bonus		Awards		Awards		Compensation		Earnings		Compensation			Total
Name and Principal Position	Year		($)		($)		($)		($)		($)		($)		($)			($)

Robert L. Cavnar(1)		2010		44,102		—		—		—		—		—		376,741	(2)		420,843
Former President and
Chief Executive Officer
James G. Ivey		2010		248,750		235,000		—		—		—		—		—			483,750
Chief Financial Officer(3)
Gary Mabie		2010		220,000		—		—		—		—		—		82,431	(4)		302,431
Chief Operating Officer
Marshall L. Munsell		2010		235,000		110,000		—		—		—		—		—			345,000
Senior Vice President of
Business Development
Thomas C. Langford		2010		235,000		110,000		—		—		—		—		—			345,000
Senior Vice President
and General Counsel


(1)		Effective February 9, 2010, Mr. Cavnar ceased employment with us based on a mutual decision with our Board of Directors. In connection with the departure, he entered into a Separation Agreement and Release with us (the “Release”), whereby (i) his employment agreement with us was terminated, subject to the continued enforcement of the provisions relating to non-competition and confidentiality; (ii) he entered into a mutual release; (iii) he was granted reimbursement of his payment of his COBRA premiums through (a) the eighteen month anniversary of the termination or (b) until he is eligible to participate in the health insurance plan of another employer, whichever is sooner; and (iv) he was paid his base salary of $33,333 per month for twelve months following his departure.

(2)		Mr. Ivey served as our principal financial officer during 2010 and, on upon the departure of Mr. Cavnar, also served as our principal executive officer during the remainder of 2010. Effective January 1, 2011, he was named our President and Chief Executive Officer.

(3)		Represents approximately $362,984 of severance and approximately $13,757 of health care reimbursement costs, each paid as a result of Mr. Cavnar’s departure.

(4)		Represents reimbursement of housing and commuting expenses.

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Grants of Plan-Based Awards Table

The following table shows information regarding grants of equity awards to our named executive officers during the year ended December 31, 2010.

2010 GRANTS OF PLAN-BASED AWARDS TABLE


															All							Grant
															Other			All Other				Date
															Stock			Option				Fair
															Awards:			Awards:		Exercise		Value of
															Number of			Number of		or Base		Stock
			Estimated Future Payouts Under						Estimated Future Payouts Under						Shares of			Securities		Price of		and
			Non-Equity Incentive Plan Awards						Equity Incentive Plan Awards						Stock or			Underlying		Option		Option
	Grant		Threshold		Target		Maximum		Threshold		Target		Maximum		Units			Options		Awards		Awards
Name	Date		($)		($)		($)		($)		($)		($)		(#)(1)			(#)		($/Sh)		($)(2)

Robert L. Cavnar		—		—		—		—		—		—		—		—			—		—		—
James G. Ivey		—		—		—		—		—		—		—		—			—		—		—
Gary Mabie		—		—		—		—		—		—		—		—			—		—		—
Marshall L. Munsell		2/9/10		—		—		—		—		—		—		120,420	(1)		—		—		—
Thomas C. Langford		2/9/10		—		—		—		—		—		—		120,420	(1)		—		—		—


(1)		Represents general partner interests in the limited partnership which maintains the Class C membership interests in the Plan issued to Messrs. Munsell and Langford effective February 9, 2010.

(2)		The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2010.

Outstanding Equity Awards at Fiscal Year-End

The following table shows the grants of equity awards to our named executive officers that were outstanding on December 31, 2010, the last day of our fiscal year.

OUTSTANDING EQUITY AWARDS AT 2010 FISCAL YEAR-END

Option Awards

Stock Awards

Equity

Incentive

Equity

Plan

Incentive

Awards:

Plan

Market

Equity

Awards:

or Payout

Incentive

Number of

Value of

Plan

Market

Unearned

Awards:

Number of

Value of

Shares,

Number of

Shares or

Units or

Securities

Units of

Other

Underlying

Stock

Rights

Unexercised

Option

That

Options

Unearned

Exercise

Option

Have Not

(#)

Options

Price

Expiration

Vested

Name

Exercisable

Unexercisable

(#)

($)

Date

(#)

($)(1)

(#)

($)

Robert L. Cavnar

—

James G. Ivey

—

40,000

—

Gary Mabie

—

Marshall L. Munsell

—

30,000

—

Thomas C. Langford

—

28,000

—


(1)		The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2010.

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Option Exercises and Stock Vested Table

The table below shows the number of shares of our common stock acquired by our named executive officers during 2010 upon the vesting of Plan awards.

Option Exercises and Stock Vested
as of Fiscal Year-End December 31, 2010


	Option Awards				Stock Awards
	Number of				Number of
	Shares		Value		Shares			Value
	Acquired on		Realized on		Acquired on			Realized on
	Exercise		Exercise		Vesting			Vesting
Name	(#)		($)		(#)			($)(2)

Robert L. Cavnar		—		—		76,560	(1)		—
James G. Ivey		—		—		10,000			—
Gary Mabie		—		—		—			—
Marshall L. Munsell		—		—		15,000			—
Thomas C. Langford		—		—		14,000			—


(1)		Represents the conversion of general partner interests to limited partner interests in the limited partnership which maintains the Class C membership interests in the Plan in connection with the resignation of Mr. Cavnar. The limited partner interests were then subsequently forfeited in connection with his resignation.

(2)		The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2010.

Pension Benefits

We do not maintain any defined benefit pension plans.

Nonqualified Deferred Compensation

We do not maintain any nonqualified deferred compensation plans.

Employment Arrangements

We have entered into employment agreements with each of our named executive officers.

Our agreement with Mr. Ivey became effective January 1, 2009 and has a term of one year, with automatic renewal for additional one year periods unless either we or Mr. Ivey elects not to renew. He currently receives an annual base salary of $300,000 and is entitled to an annual bonus of up to 100% of his base salary as may be determined from time to time in the sole discretion of the Board of Directors based on the achievement of certain performance criteria. The Board of Directors also evaluates Mr. Ivey’s salary on an annual basis and will determine if any additional increases are warranted. The employment agreement prohibits Mr. Ivey from competing with us during his employment and for a period of one year thereafter if he is terminated for cause or he resigns without good reason. Mr. Ivey is also subject to a non-solicitation agreement for two years after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Payments under the agreement to Mr. Ivey in connection with his termination or a change of control are described below under “— Potential Payments Upon Termination or Change of Control.”

Our agreement with Mr. Mabie became effective February 8, 2010 and had a term of one year. This agreement has been extended through February 8, 2012. He currently receives an annual base salary of $250,000 and is entitled to an annual bonus as may be determined from time to time in the sole discretion of

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the Board of Directors based on the achievement of certain performance criteria. The Board of Directors also evaluates Mr. Mabie’s salary on an annual basis and will determine if any additional increases are warranted. Mr. Mabie is also subject to a non-solicitation agreement for six months after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Payments under the agreement to Mr. Mabie in connection with his termination or a change of control are described below under “— Potential Payments Upon Termination or Change of Control.”

Our agreements with Messrs. Munsell and Langford became effective November 30, 2007 and have a term of one year, with automatic renewal for additional one year periods unless either we or Mr. Munsell or Mr. Langford, as applicable, elects not to renew. They each currently receive an annual base salary of $240,000 and each is entitled to an annual bonus of up to 100% of his base salary as may be determined from time to time in the sole discretion of the Board of Directors based on the achievement of certain performance criteria. The Board of Directors also evaluates their salaries on an annual basis and will determine if any additional increases are warranted. The employment agreements prohibit Messrs. Munsell and Langford from competing with us during his employment and for a period of one year thereafter if he is terminated for cause or he resigns without good reason. Messrs. Munsell and Langford are also subject to a non-solicitation agreement for two years after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Payments under the agreements to Messrs. Munsell and Langford in connection with his termination or a change of control are described below under “— Potential Payments Upon Termination or Change of Control.”

Potential Payments upon Termination and Change of Control

The following tables describe the potential payments upon termination or a change in control for our named executive officers. Tables are not included for Mr. Cavnar because, as noted above, effective February 9, 2010, he is no longer employed by us.


Name: James G. Ivey
Title: Chief Financial Officer
					Involuntary
					Not for Cause
					Termination
					or Voluntary
					Termination						After a
	Voluntary		For Cause		for Good		Death or				Change in
Executive Benefits and Payments	Termination		Termination		Reason		Disability		Retirement		Control
Upon Termination(1)	($)		($)		($)		($)		($)		($)

Compensation
Severance(2)		—		—		250,000		—		—		500,000
Bonus(3)		—		—		250,000		—		—		250,000
Plan awards		—		—		—		—		—		—
Benefits and Perquisites
Health Continuation and Welfare Benefits(6)		—		—		43,821		1,200,000		—		43,821

Total		—		—		543,821		1,200,000		—		793,821

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Name: Gary Mabie
Title: Chief Operating Officer


					Involuntary
					Not for Cause
					Termination
					or Voluntary
					Termination						After a
	Voluntary		For Cause		for Good		Death or				Change in
Executive Benefits and Payments	Termination		Termination		Reason		Disability		Retirement		Control
Upon Termination(1)	($)		($)		($)		($)		($)		($)

Compensation
Severance(2)		—		—		240,000		—		—		480,000
Bonus(3)		—		—		—		—		—		—
Plan awards		—		—		—		—		—		—
Benefits and Perquisites
Health Continuation and Welfare Benefits(6)		—		—		10,283		1,125,000		—		10,283

Total		—		—		250,283		1,125,000		—		490,283


Name: Marshall L. Munsell
Title: Senior Vice President of Business Development
					Involuntary
					Not for Cause
					Termination
					or Voluntary
					Termination						After a
	Voluntary		For Cause		for Good		Death or				Change in
Executive Benefits and Payments	Termination		Termination		Reason		Disability		Retirement		Control
Upon Termination(1)	($)		($)		($)		($)		($)		($)

Compensation
Severance(2)		—		—		235,000		—		—		470,000
Bonus(3)		—		—		235,000		—		—		235,000
Plan awards		—		—		—		—		—		—
Benefits and Perquisites
Health Continuation and Welfare Benefits(6)		—		—		49,376		1,140,000		—		49,376

Total		—		—		519,376		1,140,000		—		754,376

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Name: Thomas C. Langford
Title: Senior Vice President and General Counsel


					Involuntary
					Not for Cause
					Termination
					or Voluntary
					Termination						After a
	Voluntary		For Cause		for Good		Death or				Change in
Executive Benefits and Payments	Termination		Termination		Reason		Disability		Retirement		Control
Upon Termination(1)	($)		($)		($)		($)		($)		($)(2)

Compensation
Severance(3)		—		—		235,000		—		—		470,000
Bonus(4)		—		—		235,000		—		—		235,000
Plan awards(5)		—		—		—		—		—		—
Benefits and Perquisites
Health Continuation and Welfare Benefits(6)		—		—		49,376		1,140,000		—		49,376

Total		—		—		519,376		1,140,000		—		754,376


(1)		For purposes of this analysis, we assumed that the effective date of termination is December 31, 2010, and that the executive’s compensation is as follows: Mr. Ivey’s base salary is equal to $250,00 and annual incentive target opportunity is equal to 100% of base salary; Mr. Mabie’s base salary is equal to $240,000 and annual incentive target opportunity is equal to 100% of base salary; Mr. Langford’s base salary is equal to $235,000 and annual incentive target opportunity is equal to 100% of base salary; and Mr. Munsell’s base salary is equal to $235,000 and annual incentive target opportunity is equal to 100% of base salary. We have assumed for purposes of this table that all bonus targets established by our Board of Directors have been met and our Board of Directors approved the payment of a bonus to the amount reflected. We have not reflected any payment for unused vacation accrued during the year.

(2)		Payments in connection with a change of control event (as defined in the employment agreements for each named executive officer) are payable if (i) they are terminated by us without cause (as defined in the employment agreements) or they terminate for good reason (as defined in the employment agreements) within 24 months after the change of control event or (ii) they terminate their employment for any reason within 30 days of the six month anniversary of the change of control event.

(3)		Under “Involuntary Not for Cause Termination or Voluntary Termination for Good Reason,” severance is calculated as 1x base salary and is payable in accordance with standard payroll practices. Under “After a Change in Control,” severance is calculated as 2x base salary and is payable in accordance with standard payroll practices.

(4)		Under “Involuntary Not for Cause Termination or Voluntary Termination for Good Reason” and “After a Change in Control,” bonus is calculated assuming all performance criteria have been met.

(5)		All unvested Plan awards are automatically forfeited for no consideration in connection with a termination of the employee for any reason. In addition, all Plan awards become fully vested in connection with a change of control. The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2010

(6)		Health and Welfare Benefits Continuation is calculated as 18 months of COBRA expense under “Involuntary Not for Cause Termination or Voluntary Termination for Good Reason” and “After a Change in Control.” In both categories, the benefits payable will be reduced to the extent that the named executive officer becomes eligible to comparable benefits from a new employer or other entity.

(7)		Welfare Benefits include various life, accident and disability insurance policies. For the purposes of this analysis, the maximum payout was calculated by assuming accidental death. Benefits will be paid in accord with each policy’s schedule of insurance and terms of the covered losses including the age of the participant.

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Compensation Committee Interlocks and Insider Participation

All compensation decisions are made by our Board of Directors. None of the members of our Board of Directors is or has been an officer or employee of our company or had any related person transactions involving us. None of our executive officers currently serves, or in the past year has served, as a member of the board of directors or compensation committee (or other committee serving an equivalent function) of any entity that has one or more executive officers serving on our board of directors or compensation committee.

Director Compensation

None of the members of our Board of Directors received any compensation from us during 2010. Certain of our equity sponsors (for which certain of our directors serve as representatives on our Board of Directors) did receive fees in 2010 pursuant to the Monitoring Agreement described below under “Certain Relationships and Related Party Transactions.”

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information with respect to the beneficial ownership of our common stock and our Series A preferred stock as of November 14, 2011.


	Number of					Number of
	Shares of					Shares of
	Common Stock					Preferred Stock
	Beneficially					Beneficially
Name and Address of Beneficial Owner	Owned(1)		Percentage			Owned(2)		Percentage(3)

ACON Funds Management, L.L.C.(4) 1133 Connecticut Avenue, NW, Suite 700 Washington, DC 20036		123,376		44.0	%		917,178		34.0	%
Guggenheim Investment Management, LLC(5) 135 East 57th Street, 6th Floor New York, New York 10022		83,840		29.9	%		502,135		18.6	%
Touradji Capital Management, LP(6) 101 Park Avenue, 48th Floor New York, NY 10178		—		—			425,921		15.8	%
West Coast Energy Partners(7) 1250 Fourth Street Santa Monica, California 90401		39,536		14.1	%		389,850		14.4	%
FS Investment Corporation(8) 280 Park Avenue New York, NY 10017		12,057		4.3	%		283,947		10.5	%
PineBridge Investments LLC(9) 277 Park Avenue, 42nd Floor New York, NY 10172		—		—			180,969		6.7	%
Other stockholders(10)		21,591		7.7	%		—		—

Total		280,400		100	%		2,700,000		100	%


(1)		Our parent company, Holdings, is a holding company and the holder of record of 100% of our issued and outstanding common stock. The number of shares of our common stock shown as beneficially owned is based on the respective beneficial ownership interest of each investor in Holdings and assumes the Class C membership interests in Holdings are not currently entitled to distributions. Holdings has three classes of membership interests outstanding: Class A, substantially all of which is owned by affiliates of ACON Funds Management, Guggenheim Investment Management and West Coast Partners; Class B, which is held by the original investors from 2005; and Class C, which are non-voting profit interests issued to our management team. All voting and investment decisions with respect to our common stock are made by the board of directors of Holdings, which is made up of representatives of ACON, Guggenheim and West Coast, as well as our chief executive officer.

(2)		The holders of our Series A preferred stock are party to the Stockholders’ Agreement, which will remain in effect for so long as we remain a subsidiary of Holdings. The Stockholders’ Agreement provides our Series A preferred stockholders with the right to, among other things, appoint four of the five members of our board of directors. The Stockholders’ Agreement also places restrictions on the ability of the holders of our Series A preferred stock to transfer their shares and requires that certain actions be approved unanimously or by a supermajority of our board of directors.

(3)		Based on 2,700,000 shares of our Series A preferred stock outstanding as of November 14, 2011.

(4)		Includes shares held by ACON Milagro Second Lien Investors, LLC. Jonathan Ginns and Mo Bawa exercise voting and investment authority over these shares and serve as the representatives of ACON on our board of directors. See “Management — Board of Directors.”

(5)		Includes shares held by 1888 Fund, Ltd., Copper River CLO Ltd., Green Lane CLO Ltd., NZC Guggenheim Master Fund Limited, Sands Point Funding Ltd., Guggenheim Energy Opportunities Fund, LP,

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		Kennecott Funding Ltd., IN-FP1, LLC and New Energy LLC. Guggenheim Investment Management, LLC is a wholly-owned subsidiary of Guggenheim Capital, LLC, which exercises voting and investment authority over these shares. Thomas J. Hauser serves as the representative of Guggenheim on our board of directors. See “Management — Board of Directors.”

(6)		Includes shares held by Touradji Diversified Holdings, LLC, Touradji Diversified Ventures I Inc., Touradji Global Resources Holdings, LLC, and Touradji Global Resources Ventures I Inc., each of which is managed by Touradji Capital Management, LP. Mr. Paul Touradji is the General Partner of Touradji Capital Management and has voting and investment authority over the shares.

(7)		Adam Cohn exercises voting and investment authority over these shares and serves as the representative of West Coast Energy Partners on our board of directors. See “Management — Board of Directors.”

(8)		Mr. Brad Mardhall exercises voting and investment authority over these shares.

(9)		Includes shares held by AIG Vantage Capital, L.P. and AIG PEP IV Co-Investment, L.P. Jonathan Sterns exercises voting and investment authority over these shares.

(10)		Includes investors who individually beneficially own less than 1% of our outstanding common stock. Members of our management team do not beneficially own any shares of our capital stock other than Class C membership interests in Holdings. See “Management — Compensation Information.”

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In the ordinary course of our business and in connection with our financing activities, we have entered into transactions with certain of our affiliates and significant stockholders. All of the transactions set forth below were approved by the unanimous vote of our board of directors. We believe that we have executed all of the transactions set forth below on terms no less favorable to us than could have been obtained from unaffiliated third parties.

Monitoring Agreement

In connection with the acquisition of Petrohawk Energy Corporation’s Gulf Coast assets in November 2007, Holdings entered into a Monitoring Agreement with our equity sponsors ACON, Guggenheim and West Coast (the “Monitoring Agreement”). Pursuant to the terms of the Monitoring Agreement, the equity sponsors agreed to provide Holdings with management and advisory services during the term of the Monitoring Agreement, including, but not limited to, services relating to: (a) financing matters; (b) acquisitions, dispositions and corporate change of control transactions, (c) commodity risk management,(d) day-to-day operational matters and (e) such other services as agreed to in writing. On the date Holdings entered into the Monitoring Agreement, the equity sponsors were paid a one-time equity commitment fee of $8.25 million. In addition, during the term of the Monitoring Agreement, and in exchange for services provided under the Monitoring Agreement, we are required to pay our equity sponsors an annual fee of $2.5 million payable in four quarterly installments. Although we are not a party to the Monitoring Agreement and therefore have no liability for payment of the fees thereunder, because Holdings is a holding company with no operations or assets other than our outstanding common stock, Holdings is dependent on distributions from us to fund its payment obligations under the Monitoring Agreement. In addition, because 100% of our common stock is held by Holdings, Holdings has the ability to require us to make distributions. However, as a result of restrictions under our prior first lien credit agreement and our existing first lien credit agreement, to date we have not been permitted to make distributions to Holdings sufficient to pay the monitoring fee and as a result the monitoring fee has continued to accrue. As of June 30, 2011, this accrued obligation was an aggregate of $6.9 million. We expect similar restrictions on distributions to make these payments will continue in the indenture governing these notes and the New Credit Facility. The Monitoring Agreement will continue in effect until all of the equity sponsors consent to its termination. As part of the Monitoring Agreement, Holdings agreed to indemnify the equity sponsors for claims resulting from services provided thereunder; provided such claims do not arise out of an equity sponsor’s gross negligence or willful misconduct. Further, the Monitoring Agreement does not limit the equity sponsors’ ability to provide similar services to other companies, including competitors, and does not require the equity sponsors to present Holdings with any corporate opportunity before informing a third party of such opportunity.

Development Services Agreement

Two of our wholly-owned subsidiaries, Milagro Producing, LLC (“Producing”) and Milagro Exploration, LLC (“Exploration”), are parties to a Development Services Agreement (the “Development Services Agreement”). Pursuant to the Development Services Agreement, Exploration provides Producing with oil and gas services relating to Producing’s owned and acquired properties. These services include: (a) geological and geophysical services, (b) project marketing services, (c) drilling, completion and operating services (including acting as an operator for oil and gas properties), (d) accounting services, (e) revenue distribution and joint interest billing services, (f) governmental compliance and regulatory filings support, (g) general business services, (h) land services, (i) production handling, marketing and hedging, and (j) such additional services as the parties mutually agree. In return for services provided under the Development Services Agreement, Exploration receives reimbursement for costs incurred and the right to hold title to or be the licensee of all geological and geophysical data procured during the course of its work performed under the Development Services Agreement. In addition, Producing provides the funds required for Exploration to develop and acquire one or more proprietary seismic programs with all data derived from such a program being the property of Exploration. Upon termination of the Development Services Agreement, and in some cases before then, Exploration will reimburse Producing for the costs associated with acquiring the proprietary seismic program. The Development Services Agreement will remain in effect as long as Producing remains in existence and may be terminated at any time for any reason by Producing.

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DESCRIPTION OF NEW CREDIT FACILITY

In connection with the closing of the offering of the old notes, we entered into a new senior secured revolving credit facility (the “New Credit Facility”). The New Credit Facility has a stated maturity date of November 10, 2014 and permits borrowings of up to $300.0 million, subject to an initial borrowing base of approximately $170.0 million. The New Credit Facility also includes a $10.0 million subfacility for standby letters of credit, of which $1.6 million has been issued as of June 30, 2011, and a discretionary swing line subfacility of $5.0 million. Standby letters of credit may be issued under the letter of credit subfacility with expiration dates not later than one year after issuance. Letters of credit which expire after the maturity date will be cash collateralized with 103% of the exposure. A letter of credit fee equal to the LIBOR Margin per annum (but in no event less than $500) on the undrawn amount of each outstanding letter of credit will be payable by us for the account of the lenders. This fee will be payable quarterly in arrears.

The borrowing base will be redetermined semi-annually on each April 1 and October 1, commencing with October 1, 2011. In the event the total outstanding balance of the New Credit Facility at the time of a borrowing base redetermination is greater than the newly established borrowing base, we will, within 30 days from the redetermination exercise one or a combination of the following options: (i) repay the difference between the outstanding New Credit Facility balance and the borrowing base, (ii) repay the deficiency in five monthly installments equal to one-fifth of such deficiency with the first such installment due 30 days after notice from the administrative agent of the new or adjusted borrowing base (or such earlier date as) and each following installment due 30 days after the preceding installment or (iii) provide additional collateral acceptable to the lenders to increase the borrowing base to an amount at least equal to the outstanding principal balance of the New Credit Facility. At any time that a borrowing base deficiency exists, any extraordinary cash receipts (including, but not limited to, hedge terminations, asset sales, insurance proceeds, and litigation settlements) shall be applied immediately to the deficiency.

Amounts outstanding under the New Credit Facility bear interest at specified margins over LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the New Credit Facility. The New Credit Facility is secured by a first priority mortgage and security interest in substantially all of the our assets, including without limitation (a) 85% of the total value of our proved reserves and 85% of the total value of our proved developed producing reserves from our oil and gas properties currently owned and hereafter acquired, (b) 100% of the equity interests of all of our direct or indirect subsidiaries, and (c) all accounts receivable, inventory, contract rights, and general intangibles.

The New Credit Facility agreement contain representations, warranties and covenants consistent with those prior first lien credit agreement, including covenants restricting sales of all or a substantial or material part of our assets; mergers, acquisitions, reorganizations and recapitalizations; liens; guarantees; restricted payments, additional indebtedness; leases; dividends and other distributions; changes in management, investments; sale-leasebacks; lease expenditures; and transactions with affiliates.

The principal financial covenants of the New Credit Facility are: (i) a leverage ratio, requiring us to maintain, for the12-month period ending on the last day of each fiscal quarter, a ratio of total debt (other than hedge obligations) to EBITDA of no more than (a) 4.50x for each quarter ending in 2011, (b) 4.25x for each quarter ending in 2012, and (c) 4.00x for each quarter ending in 2013 and thereafter; (ii) a senior secured leverage ratio, requiring us to maintain, for the12-month period ending on the last day of each fiscal quarter, a ratio of total senior secured debt (other than the notes) to EBITDA of no more than 2.00x; (iii) an interest coverage ratio, requiring us to maintain, for the12-month period ending on the last day of each fiscal quarter, a ratio of EBITDA to interest expense of not less than (a) 2.25x for each quarter ending in 2011 and (b) 2.50x for each quarter thereafter; and (iv) a current ratio, requiring us to maintain a current ratio on the last day of each fiscal quarter of not less than 1.00x.

Beginning September 8, 2011, we were required to maintain forward hedges at all times on at least 50% but not more than 90%, of projected proved developed producing volumes based on the most recently delivered reserve report at any time through the stated maturity date.

If during a borrowing base deficiency, we terminate or monetize a commodity hedge position, 100% of the proceeds from said termination must be used to reduce or eliminate the borrowing base deficiency.

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DESCRIPTION OF THE EXCHANGE NOTES

You can find the definitions of certain terms used in this description under the subheading “— Certain Definitions.” In this description, the word “Milagro” refers only to Milagro Oil & Gas, Inc. and not to any of its Subsidiaries.

Milagro will issue the exchange notes under an indenture among itself, the Guarantors and Wells Fargo Bank, N.A., as trustee. The terms of the exchange 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. Unless the context requires otherwise, all references to the “notes” in this “Description of the Exchange Notes” include the old notes and the exchange notes. The old notes and the exchange notes will be treated as a single class for all purposes of the Indenture.

The following description is a summary of the material provisions of the indenture, the collateral trust agreement, the intercreditor agreement and the registration rights agreement. It does not restate those agreements in their entirety. We urge you to read the indenture, the collateral trust agreement, the intercreditor agreement and the registration rights agreement because they, and not this description, define your rights as holders of the notes. Copies of the indenture, the collateral trust agreement, the intercreditor agreement and the registration rights agreement are available as set forth below under “— Additional Information.”Certain defined terms used in this description but not defined below under “— Certain Definitions” have the meanings assigned to them in the indenture, the collateral trust agreement, the intercreditor agreement and the registration rights agreement.

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.

Brief Description of the Notes and the Note Guarantees

The Notes

The old notes are, and the exchange notes will be,:


	•	general obligations of Milagro;

	•	secured on a second-priority basis by Liens on all of the assets of Milagro that secure the Credit Agreement, other than the Excluded Assets, subject in priority to the Liens securing Milagro’s guarantee of the Credit Agreement and any other Priority Lien Debt and other Permitted Prior Liens;

	•	effectively junior, to the extent of the value of the Collateral, to Milagro’s guarantee of the Credit Agreement and any other Priority Lien Debt, which will be secured on a first-priority basis by the same assets of Milagro that secure the notes;

	•	effectively junior to any Permitted Prior Liens, to the extent of the value of the assets of Milagro subject to those Permitted Prior Liens

	•	pari passuin right of payment with all existing and future senior Indebtedness of Milagro, including its guarantee of the Indebtedness under the Credit Agreement;

	•	senior in right of payment to any future subordinated Indebtedness of Milagro; and

	•	unconditionally guaranteed by the Guarantors on a senior secured, second-priority basis.

The Note Guarantees

The old notes are, and the exchange notes will be, initially guaranteed by all of Milagro’s existing and future direct and indirect Domestic Subsidiaries.

Each guarantee of the old notes is, and each guarantee of the exchange notes will be:


	•	a general obligation of the Guarantor;

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	•	secured on a second-priority basis by Liens on all of the assets of that Guarantor that secure the Credit Agreement, other than the Excluded Assets, subject in priority to the Liens securing that Guarantor’s guarantee of, or obligations under, the Credit Agreement and any other Priority Lien Debt and other Permitted Prior Liens;

	•	effectively junior, to the extent of the value of the Collateral, to that Guarantor’s guarantee of, or obligations under, the Credit Agreement and any other Priority Lien Debt, which will be secured on a first-priority basis by the same assets of that Guarantor that secure the notes;

	•	effectively junior to any Permitted Prior Liens, to the extent of the value of the assets of that Guarantor subject to those Permitted Prior Liens;

	•	pari passuin right of payment with all existing and future senior Indebtedness of that Guarantor, including its Indebtedness under, or its guarantee of the Indebtedness under, the Credit Agreement; and

	•	senior in right of payment to any future subordinated Indebtedness of that Guarantor.

Pursuant to the indenture, Milagro will be permitted to designate additional Indebtedness as Priority Lien Debt, in a principal amount not to exceed the Priority Lien Cap. Milagro also will be permitted to incur additional Indebtedness as Parity Lien Debt in a principal amount not to exceed the Parity Lien Cap, subject to the covenants described below under “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” and “— Certain Covenants — Liens.” As of June 30, 2011, Milagro had approximately $96.0 million of Priority Lien Debt and approximately $250.0 million of Parity Lien Debt outstanding (all of which would have been the Parity Lien Debt evidenced by the notes).

As of the date of the indenture, all of our Subsidiaries were “Restricted Subsidiaries.” However, under the circumstances described below under the caption “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries,” we will be permitted to designate certain of our Subsidiaries as “Unrestricted Subsidiaries.” Our Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. Our Unrestricted Subsidiaries will not guarantee the notes.

Principal, Maturity and Interest

Milagro issued $250.0 million in aggregate principal amount of notes in the offering. Milagro may issue additional notes under the indenture from time to time after this offering. Any issuance of additional notes is subject to all of the covenants in the indenture, including the covenant described below under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock.” The 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. Milagro has and will issue notes in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. The notes will mature on May 15, 2016.

Interest on the notes accrues at the rate of 10.500% per annum and is payable semi-annually in arrears on May 15 and November 15, commencing on November 15, 2011. Interest on overdue principal and interest will accrue at a rate that is 1% higher than the then applicable interest rate on the notes. Milagro will make each interest payment to the holders of record on the immediately preceding May 1 and November 1.

Interest on the notes accrues from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest is computed on the basis of a360-day year comprised of twelve30-day months.

Methods of Receiving Payments on the Notes

If a holder of notes has given wire transfer instructions to Milagro, Milagro will pay all principal of, premium on, if any, and interest and Special Interest, if any, on, that holder’s notes in accordance with those instructions to an account in the United States. All other payments on the notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless Milagro elects to make interest payments by check mailed to the noteholders at their address set forth in the register of holders.

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Paying Agent and Registrar for the Notes

The trustee will initially act as paying agent and registrar. Milagro may change the paying agent or registrar without prior notice to the holders of the notes, and Milagro or any of its Subsidiaries may act as paying agent or registrar.

Transfer and Exchange

A holder may transfer or exchange notes in accordance with the provisions of the indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer. Milagro will not be required to transfer or exchange any note selected for redemption. Also, Milagro will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.

Note Guarantees

The notes are and will be guaranteed by each of Milagro’s current and future Domestic Subsidiaries. These Note Guarantees are and will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee will be limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors — Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from guarantors.”

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

(1) immediately after giving effect to such transaction, no Default or Event of Default exists; and

(2) either:

(a) the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger unconditionally assumes all the obligations of that Guarantor under (x) its Note Guarantee pursuant to a supplemental indenture satisfactory to the trustee and (y) the other applicable Notes Documents pursuant to supplements satisfactory to the trustee; or

(b) the Net Proceeds of such sale or other disposition are applied in accordance with the applicable provisions of the indenture.

The Note Guarantee of a Guarantor will be released:

(1) in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor, by way of merger, consolidation or otherwise, to a Person that is not (either before or after giving effect to such transaction) Milagro or a Restricted Subsidiary of Milagro, if the sale or other disposition does not violate the provisions described below under the caption “— Repurchases at the Option of Holders — Asset Sales;”

(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) Milagro or a Restricted Subsidiary of Milagro, if the sale or other disposition does not violate the provisions described below under the caption “— Repurchases at the Option of Holders — Asset Sales” and the Guarantor ceases to be a Restricted Subsidiary of Milagro as a result of the sale or other disposition;

(3) if Milagro designates any Restricted Subsidiary that is a Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture; or

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(4) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture as provided below under the captions “— Legal Defeasance and Covenant Defeasance” and “— Satisfaction and Discharge.”

See “— Repurchase at the Option of Holders — Asset Sales.”

Security

The obligations of Milagro with respect to the notes, the obligations of the Guarantors under the guarantees, all other Parity Lien Obligations and the performance of all other obligations of Milagro, the Guarantors and Milagro’s other Restricted Subsidiaries under the Note Documents will be secured equally and ratably by second-priority Liens in the Collateral granted to the collateral trustee for the benefit of the holders of the Parity Lien Obligations. These Liens will be junior in priority to the Liens securing Priority Lien Obligations, subject to the Priority Lien Cap, and to all other Permitted Prior Liens.

The Collateral consists of Milagro’s and the Guarantors’ Oil and Gas Properties and substantially all other assets of Milagro and the Guarantors (other than the Excluded Assets), in each case, to the extent such properties and assets secure obligations of Milagro and the Guarantors under the Credit Agreement;provided, in any event, except as otherwise provided in the intercreditor agreement, the Collateral shall include not less than 80% of the total Recognized Value of Milagro’s and the Guarantors’ proved Oil and Gas Properties located in the United States or in adjacent Federal waters which are evaluated in the most recently completed Reserve Report delivered pursuant to the Credit Agreement (or any agreements refinancing, replacing, refunding or restating the Credit Agreement as in effect on the Issue Date). If no such Reserve Report is delivered pursuant to the Credit Agreement or any such other agreement, Milagro shall deliver to the collateral trustee semi-annually on or before March 1 and September 1 in each calendar year an Officers’ Certificate certifying that, as of the date of such certificate, the Collateral includes Oil and Gas Properties subject to Mortgages over at least 80% of the total Recognized Value of Milagro’s and the Guarantors’ proved Oil and Gas Properties located in the United States and adjacent Federal waters. To the extent that any Oil and Gas Properties constituting Collateral are released after the date of any applicable Reserve Report or certificate to be delivered pursuant to theprovisocontained in the second preceding sentence, and are then assigned to Persons other than Milagro and the Guarantors, any proved reserves attributable to such Oil and Gas Properties shall be deemed excluded from such Reserve Report for the purpose of determining whether such 80% requirement is met after giving effect to such release.

Pursuant to the Credit Agreement, in connection with each redetermination of the borrowing base, the Guarantors that are borrowers under the Credit Agreement will be required to review the Reserve Report that is required to be delivered under the Credit Agreement and the list of current Mortgaged Properties to ascertain whether the Mortgaged Properties represent at least 85% of the total Recognized Value of the proved Oil and Gas Properties and the proved producing Oil and Gas Properties evaluated in the most recently completed Reserve Report. In the event that the Mortgaged Properties do not represent at least 85% of such total Recognized Value, then, under the Credit Agreement, Milagro and the Guarantors are required to grant to the Credit Agreement Agent as security for the Priority Lien Obligations a Priority Lien (subject only to Permitted Liens) on additional proved Oil and Gas Properties not already subject to a Lien such that after giving effect thereto, the Mortgaged Properties will represent at least 85% of such total Recognized Value. If Milagro or any Guarantor creates any additional Lien upon any Oil and Gas Properties to secure Priority Lien Obligations, the indenture provides that it will grant a Parity Lien upon such property (subject to Permitted Prior Liens) as security for the notes and the other Parity Lien Obligations substantially concurrently with granting any such additional Lien.

The Collateral does not and will not include the following:

(1) any lease (other than an oil and gas lease), license, contract or agreement to which Milagro or any Guarantor is a party or any of its rights or interests thereunder if and only for so long as the grant of a Lien under the security documents will constitute or result in a termination under, or a default or breach thereof that would give the other party thereto the right to terminate, any such lease, license, contract or agreement (other than to the extent that any such term would be rendered ineffective pursuant to

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Sections 9-406, 9-407, 9-408 or 9-409 of the Uniform Commercial Code of any relevant jurisdiction or any other applicable law or principles of equity);providedthat such lease, license, contract or agreement will cease to be an Excluded Asset immediately and automatically, at such time as such consequences will no longer result;

(2) the Capital Stock of any Foreign Subsidiary to the extent that the voting power of such Capital Stock aggregates to more than 65% of the voting power of such Foreign Subsidiary or the Capital Stock of any Subsidiary of a Foreign Subsidiary;

(3) the Capital Stock of any Subsidiary 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 thenRule 3-16 orRule 3-10 ofRegulation 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;

(4) fixed or capital assets owned by Milagro or any Guarantor that is 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 fixed or capital assets; and

(5) other property or assets owned by the Company or any Guarantor that is not secured by Liens for the benefit of any Priority Lien Obligations;

(such excluded assets collectively referred in this prospectus as the “Excluded Assets”)

On the date of the indenture, Milagro and the Guarantors entered into a collateral trust agreement (the “collateral trust agreement”) with the collateral trustee and the trustee. The collateral trust agreement sets forth the terms on which the collateral trustee will receive, hold, administer, maintain, enforce and distribute the proceeds of all Liens upon any property of Milagro or any Guarantor at any time held by it, in trust for the benefit of the current and future holders of the Parity Lien Obligations.

Collateral Trustee

Wells Fargo Bank, N.A. has been appointed pursuant to the collateral trust agreement to serve as the collateral trustee for the benefit of the holders of:


	•	the notes and the Note Guarantees; and

	•	all other Parity Lien Obligations outstanding from time to time.

The collateral trustee will hold (directly or through co-trustees or agents), and, subject to the terms of the intercreditor agreement, will be entitled to enforce, all Liens on the Collateral created by the security documents.

Except as provided in the collateral trust agreement or as directed by an Act of Parity Lien Debtholders in accordance with the collateral trust agreement, the collateral trustee will not be obligated:

(1) to act upon directions purported to be delivered to it by any Person;

(2) to foreclose upon or otherwise enforce any Lien; or

(3) to take any other action whatsoever with regard to any or all of the security documents, the Liens created thereby or the Collateral.

Milagro will deliver to each Parity Lien Representative copies of all security documents delivered to the collateral trustee.

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The Intercreditor Agreement

On the date of the indenture, the collateral trustee entered into an intercreditor agreement (the “intercreditor agreement”) with Milagro, the Guarantors and the Priority Lien Collateral Agent, which provides for, among other things, the junior nature of the Liens on the Collateral securing the Parity Lien Obligations. All such Liens are subject to Permitted Prior Liens. Although the holders of the notes are not party to the intercreditor agreement, by their acceptance of the notes they agree to be bound thereby. The intercreditor agreement permits the Priority Lien Obligations and the Parity Lien Obligations to be refunded, refinanced or replaced by certain permitted refinancing indebtedness without affecting the lien priorities set forth in the intercreditor agreement, in each case, without the consent of any holder of Priority Lien Obligations or Parity Lien Obligations (including holders of the notes).

Ranking of Parity Liens

The intercreditor agreement provides that, notwithstanding:

(1) anything to the contrary contained in the security documents;

(2) the time of incurrence of any Series of Secured Debt;

(3) the order or method of attachment or perfection of any Liens securing any Series of Secured Debt;

(4) the time or order of filing or recording of financing statements, mortgages or other documents filed or recorded to perfect any Lien upon any Collateral;

(5) the time of taking possession or control over any Collateral;

(6) any Priority Lien may not have been perfected or may be or have become subordinated, by equitable subordination or otherwise, to any other Lien; or

(7) the rules for determining priority under any law governing relative priorities of Liens,

all Parity Liens at any time granted by Milagro or any Guarantor are subject and subordinate to all Priority Liens securing Priority Lien Obligations, subject to the Priority Lien Cap.

The provisions under the caption “— Ranking of Parity Liens” are intended for the benefit of, and are enforceable as a third party beneficiary by, each present and future holder of Priority Lien Obligations and each present and future Priority Lien Collateral Agent as holder of Priority Liens. No other Person is entitled to rely on, have the benefit of or enforce those provisions.

In addition, the provisions under the caption “— Ranking of Parity Liens” are intended solely to set forth the relative ranking, as Liens, of the Liens securing Parity Lien Debt as against the Priority Liens. Neither the notes, nor any other Parity Lien Obligations, are intended to be, or will ever be by reason of the foregoing provision, in any respect subordinated, deferred, postponed, restricted or prejudiced in right of payment.

Limitation on Enforcement of Remedies

The intercreditor agreement provides that, except as provided below in this paragraph or in the following paragraph, neither the collateral trustee, nor any holder of Parity Lien Obligations, may commence any judicial or nonjudicial foreclosure proceedings with respect to, seek to have a trustee, receiver, liquidator or similar official appointed for or over, attempt any action to take possession of, exercise any right, remedy or power with respect to, or otherwise take any action to enforce its interest in or realize upon, or take any other action available to it in respect of, the Collateral under any security document, applicable law or otherwise, at any time prior to the Discharge of Priority Lien Obligations. Only the Priority Lien Collateral Agent is entitled to take any such actions or exercise any such remedies with respect to the Collateral prior to the Discharge of Priority Lien Obligations. The intercreditor agreement provides that, notwithstanding the foregoing, the collateral trustee may, but will have no obligation to, on behalf of the holders of Parity Lien Obligations, take all such actions (not adverse to the Priority Liens or the rights of the Priority Lien Collateral Agent and

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holders of the Priority Lien Obligations) it deems necessary to perfect or continue the perfection of their junior security interests in the Collateral or to create, preserve or protect (but not enforce) their junior security interests in the Collateral. Until the Discharge of Priority Lien Obligations, the Priority Lien Collateral Agent has the exclusive right to deal with that portion of the Collateral consisting of deposit accounts and securities accounts, including exercising rights under control agreements with respect to such accounts. In addition, whether before or after the Discharge of Priority Lien Obligations, the collateral trustee and the holders of Parity Lien Obligations may take any actions and exercise any and all rights that would be available to a holder of unsecured claims, including, without limitation, the commencement of an Insolvency or Liquidation Proceeding against Milagro or any Guarantor in accordance with applicable law;provided, that the collateral trustee and such holders of Parity Lien Obligations may not take any of the actions described below under clauses (1) through (9) of the first paragraph under the caption “— No Interference; Payment Over; Reinstatement” or prohibited by the provisions described in the first two paragraphs below under the caption “— Agreements with Respect to Insolvency or Liquidation Proceedings”;provided,further, that in the event that the collateral trustee or any holder of Parity Lien Obligations becomes a judgment lien creditor in respect of any Collateral as a result of its enforcement of its rights as an unsecured creditor with respect to the Parity Lien Obligations, such judgment lien shall be subject to the terms of the intercreditor agreement for all purposes (including in relation to the Priority Lien Obligations) as the other liens securing the Parity Lien Obligations are subject to the intercreditor agreement.

Notwithstanding the foregoing, both before and during an insolvency or liquidation proceeding, after a period of 180 days has elapsed (which period will be tolled during any period in which the Priority Lien Collateral Agent is not entitled, on behalf of holders of Priority Lien Obligations, to enforce or exercise any rights or remedies with respect to any Collateral as a result of (x) any injunction issued by a court of competent jurisdiction or (y) the automatic stay or any other stay in any insolvency or liquidation proceeding) since the date on which the collateral trustee has delivered to the Priority Lien Collateral Agent written notice of the acceleration of the notes (the “Standstill Period”), the collateral trustee and the holders of Parity Lien Obligations may enforce or exercise any rights or remedies with respect to any Collateral;provided,however, that notwithstanding the expiration of the Standstill Period or anything in the collateral trust agreement to the contrary, in no event may the collateral trustee or any other holder of Parity Lien Obligations enforce or exercise any rights or remedies with respect to any Collateral, or commence, join with any Person at any time in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding, if the Priority Lien Collateral Agent on behalf of the holders of Priority Lien Obligations or any other holder of Priority Lien Obligations shall have commenced, and shall be diligently pursuing (or shall have sought or requested relief from, or modification of, the automatic stay or any other stay in any insolvency or liquidation proceeding to enable the commencement and pursuit thereof), the enforcement or exercise of any rights or remedies with respect to all or any material portion of the Collateral or any such action or proceeding (prompt written notice thereof to be given to the Parity Lien Representatives by the collateral trustee);provided,further, that, if at any time after the expiration of the Standstill Period, if neither the Priority Lien Collateral Agent, nor any holder of Priority Lien Obligations, shall have commenced and be diligently pursuing the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding, and the collateral trustee shall have commenced the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding, then for so long as the collateral trustee is diligently pursuing such rights or remedies, neither any holder of Priority Lien Obligations nor the Priority Lien Collateral Agent shall take any action of a similar nature with respect to such Collateral, or commence, join with any Person at any time in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding.

Priority Lien Collateral Agent

The intercreditor agreement provides that neither the Priority Lien Collateral Agent, nor any holder of any Priority Lien Obligations, has any duties or other obligations to any holder of Parity Lien Obligations with respect to the Collateral, other than to transfer to the collateral trustee any remaining Collateral and the proceeds of the sale or other disposition of any Collateral remaining in its possession following the Discharge

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of Priority Lien Obligations, in each case, without representation or warranty on the part of, or recourse to, the Priority Lien Collateral Agent or any holder of Priority Lien Obligations.

In addition, the intercreditor agreement further provides that, until the Discharge of Priority Lien Obligations (but subject to the rights of the collateral trustee and the holders of Parity Lien Obligations following expiration of the Standstill Period as provided in the paragraph defining “Standstill Period”), the Priority Lien Collateral Agent is entitled, for the benefit of the holders of the Priority Lien Obligations, to sell, transfer or otherwise dispose of or deal with the Collateral without regard to any junior security interest therein granted to the holders of Parity Lien Obligations or any rights to which the collateral trustee or any holder of Parity Lien Obligations would otherwise be entitled as a result of such junior security interest. Without limiting the foregoing, the intercreditor agreement provides that neither the Priority Lien Collateral Agent, nor any holder of any Priority Lien Obligations, has any duty or obligation first to marshal or realize upon the Collateral, or to sell, dispose of or otherwise liquidate all or any portion of the Collateral, in any manner that would maximize the return to the holders of Parity Lien Obligations, notwithstanding that the order and timing of any such realization, sale, disposition or liquidation may affect the amount of proceeds actually received by the holders of Parity Lien Obligations from such realization, sale, disposition or liquidation. Following the Discharge of Priority Lien Obligations, the collateral trustee and the holders of Parity Lien Obligations may, subject to any other agreements binding on the collateral trustee and the holders of Parity Lien Obligations, assert their rights, under the Uniform Commercial Code or otherwise, to any proceeds remaining following a sale, disposition or other liquidation of Collateral by, or on behalf of, the holders of Priority Lien Obligations.

The intercreditor agreement additionally provides that the collateral trustee, and each holder of Parity Lien Obligations, waives any claim against the Priority Lien Collateral Agent, or any holder of any Priority Lien Obligations. arising out of any actions which the Priority Lien Collateral Agent or such holder of Priority Lien Obligations takes or omits to take (including actions with respect to the creation, perfection or continuation of Liens on any Collateral, actions with respect to the foreclosure upon, sale, release or depreciation of, or failure to realize upon, any Collateral, and actions with respect to the collection of any claim for all or any part of the Priority Lien Obligations from any account debtor, guarantor or any other party) in accordance with the intercreditor agreement and the Priority Lien Documents or the valuation, use, protection or release of any security for such Priority Lien Obligations.

No Interference; Payment Over; Reinstatement

The intercreditor agreement provides that the collateral trustee and each holder of Parity Lien Obligations:

(1) will not take or cause to be taken any action the purpose or effect of which is, or could be, to make any Lien that the collateral trustee or the holders of Parity Lien Obligations have on the Collateralpari passuwith, or to give the collateral trustee or any holder of Parity Lien Obligations any preference or priority relative to, any Lien that the Priority Lien Collateral Agent holds on behalf of the holders of any Priority Lien Obligations secured by any Collateral or any part thereof;

(2) will not challenge or question, in any proceeding, the validity or enforceability of any Priority Lien Obligations or Priority Lien Documents or the validity, attachment, perfection or priority of any Lien held by the Priority Lien Collateral Agent on behalf of the holders of any Priority Lien Obligations, or the validity or enforceability of the priorities, rights or duties established by the provisions of the intercreditor agreement;

(3) will not take or cause to be taken any action the purpose or effect of which is, or could be, to interfere, hinder or delay, in any manner, whether by judicial proceedings or otherwise, any sale, transfer or other disposition of the Collateral by the Priority Lien Collateral Agent or the holders of any Priority Lien Obligations in an enforcement action;

(4) will have no right to (A) direct the Priority Lien Collateral Agent or any holder of any Priority Lien Obligations to exercise any right, remedy or power with respect to any Collateral or (B) consent to

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the exercise by the Priority Lien Collateral Agent or any holder of any Priority Lien Obligations of any right, remedy or power with respect to any Collateral;

(5) will not institute any suit or assert in any suit or in any Insolvency or Liquidation Proceeding, any claim against the Priority Lien Collateral Agent or any holder of any Priority Lien Obligations seeking damages from or other relief by way of specific performance, instructions or otherwise with respect to, and neither the Priority Lien Collateral Agent nor any holders of any Priority Lien Obligations will be liable for, any action taken or omitted to be taken by the Priority Lien Collateral Agent or such holders of Priority Lien Obligations with respect to any Collateral securing such Priority Lien Obligations;

(6) will not seek and will waive any right to have any Collateral or any part thereof marshaled upon any foreclosure or other disposition of such Collateral;

(7) will not attempt, directly or indirectly, whether by judicial proceedings or otherwise, to challenge the enforceability of any provision of the intercreditor agreement;

(8) will not object to forbearance by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations; and

(9) will not assert, and hereby waive, to the fullest extent permitted by law, any right to demand, request, plead or otherwise assert or claim the benefit of any marshalling, appraisal, valuation or other similar right that may be available under applicable law with respect to the Collateral or any similar rights a junior secured creditor may have under applicable law.

The intercreditor agreement provides that, notwithstanding the foregoing, both before and during any Insolvency or Liquidation Proceeding, the collateral trustee and the holders of Parity Lien Obligations may, to the extent consistent with the terms of the intercreditor agreement, take any actions and exercise any and all rights that would be available to a holder of unsecured claims, including, without limitation, the commencement of an Insolvency or Liquidation Proceeding against Milagro or any Guarantor in accordance with applicable law;provided, that the collateral trustee and such holders of Parity Lien Obligations may not take any of the actions described under clauses (1) through (9) above or prohibited by the provisions described in the first two paragraphs under the caption “— Agreements with Respect to Insolvency or Liquidation Proceedings”;provided, that in the event that the collateral trustee or the holders of Parity Lien Obligations becomes a judgment lien creditor in respect of any Collateral as a result of its enforcement of its rights as an unsecured creditor with respect to the Parity Lien Obligations, such judgment lien shall be subject to the terms of the intercreditor agreement for all purposes (including in relation to the Priority Lien Obligations) as the other liens securing the Parity Lien Obligations are subject to the intercreditor agreement.

The intercreditor agreement provides that if the collateral trustee or any holder of Parity Lien Obligations obtains possession of any Collateral or realizes any proceeds or payment in respect of any Collateral, pursuant to the exercise of remedies under any security document, or by the exercise of any rights available to it under applicable law, as a result of any distribution of, or in respect of any Collateral or proceeds in any Insolvency or Liquidation Proceeding, or upon the application of any Collateral or proceeds upon the dissolution or liquidation of Milagro or any Guarantor or through any other exercise of remedies, at any time prior to the Discharge of Priority Lien Obligations secured, or intended to be secured, by such Collateral, then it will hold such Collateral, proceeds or payment in trust for the Priority Lien Collateral Agent and the holders of Priority Lien Obligations and transfer such Collateral, proceeds or payment, as the case may be, to the Priority Lien Collateral Agent reasonably promptly after obtaining written notice from the Priority Lien Collateral Agent or any holder of Priority Lien Obligations that it has possession of such Collateral, or proceeds or payment in respect thereof. The collateral trustee and each holder of Parity Lien Obligations will further agree that if, at any time, it obtains written notice that all or part of any payment with respect to any Priority Lien Obligations previously made shall be rescinded for any reason whatsoever, it will promptly pay over to the Priority Lien Collateral Agent any payment received by it and then in its possession or under its direct control in respect of any such Priority Lien Collateral and shall promptly turn any such Collateral then held by it over to the Priority Lien Collateral Agent, and the provisions set forth in the intercreditor agreement will be reinstated as

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if such payment had not been made, until the Discharge of Priority Lien Obligations. All Parity Liens and other junior priority Liens will remain attached to and enforceable against all proceeds so held or remitted, subject to the priorities set forth in the intercreditor agreement. The intercreditor agreement provides that the provisions described in this paragraph will not apply to any proceeds of Collateral realized in a transaction not prohibited by the Priority Lien Documents and as to which the possession or receipt thereof by the collateral trustee or other holder of is otherwise permitted by the Priority Lien Documents.

Automatic Release of Parity Liens

The intercreditor agreement provides that the collateral trustee and each holder of Parity Lien Obligations agree that, if the Priority Lien Collateral Agent or the holders of Priority Lien Obligations release their Lien on any Collateral, the Parity Lien on such Collateral securing the Parity Lien Obligations will terminate and be released automatically and without further action if (i) such release is effected in connection with the Priority Lien Collateral Agent’s foreclosure upon, or other exercise of rights or remedies with respect to, such Collateral or (ii) after giving effect to such release and the filing of any additional Mortgages or supplements or amendments to existing Mortgages on or prior to the consummation of such release, the Collateral securing the Parity Lien Obligations shall include Oil and Gas Properties subject to Mortgages over at least 80% of the total Recognized Value of Milagro’s and the Guarantors’ proved Oil and Gas Properties located in the United States and adjacent Federal waters (provided that any release in connection with a sale, transfer or other disposition of Collateral in a transaction or circumstance that complies with the provisions under “— Repurchases at the Option of Holders — Asset Sales” and clauses (1) through (4) under “Collateral Trust Agreement — Release of Liens on Collateral” shall not be subject to the condition in this clause (ii));provided, in the case of each of clauses (i) and (ii), the Parity Liens on such Collateral securing the Parity Lien Obligations shall remain in place (and shall remain subject and subordinate to all Priority Liens securing Priority Lien Obligations, subject to the Priority Lien Cap) with respect to any proceeds of a sale, transfer or other disposition not paid to the holders of Priority Lien Obligations or that remain after the Discharge of Priority Lien Obligations.

Notwithstanding the foregoing, in the event of the release of the Priority Lien Collateral Agent’s Liens on all or substantially all of the Collateral (other than when such release occurs in connection with the Priority Lien Collateral Agent’s foreclosure upon, or other exercise of rights and remedies with respect to, such Collateral), no release of the junior Liens on such Collateral securing the Parity Lien Obligations will be made unless (A) consent to release of such junior Liens has been given by the requisite percentage or number of the holders of Parity Lien Obligations at the time outstanding, as provided for in the applicable Parity Lien Documents, and (B) Milagro has delivered an Officers’ Certificate to the Priority Lien Collateral Agent and the collateral trustee certifying that all such consents have been obtained.

Agreements With Respect to Insolvency or Liquidation Proceedings

If Milagro or any of its Subsidiaries becomes subject to any Insolvency or Liquidation Proceedings and, as debtor(s)-in-possession, moves for approval of financing (“DIP Financing”) to be provided by one or more lenders (the “DIP Lenders”) under Section 364 of the Bankruptcy Code or the use of cash collateral under Section 363 of the Bankruptcy Code, the intercreditor agreement provides that neither the collateral trustee nor any holder of Parity Lien Obligations will raise any objection, contest or oppose, and will waive any claim such Person may now or hereafter have, to any such financing or to the Liens on the Collateral securing the same (“DIP Financing Liens”), or to any use of cash collateral that constitutes Collateral or to any grant of administrative expense priority under Section 364 of the Bankruptcy Code, unless (1) the Priority Lien Collateral Agent or the holders of any Priority Lien Obligations oppose or object to such DIP Financing, such DIP Financing Liens or such use of cash collateral, (2) such DIP Financing Liens are neither senior to, norpari passuwith, the Liens on Collateral securing Priority Lien Obligations or (3) the maximum principal amount of Indebtedness permitted under such DIP Financing exceeds the sum of (x) the amount of Priority Lien Obligations refinanced with the proceeds thereof and (y) $30,000,000. To the extent such DIP Financing Liens are senior to, or rankpari passuwith, the Liens on Collateral securing Priority Lien Obligations, the collateral trustee will, for itself and on behalf of holders of the Parity Lien Obligations, subordinate the Liens

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on the Collateral that secure the Parity Lien Obligations to the Liens on the Collateral that secure Priority Lien Obligations and to such DIP Financing Liens, so long as the collateral trustee, on behalf of holders of the Parity Lien Obligations, retain Liens on all the Collateral, including proceeds thereof arising after the commencement of any Insolvency or Liquidation Proceeding, with the same priority as existed prior to the commencement of the case under the Bankruptcy Code. Furthermore, the intercreditor agreement provides that without the consent of the Priority Lien Collateral Agent, neither the collateral trustee nor any holder of Parity Lien Obligations will propose, support or enter into any DIP Financing, if the effect of such DIP Financing would be that the Parity Lien Obligations would no longer be subordinated to the Priority Lien Obligations in the manner set forth in the intercreditor agreement, or the holders of Parity Lien Obligations would recover any payments they are not otherwise entitled to under the intercreditor agreement, including by way of adequate protection.

The intercreditor agreement provides that the collateral trustee and each holder of Parity Lien Obligations will not object to, oppose or contest (or join with or support any third party objecting to, opposing or contesting) a sale or other disposition of any Collateral (or any portion thereof) under Section 363 of the Bankruptcy Code or any other provision of the Bankruptcy Code if (1) the Priority Lien Collateral Agent or the requisite holders of Priority Lien Obligations shall have consented to such sale or disposition of such Collateral and (2) all junior Liens on the Collateral securing the Parity Lien Obligations shall attach to the proceeds of such sale in the same respective priorities as set forth in the intercreditor agreement with respect to the Collateral. The intercreditor agreement further provides that the collateral trustee and the holders of Parity Lien Obligations will waive any claim that may be had against the Priority Lien Collateral Agent or any holder of Priority Lien Obligations arising out of any DIP Financing Liens (granted in a manner that is consistent with the intercreditor agreement) or administrative expense priority under Section 364 of the Bankruptcy Code. The intercreditor agreement further provides that the collateral trustee and the holders of Parity Lien Obligations will not file or prosecute in any Insolvency or Liquidation Proceeding any motion for adequate protection (or any comparable request for relief) based upon their interest in the Collateral, and will not object to, oppose or contest (or join with or support any third party objecting to, opposing or contesting) (a) any request by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations for adequate protection or (b) any objection by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations to any motion, relief, action or proceeding based on the Priority Lien Collateral Agent or any holder of Priority Lien Obligations claiming a lack of adequate protection, except that the collateral trustee and the holders of Parity Lien Obligations:

(1) may freely seek and obtain relief granting a junior Lien on Collateral co-extensive in all respects with, but subordinated to, all Liens granted in the Insolvency or Liquidation Proceeding to, or for the benefit of, the holders of the Priority Lien Obligations; and

(2) may freely seek and obtain any relief upon a motion for adequate protection (or any comparable relief), without any condition or restriction whatsoever, at any time after the Discharge of Priority Lien Obligations.

In any Insolvency or Liquidation Proceeding, neither the collateral trustee nor any holder of Parity Lien Obligations shall support or vote for any plan of reorganization or disclosure statement of Milagro or any Guarantor unless (x) such plan is accepted by the class of holders of the Priority Lien Obligations in accordance with Section 1126(c) of the Bankruptcy Code or otherwise provides for the payment in full in cash of all Priority Lien Obligations (including all post-petition interest, fees and expenses) on the effective date of such plan of reorganization, or (y) such plan provides on account of the holders of the Priority Lien Obligations for the retention by the Priority Lien Collateral Agent, for the benefit of the holders of the Priority Lien Obligations, of the Liens on the Collateral securing the Priority Lien Obligations, and on all proceeds thereof, and such plan also provides that any Liens retained by, or granted to, the collateral trustee are only on property securing the Priority Lien Obligations and shall have the same relative priority with respect to the Collateral or other property, respectively, as provided in the intercreditor agreement with respect to the Collateral, and to the extent such plan provides for deferred cash payments, or for the distribution of any other property of any kind or nature, on account of the Priority Lien Obligations or the Parity Lien Obligations, such plan provides that any such deferred cash payments or other distributions in respect of the Parity Lien

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Obligations shall be delivered to the Priority Lien Collateral Agent and distributed in accordance with the priorities provided in the intercreditor agreement. Except as previously provided, the holders of the Parity Lien Obligations shall remain entitled to vote their claims in any such Insolvency or Liquidation Proceeding.

The intercreditor agreement additionally provides that the collateral trustee and each holder of Parity Lien Obligations will waive any claim that may be had against the Priority Lien Collateral Agent or any holder of any Priority Lien Obligations arising out of any election by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in any proceeding instituted under the Bankruptcy Code, of the application of Section 1111(b) of the Bankruptcy Code.

Notwithstanding the foregoing, during an Insolvency or Liquidation Proceeding, the collateral trustee and the holders of Parity Lien Obligations may take any actions and exercise any and all rights that would be available to a holder of unsecured claims;provided, that the collateral trustee and the holders of Parity Lien Obligations may not take any of the actions specifically prohibited by the provisions described in the first two paragraphs of this section captioned “— Agreement With Respect to Insolvency or Liquidation Proceedings” or by clauses (1) through (9) under the caption “— No Interference; Payment Over; Reinstatement”;provided, that in the event that the collateral trustee or any holder of Parity Lien Obligations becomes a judgment lien creditor in respect of the Collateral, as a result of its enforcement of its rights as an unsecured creditor with respect to the Parity Lien Obligations, such judgment lien shall be subject to the terms of the intercreditor agreement for all purposes (including in relation to the Priority Lien Obligations) as the other Liens securing the Parity Lien Obligations are subject to the intercreditor agreement.

Notice Requirements and Procedural Provisions

The intercreditor agreement also provides for various advance notice requirements and other procedural provisions typical for agreements of this type, including procedural provisions which allows any successor Priority Lien Collateral Agent to become a party to the intercreditor agreement (without the consent of any holder of Priority Lien Obligations or Parity Lien Obligations (including holders of the notes) ) upon the refinancing or replacement of the Priority Lien Obligations or Priority Lien Debt Obligations as permitted by the applicable Priority Lien Documents.

No New Liens; Similar Documents

So long as the Discharge of Priority Lien Obligations has not occurred, neither Milagro nor any Subsidiary shall grant or permit any additional Liens, or take any action to perfect any additional Liens, on any property to secure any Parity Lien Obligation unless it has also granted, or contemporaneously grants, a Lien on such property to secure the Priority Lien Obligations and has taken all actions required to perfect such Liens. To the extent that the foregoing provisions are not complied with for any reason, without limiting any other rights and remedies available to the Priority Lien Collateral Agentand/or the other holders of Priority Lien Obligations, the collateral trustee and the holders of Priority Lien Obligations agree that any amounts received by or distributed to any of them pursuant to or as a result of Liens granted in contravention of this paragraph shall be subject to the intercreditor agreement. The intercreditor agreement has reciprocal provisions as to the granting of Liens to holders of Priority Lien Obligations and Parity Lien Obligations. The intercreditor agreement also provides for further undertakings by the collateral trustee and the Priority Lien Collateral Agent and agreements that all security documents providing for the Parity Liens and the Priority Liens shall be in all material respects the same forms of documents other than as the priority nature, other modifications that make the security documents with respect to the Parity Liens less restrictive than the corresponding documents with respect to the Priority Liens and provisions in the security documents for the Parity Liens which relate solely to rights and duties of the collateral trustee and the holders of the Parity Lien Obligations.

Insurance

Unless and until the Discharge of Priority Lien Obligations has occurred (but subject to the rights of the collateral trustee and the holders of Parity Lien Obligations following expiration of the Standstill Period as

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provided in the paragraph defining “Standstill Period”), the Priority Lien Collateral Agent shall have the sole and exclusive right, subject to the rights of the obligors under the Priority Lien Documents, to adjust and settle claims in respect of Collateral under any insurance policy in the event of any loss thereunder and to approve any award granted in any condemnation or similar proceeding (or any deed in lieu of condemnation) affecting the Collateral. Unless and until the Discharge of Priority Lien Obligations has occurred, and subject to the rights of the obligors under the Priority Lien security documents, all proceeds of any such policy and any such award (or any payments with respect to a deed in lieu of condemnation) in respect to the Collateral shall be paid to the Priority Lien Collateral Agent pursuant to the terms of the Priority Lien Documents (including for purposes of cash collateralization of commitments, letters of credit and Hedge Agreements) and, after the Discharge of Priority Lien Obligations has occurred, to the collateral trustee to the extent required under the Parity Lien security documents and then, to the extent no Parity Lien Obligations are outstanding, to the owner of the subject property, to such other person as may be entitled thereto or as a court of competent jurisdiction may otherwise direct. If the collateral trustee or any holder of Parity Lien Obligations shall, at any time, receive any proceeds of any such insurance policy or any such award or payment in contravention of the foregoing, it shall pay such proceeds over to the Priority Lien Collateral Agent in accordance with the intercreditor agreement. In addition, if by virtue of being named as an additional insured or loss payee of any insurance policy of any obligor covering any of the Collateral, the collateral trustee or any other holder of Parity Lien Obligations shall have the right to adjust or settle any claim under any such insurance policy, then unless and until the Discharge of Priority Lien Obligations has occurred, the collateral trustee and any such holder of Parity Lien Obligations shall follow the instructions of the Priority Lien Collateral Agent, or of the obligors under the Priority Lien Documents to the extent the Priority Lien Documents grant such obligors the right to adjust or settle such claims, with respect to such adjustment or settlement (subject to the rights of the collateral trustee and the holders of Parity Lien Obligations following expiration of the Standstill Period as provided in the paragraph defining “Standstill Period”).

Amendment to Parity Lien Documents

Without the prior written consent of the Priority Lien Collateral Agent, no Parity Lien Document may be amended, supplemented, restated or otherwise modifiedand/or refinanced or entered into to the extent such amendment, supplement, restatement or other modificationand/or refinancing, or the terms of any new Parity Lien Document, would contravene the provisions of the intercreditor agreement or the Priority Lien Documents.

Automatic Stay; Post Petition Interest; Section 506 of the Bankruptcy Code

Until the Discharge of Priority Lien Obligations has occurred, neither collateral trustee nor any holder of Parity Lien Obligations shall seek relief, pursuant to Section 362(d) of the Bankruptcy Code or otherwise, from the automatic stay of Section 362(a) of the Bankruptcy Code or from any other stay in any Insolvency or Liquidation Proceeding in respect of the Collateral, without the prior written consent of the Priority Lien Collateral Agent.

Neither collateral trustee nor any holder of Parity Lien Obligations shall oppose or seek to challenge any claim by the Priority Lien Collateral Agent or any other holder of Priority Lien Obligations for allowance or payment in any Insolvency or Liquidation Proceeding of Priority Lien Obligations consisting of post-petition interest, fees or expenses to the extent of the value of the Priority Liens (it being understood that such value will be determined without regard to the existence of the Parity Liens on the Collateral). Neither Priority Lien Collateral Agent nor any holder of Priority Lien Obligations shall oppose or seek to challenge any claim by the collateral trustee or any other holder of Parity Lien Obligations for allowance or payment in any Insolvency or Liquidation Proceeding of Parity Lien Obligations consisting of post-petition interest, fees or expenses to the extent of the value of the Parity Liens on the Collateral;provided, that if the Priority Lien Collateral Agent or any holder of Priority Lien Obligations shall have made any such claim, such claim (i) shall have been approved or (ii) will be approved contemporaneously with the approval of any such claim by the collateral trustee or any holder of Parity Lien Obligations.

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So long as the Discharge of Priority Lien Obligations has not occurred, without the express written consent of the Priority Lien Collateral Agent, neither collateral trustee nor any holder of Parity Lien Obligations shall (or shall join with or support any third party in opposing, objecting to or contesting, as the case may be), in any Insolvency or Liquidation Proceeding involving any Grantor, (i) oppose, object to or contest the determination of the extent of any Liens held by any of holder of Priority Lien Obligations or the value of any claims of any such holder under Section 506(a) of the Bankruptcy Code or (ii) oppose, object to or contest the payment to the holder of Priority Lien Obligations of interest, fees or expenses under Section 506(b) of the Bankruptcy Code.

Purchase Option

Notwithstanding anything in the intercreditor agreement to the contrary, on or at any time after (i) the commencement of an insolvency, bankruptcy or liquidation proceeding or (ii) the acceleration of the Priority Lien Obligations, each of the holders of notes and each of their respective designated affiliates (the “purchasers”) will have the right, at their sole option and election (but will not be obligated), at any time upon prior written notice to the applicable Priority Lien Representative, to purchase from the holders of the Priority Lien Obligations all (but not less than all) Priority Lien Obligations (including unfunded commitments) that are outstanding on the date of such purchase. Promptly following the receipt of such notice, the applicable Priority Lien Representative will deliver to the trustee a statement of the amount of Priority Lien Debt and other Priority Lien Obligations then outstanding and the amount of the cash collateral requested by the applicable Priority Lien Representative to be delivered pursuant to clause (2) of the immediately following paragraph. The right to purchase provided for in this paragraph will expire unless, within 10 business days after the receipt by the trustee of such notice from the applicable Priority Lien Representative, the trustee delivers to the applicable Priority Lien Representative an irrevocable commitment of the purchasers to purchase all (but not less than all) and to otherwise complete the purchase on the terms set forth under this provision.

On the date specified by the trustee (on behalf of the purchasers) in such irrevocable commitment (which shall not be less than five business days, nor more than 20 business days, after the receipt by the collateral trustee of such irrevocable commitment), the holders of the Priority Lien Obligations shall sell to the purchasers all (but not less than all) Priority Lien Obligations (including unfunded commitments) that are outstanding on the date of such sale, subject to any required approval of any court or other regulatory or governmental authority then in effect, if any, and only if on the date of such sale, the applicable Priority Lien Representative receives the following:

(1) payment, as the purchase price for all Priority Lien Obligations sold in such sale, of an amount equal to the full amount of all Priority Lien Obligations (other than outstanding letters of credit) then outstanding (including principal, interest, fees, reasonable attorneys’ fees and legal expenses, but excluding contingent indemnification obligations for which no claim or demand for payment has been made at or prior to such time);provided, that in the case of Hedging Obligations that constitute Priority Lien Obligations, the purchasers shall cause the applicable Hedge Agreements to be assigned and novated or, if such Hedging Agreements have been terminated, such purchase price shall include an amount equal to the sum of any unpaid amounts then due in respect of such Hedging Obligations, calculated using the market quotation method and after giving effect to any netting arrangements;

(2) a cash collateral deposit in such amount as the applicable Priority Lien Representative determines is reasonably necessary to secure the payment of any outstanding letters of credit constituting Priority Lien Debt that may become due and payable after such sale (but not in any event in an amount greater than one hundred five (105%) percent of the amount then reasonably estimated by the applicable Priority Lien Representative to be the aggregate outstanding amount of such letters of credit at such time), which cash collateral shall be (A) held by the applicable Priority Lien Representative as security solely to reimburse the issuers of such letters of credit that become due and payable after such sale and any fees and expenses incurred in connection with such letters of credit and (B) returned to the trustee (except as may otherwise be required by applicable law or any order of any court or other governmental

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authority) promptly after the expiration or termination from time to time of all payment contingencies affecting such letters of credit; and

(3) any agreements, documents or instruments which the applicable Priority Lien Representative may reasonably request pursuant to which the trustee and the purchasers in such sale expressly assume and adopt all of the obligations of the applicable Priority Lien Representative and the holders of the Priority Lien Obligations under the Priority Lien Security Documents on and after the date of the purchase and sale and the trustee (or any other representative appointed by the holders of a majority in aggregate principal amount of the notes then outstanding) becomes a successor agent thereunder.

Such purchase of the Priority Lien Obligations shall be made on a pro rata basis among the holders of the notes (and their respective designated affiliates) giving notice to the applicable Priority Lien Representative of their interest to exercise the purchase option hereunder according to each such holder’s portion of the notes outstanding on the date of purchase. Such purchase price and cash collateral shall be remitted by wire transfer in federal funds to such bank account of the applicable Priority Lien Representative as the applicable Priority Lien Representative may designate in writing to the trustee for such purpose. Interest shall be calculated to but excluding the business day on which such sale occurs if the amounts so paid by the trustee and holders of the notes to the bank account designated by the applicable Priority Lien Representative are received in such bank account prior to 12:00 noon, New York City time, and interest shall be calculated to and including such business day if the amounts so paid by the trustee and holders of the notes to the bank account designated by the applicable Priority Lien Representative are received in such bank account later than 12:00 noon, New York City time.

Such sale shall be expressly made without representation or warranty of any kind by the applicable Priority Lien Representative and the holders of Priority Lien Obligations as to the Priority Lien Obligations, the Collateral or otherwise and without recourse to the applicable Priority Lien Representative and the holders of Priority Lien Obligations, except that the applicable Priority Lien Representative and the holders of Priority Lien Obligations shall represent and warrant severally as to the Priority Lien Obligations then owing to it: (i) that the applicable Priority Lien Representative and such holders of the Priority Lien Obligations own the Priority Lien Obligations; and (ii) the applicable Priority Lien Representative and such holders of the Priority Lien Obligations have the necessary corporate or other governing authority to assign such interests.

After such sale becomes effective, the outstanding letters of credit will remain enforceable against the issuers thereof and will remain secured by the Priority Liens upon the Collateral in accordance with the applicable provisions of the Priority Lien Documents as in effect at the time of such sale, and the issuers of letters of credit will remain entitled to the benefit of the Priority Liens upon the Collateral and sharing rights in the proceeds thereof in accordance with the provisions of the Priority Lien Documents as in effect at the time of such sale, as fully as if the sale of the Priority Lien Debt had not been made, but only the person or successor agent to whom the Priority Liens are transferred in such sale will have the right to foreclose upon or otherwise enforce the Priority Liens and only the purchasers in the sale will have the right to direct such person or successor as to matters relating to the foreclosure or other enforcement of the Priority Liens.

Postponement of Subrogation

The intercreditor agreement provides that no payment or distribution to any holder of Priority Lien Obligations, pursuant to the provisions of the intercreditor agreement, entitles the collateral trustee or any holder of Parity Lien Obligations to exercise any rights of subrogation in respect thereof until the Discharge of Priority Lien Obligations shall have occurred. Following the Discharge of Priority Lien Obligations, each holder of Priority Lien Obligations will execute such documents, agreements, and instruments as any holder of Parity Lien Obligations may reasonably request to evidence the transfer by subrogation to any such person of an interest in the Priority Lien Obligations resulting from payments or distributions to such holder by such person, so long as all costs and expenses (including all reasonable legal fees and disbursements) incurred in connection therewith by such holder of Priority Lien Obligations are paid by such person upon request for payment thereof

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Collateral Trust Agreement

Enforcement of Liens

If the collateral trustee at any time receives written notice from a Parity Lien Representative stating that any event has occurred that constitutes a default under any Parity Lien Document entitling the collateral trustee to foreclose upon, collect or otherwise enforce its Liens under the security documents, it will promptly deliver written notice thereof to each other Parity Lien Representative. Thereafter, the collateral trustee may await direction by an Act of Parity Lien Debtholders and, subject to the terms of the intercreditor agreement, will act, or decline to act, as directed by an Act of Parity Lien Debtholders, in the exercise and enforcement of the collateral trustee’s interests, rights, powers and remedies in respect of the Collateral or under the security documents or applicable law and, following the initiation of such exercise of remedies, the collateral trustee will act, or decline to act, with respect to the manner of such exercise of remedies as directed by an Act of Parity Lien Debtholders. Unless it has been directed to the contrary by an Act of Parity Lien Debtholders, the collateral trustee in any event may (but will not be obligated to) take or refrain from taking such action with respect to any default under any Parity Lien Document as it may deem advisable and in the best interest of the holders of Parity Lien Obligations.

Order of Application

The collateral trust agreement provides that if any Collateral is sold or otherwise realized upon by the collateral trustee in connection with any foreclosure, collection or other enforcement of Liens granted to the collateral trustee in the security documents, subject to the terms of the intercreditor agreement, the proceeds received by the collateral trustee from such foreclosure, collection or other enforcement and the proceeds of any title or other insurance policy received by the collateral trustee will be distributed by the collateral trustee in the following order of application:

FIRST, to the payment of all amounts payable under the collateral trust agreement on account of the collateral trustee’s fees and any reasonable legal fees, costs and expenses or other liabilities of any kind incurred by the collateral trustee or any co-trustee or agent of the collateral trustee in connection with any security document (including, but not limited to, indemnification obligations);

SECOND, to the repayment of Indebtedness and other Obligations, other than Secured Debt, secured by a Permitted Prior Lien on the Collateral sold or realized upon to the extent that such Indebtedness or other Obligation is intended to be discharged (in whole or in part) in connection with such sale;

THIRD, to the respective Parity Lien Representatives equally and ratably for application to the payment of all outstanding Parity Lien Debt and any other Parity Lien Obligations that are then due and payable in such order as may be provided in the Parity Lien Documents in an amount sufficient to pay in full in cash all outstanding Parity Lien Debt and all other Parity Lien Obligations that are then due and payable (including, to the extent legally permitted, all interest accrued thereon after the commencement of any insolvency or liquidation proceeding at the rate, including any applicable post-default rate, specified in the Parity Lien Documents, even if such interest is not enforceable, allowable or allowed as a claim in such proceeding, and including the discharge or cash collateralization (at the lower of (1) 105% of the aggregate undrawn amount and (2) the percentage of the aggregate undrawn amount required for release of Liens under the terms of the applicable Parity Lien Document) of all outstanding letters of credit, if any, constituting Parity Lien Debt); and

FOURTH, any surplus remaining after the payment in full in cash of the amounts described in the preceding clauses will be paid to Milagro or the applicable Guarantor, as the case may be, its successors or assigns, or as a court of competent jurisdiction may direct.

The provisions set forth above under this caption “— Order of Application” are intended for the benefit of, and will be enforceable as a third party beneficiary by, each present and future holder of Parity Lien Obligations, each present and future Parity Lien Debt Representative and the collateral trustee as holder of Parity Liens. The Parity Lien Representative of each future Series of Parity Lien Debt will be required to

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deliver an Additional Secured Debt Designation to the collateral trustee and each other Parity Lien Representative at the time of incurrence of such Series of Parity Lien Debt.

Release of Liens on Collateral

The collateral trust agreement provides that the collateral trustee’s Liens on the Collateral will be released:

(1) in whole, upon (a) payment in full and discharge of all outstanding Parity Lien Debt and all other Parity Lien Obligations that are outstanding, due and payable at the time all of the Parity Lien Debt is paid in full and discharged, (b) termination or expiration of all commitments to extend credit under all Parity Lien Documents and (c) the cancellation or termination or cash collateralization (at the lower of (1) 105% of the aggregate undrawn amount and (2) the percentage of the aggregate undrawn amount required for release of Liens under the terms of the applicable Parity Lien Documents) of all outstanding letters of credit issued pursuant to any Parity Lien Documents;

(2) as to any Collateral that is sold, transferred or otherwise disposed of by Milagro or any Guarantor to a Person that is not (either before or after such sale, transfer or disposition) Milagro or a Restricted Subsidiary of Milagro in a transaction or other circumstance that complies with the provisions described under the caption “— Repurchases at the Option of Holders — Asset Sales” below (other than the obligation to apply proceeds of such Asset Sale as provided in such provision) and is permitted by all of the other Parity Lien Documents, at the time of such sale, transfer or other disposition or to the extent of the interest sold, transferred or otherwise disposed of;provided, that the collateral trustee’s Liens upon the Collateral will not be released if the sale or disposition is subject to the covenant described below under the caption “— Certain Covenants — Merger, Consolidation or Sale of Assets”;

(3) as to a release of less than all or substantially all of the Collateral, if consent to the release of all Parity Liens on such Collateral has been given by an Act of Parity Lien Debtholders;

(4) as to a release of all or substantially all of the Collateral, if (a) consent to the release of that Collateral has been given by the requisite percentage or number of holders of each Series of Parity Debt at the time outstanding as provided for in the applicable Parity Lien Documents, and (b) Milagro has delivered an officers’ certificate to the collateral trustee certifying that all such necessary consents have been obtained; and

(5) if and to the extent required by the provisions of the intercreditor agreement described above under the caption “— The Intercreditor Agreement — Automatic Release of Parity Liens.”

The security documents provide that the Liens securing the Secured Debt will extend to the proceeds of any sale of Collateral. As a result, subject to the provisions of the intercreditor agreement, the collateral trustee’s Liens will apply to the proceeds of any such Collateral received in connection with any sale or other disposition of assets described in the preceding paragraph.

Release of Liens in Respect of Notes

The indenture and the collateral trust agreement provide that the collateral trustee’s Parity Liens upon the Collateral will no longer secure the notes outstanding under the indenture or any other Obligations under the indenture, and the right of the holders of the notes and such Obligations to the benefits and proceeds of the collateral trustee’s Parity Liens on the Collateral will terminate and be discharged:

(1) upon satisfaction and discharge of the indenture as set forth under the caption “— Satisfaction and Discharge”;

(2) upon a Legal Defeasance or Covenant Defeasance of the notes as set forth under the caption “— Legal Defeasance and Covenant Defeasance”;

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(3) upon payment in full and discharge of all notes outstanding under the indenture and all Obligations that are outstanding, due and payable under the indenture at the time the notes are paid in full and discharged;

(4) in whole or in part, with the consent of the holders of the requisite percentage of notes in accordance with the provisions described below under the caption “— Amendment, Supplement and Waiver”; or

(5) if and to the extent required by the provisions of the intercreditor agreement described under the caption “— The Intercreditor Agreement — Automatic Release of Parity Liens.”

Release of Liens in Respect of any Series of Parity Lien Debt Other than the Notes

The collateral trust agreement provides that, as to any Series of Parity Lien Debt other than the notes, the collateral trustee’s Parity Lien no longer secures such Series of Parity Lien Debt if such Parity Lien Debt has been repaid in full, all commitments to extend credit in respect of such Series of Parity Lien Debt have been terminated and all other Parity Lien Obligations related thereto that are outstanding and unpaid at the time such Series of Parity Lien Debt is paid are also paid in full.

Amendment of Security Documents

The collateral trust agreement provides that no amendment or supplement to the provisions of any security document that secures the Parity Lien Obligations will be effective without the approval of the collateral trustee acting as directed by an Act of Parity Lien Debtholders, except that:

(1) any amendment or supplement that has the effect solely of

(a) adding or maintaining Collateral, securing additional Parity Lien Debt that was otherwise permitted by the terms of the Parity Lien Documents to be secured by the Collateral or preserving, perfecting or establishing the Liens thereon or the rights of the collateral trustee therein; or

(b) providing for the assumption of any Guarantor’s obligations under any Parity Lien Document in the case of a merger or consolidation or sale of all or substantially all of the assets of such Guarantor to the extent permitted by the terms of the indenture governing the notes and the other Parity Lien Documents, as applicable;

will become effective when executed and delivered by Milagro or any other applicable grantor party thereto and the collateral trustee;

(2) no amendment or supplement that reduces, impairs or adversely affects the right of any holder of Parity Lien Obligations:

(a) to vote its outstanding Parity Lien Debt as to any matter described as subject to an Act of Parity Lien Debtholders or direction by the Required Parity Lien Debtholders (or amends the provisions of this clause (2) or the definition of “Act of Parity Lien Debtholders” or “Required Parity Lien Debtholders”),

(b) to share in the order of application described above under “— Order of Application” in the proceeds of enforcement of or realization on any Collateral, or

(c) to require that Liens securing Parity Lien Obligations be released only as set forth in the provisions described above under the caption “— Release of Liens on Collateral,”

will become effective without the consent of the requisite percentage or number of holders of each Series of Parity Lien Debt adversely affected thereby under the applicable Parity Lien Document; and

(3) no amendment or supplement that imposes any obligation upon the collateral trustee or any Parity Lien Representative or adversely affects the rights of the collateral trustee or any Parity Lien Representative, respectively, in its individual capacity as such will become effective without the consent of the collateral trustee or such Parity Lien Representative, respectively.

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Any amendment or supplement to the provisions of the security documents securing the Parity Lien Obligations that releases Collateral will be effective only in accordance with the requirements set forth in the applicable Parity Lien Document referenced above under the caption “— Release of Liens on Collateral.” Any amendment or supplement that results in the collateral trustee’s Liens upon the Collateral no longer securing the notes and the other Obligations under the indenture may only be effected in accordance with the provisions described above under the caption “— Release of Liens in Respect of Notes.”

The collateral trust agreement and the intercreditor agreement provide that, notwithstanding anything to the contrary under the caption “— Amendment of Security Documents,” but subject to clauses (2) and (3) above:

(1) any mortgage or other security document that secures Parity Lien Obligations may be amended or supplemented with the approval of the collateral trustee acting as directed in writing by the Required Parity Lien Debtholders, unless such amendment or supplement would not be permitted under the terms of the intercreditor agreement or any Priority Lien Documents; and

(2) any amendment or waiver of, or any consent under, any provision of any security document that secures Priority Lien Obligations will apply automatically to any comparable provision of any comparable Parity Lien Document without the consent of or notice to any holder of Parity Lien Obligations and without any action by Milagro or any Guarantor or any holder of notes or other Parity Lien Obligations.

Voting

In connection with any matter under the collateral trust agreement requiring a vote of holders of Parity Lien Debt, each Series of Parity Lien Debt will cast its votes in accordance with the Parity Lien Documents governing such Series of Parity Lien Debt. The amount of Parity Lien Debt to be voted by a Series of Parity Lien Debt will equal (1) the aggregate principal amount of Parity Lien Debt held by such Series of Parity Lien Debt (including outstanding letters of credit whether or not then available or drawn),plus(2) other than in connection with an exercise of remedies, the aggregate unfunded commitments to extend credit which, when funded, would constitute Indebtedness of such Series of Parity Lien Debt. Following and in accordance with the outcome of the applicable vote under its Parity Lien Documents, the Parity Lien Representative of each Series of Parity Lien Debt will vote the total amount of Parity Lien Debt under that Series as a block in respect of any vote under the collateral trust agreement.

Provisions of the Indenture Relating to Security

Equal and Ratable Sharing of Collateral by Holders of Parity Lien Debt

The indenture will provide that, notwithstanding:

(1) anything to the contrary contained in the security documents;

(2) the time of incurrence of any Series of Parity Lien Debt;

(3) the order or method of attachment or perfection of any Liens securing any Series of Parity Lien Debt;

(4) the time or order of filing or recording of financing statements, mortgages or other documents filed or recorded to perfect any Lien upon any Collateral;

(5) the time of taking possession or control over any Collateral;

(6) that any Parity Lien may not have been perfected or may be or have become subordinated, by equitable subordination or otherwise, to any other Lien; or

(7) the rules for determining priority under any law governing relative priorities of Liens:

all Parity Liens granted at any time by Milagro or any Guarantor will secure, equally and ratably, all present and future Parity Lien Obligations.

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This section is intended for the benefit of, and will be enforceable as a third party beneficiary by, each present and future holder of Parity Lien Obligations, each present and future Parity Lien Representative and the collateral trustee as holder of Parity Liens. The Parity Lien Representative of each future Series of Parity Lien Debt will be required to deliver an Additional Secured Debt Designation to the collateral trustee and the trustee at the time of incurrence of such Series of Parity Lien Debt.

Relative Rights

Nothing in the Note Documents will:

(1) impair, as between Milagro and the holders of the notes, the obligation of Milagro to pay principal of, premium, accrued and unpaid interest and Special Interest, if any, on the notes in accordance with their terms or any other obligation of Milagro or any Guarantor;

(2) affect the relative rights of holders of notes as against any other creditors of Milagro or any Guarantor (other than holders of Priority Liens, Permitted Prior Liens or other Parity Liens);

(3) restrict the right of any holder of notes to sue for payments that are then due and owing (but not enforce any judgment in respect thereof against any Collateral to the extent specifically prohibited by the provisions described above under the captions “— The Intercreditor Agreement — Limitation on Enforcement of Remedies,” “— The Intercreditor Agreement — No Interference; Payment Over; Reinstatement,” and “— The Intercreditor Agreement — Agreements With Respect to Insolvency or Liquidation Proceedings;”

(4) restrict or prevent any holder of notes or other Parity Lien Obligations, the collateral trustee or any Parity Lien Representative from exercising any of its rights or remedies upon a Default or Event of Default not specifically restricted or prohibited by the provisions above described under the captions “— The Intercreditor Agreement — Limitation on Enforcement of Remedies,” “— The Intercreditor Agreement — No Interference; Payment Over; Reinstatement,” “— The Intercreditor Agreement — Agreements With Respect to Insolvency or Liquidation Proceedings,” or “— Collateral Trust Agreement — Enforcement of Liens”; or

(5) restrict or prevent any holder of notes or other Parity Lien Obligations, the collateral trustee or any Parity Lien Representative from taking any lawful action in an insolvency or liquidation proceeding not specifically restricted or prohibited by the provisions above described under the captions “— The Intercreditor Agreement — Agreements With Respect to Insolvency or Liquidation Proceedings” or “— Collateral Trust Agreement — Enforcement of Liens”.

Compliance with Trust Indenture Act

The indenture will provide that Milagro will comply with the provisions of TIA §314.

To the extent applicable, Milagro will cause TIA §313(b), relating to reports, and TIA §314(d), relating to the release of property or securities subject to the Lien of the security documents, to be complied with. Any certificate or opinion required by TIA §314(d) may be made by an officer of Milagro except in cases where TIA §314(d) requires that such certificate or opinion be made by an independent Person, which Person will be an independent engineer, appraiser or other expert selected by Milagro. Notwithstanding anything to the contrary in this paragraph, Milagro will not be required to comply with all or any portion of TIA §314(d) if it determines, in good faith based on advice of counsel, that under the terms of TIA §314(d)and/or any interpretation or guidance as to the meaning thereof of the SEC and its staff, including “no action” letters or exemptive orders, all or any portion of TIA §314(d) is inapplicable to one or a series of released Collateral.

Further Assurances; Liens on Additional Property

The indenture and the security documents will provide that Milagro and each of the Guarantors will do or cause to be done all acts and things that may be required, or that the collateral trustee from time to time may reasonably request, to assure and confirm that the collateral trustee holds, for the benefit of the holders of

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Parity Lien Obligations, duly created and enforceable and perfected Liens upon the Collateral (including any property or assets that are acquired or otherwise become, or are required by any Parity Lien Document to become, Collateral after the notes are issued), in each case, as contemplated by, and with the Lien priority required under, the Parity Lien Documents.

Upon the reasonable request of the collateral trustee or any Parity Lien Representative at any time and from time to time, Milagro and each of the Guarantors will promptly execute, acknowledge and deliver such security documents, instruments, certificates, notices and other documents, and take such other actions as shall be reasonably required, or that the collateral trustee may reasonably request, to create, perfect, protect, assure or enforce the Liens and benefits intended to be conferred, in each case as contemplated by the Parity Lien Documents for the benefit of the holders of Parity Lien Obligations;provided, that no such security document, instrument or other document shall be materially more burdensome upon Milagro and the Guarantors than the Parity Lien Documents executed and delivered by Milagro and the Guarantors in connection with the issuance of the notes on or about the Issue Date.

The indenture will provide that if at any time of certification by Milagro with respect to the Recognized Value of Oil and Gas Properties subject to a Mortgage as described under “— Security”, such Oil and Gas Properties represent less than 80% of the Recognized Value of Milagro’s and the Guarantors’ proved Oil and Gas Properties located in the United States and adjacent Federal waters, Milagro will promptly, and in any event within 90 days after the date of such certification, cause to be delivered to the collateral trustee (in form and substance reasonably satisfactory to the collateral trustee) such Mortgages or amendments or supplements to prior Mortgages as may be necessary to increase such percentage to at least 80% of such Recognized Value.

Insurance

Milagro and the Guarantors will:

(1) keep their properties insured at all times by financially sound and reputable insurers;

(2) maintain such other insurance, to such extent and against such risks (and with such deductibles, retentions and exclusions), including fire and other risks insured against by extended coverage and coverage for acts of terrorism, as is customary with companies in the same or similar businesses operating in the same or similar locations, including public liability insurance against claims for personal injury or death or property damage occurring upon, in, about or in connection with the use of any properties owned, occupied or controlled by them; and

(3) maintain such other insurance as may be required by law.

Upon the request of the collateral trustee, Milagro and the Guarantors will furnish to the collateral trustee information as to their property and liability insurance carriers. Holders of the Parity Lien Obligations, as a class, will be named as additional insureds, with a waiver of subrogation, on all insurance policies of Milagro and the Guarantors, and the collateral trustee will be named as loss payee, with 30 days’ notice of cancellation or material change, on all property and casualty insurance policies of Milagro and the Guarantors. See “— Intercreditor Agreement — Insurance” above.

Optional Redemption

At any time prior to May 15, 2014, Milagro may on any one or more occasions redeem up to 35% of the aggregate principal amount of outstanding notes (which amount includes additional notes issued under the indenture), upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to 110.500% of the principal amount of the notes redeemed, plus accrued and unpaid interest and Special Interest, if any, to the date of redemption (subject to the rights of holders of notes on the relevant record date to receive interest

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on the relevant interest payment date), with the net cash proceeds of an Equity Offering by Milagro;providedthat:

(1) at least 65% of the aggregate principal amount of notes issued under the indenture (which amount includes additional notes, but excluding notes held by Milagro and its Subsidiaries) remains outstanding immediately after the occurrence of such redemption; and

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

At any time prior to May 15, 2014, Milagro may on any one or more occasions redeem all or a part of the notes, upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus the Applicable Premium as of, and accrued and unpaid interest and Special Interest, if any, to the date of redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

Except pursuant to the preceding paragraphs, the notes will not be redeemable at Milagro’s option prior to May 15, 2014.

On or after May 15, 2014, Milagro may on any one or more occasions redeem all or a part of the notes, upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest and Special Interest, if any, on the notes redeemed, to the applicable date of redemption, if redeemed on and after the following dates, subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date:


Year	Percentage

May 15, 2014		110.500	%
May 15, 2015		102.625	%
November 15, 2015		100.000	%

Unless Milagro defaults in the payment of the redemption price, interest will cease to accrue on the notes or portions thereof called for redemption on the applicable redemption date.

Mandatory Redemption

Milagro is not required to make mandatory redemption or sinking fund payments with respect to the notes.

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, each holder of notes will have the right to require Milagro to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) 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, Milagro 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 and Special Interest, if any, on the notes repurchased to the date of purchase, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, Milagro will mail a notice to each holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes on the Change of Control Payment 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. Milagro will comply with the requirements ofRule 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 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, Milagro 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 compliance.

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On or before the Change of Control Payment Date, Milagro will, to the extent lawful:

(1) accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;

(2) 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

(3) 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 Milagro.

The paying agent will promptly mail to each holder of notes properly tendered the Change of Control Payment for such notes, 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. Milagro will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

The provisions described above that require Milagro 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. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the holders of the notes to require that Milagro repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

Milagro will not be required to make a Change of Control Offer upon a Change of Control if (1) 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 Milagro and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, or (2) notice of redemption has been given pursuant to the indenture as described above under the caption “— Optional Redemption,” unless and until there is a default in payment of the applicable redemption price. Notwithstanding anything to the contrary contained herein, a Change of Control Offer may be made in advance of a Change of Control, conditioned upon the consummation of such Change of Control, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer is made.

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 Milagro 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 Milagro to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of Milagro and its Restricted Subsidiaries taken as a whole to another Person or group may be uncertain.

Asset Sales

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

(1) Milagro (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 in the Asset Sale by Milagro or such Restricted Subsidiary is in the form of cash or Cash Equivalents. For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities, as shown on Milagro’s most recent consolidated balance sheet, of Milagro or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms

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subordinated to the notes or any Note Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation or indemnity agreement that releases Milagro or such Restricted Subsidiary from or indemnifies against further liability;

(b) any securities, notes or other obligations received by Milagro or any such Restricted Subsidiary from such transferee that are contemporaneously, subject to ordinary settlement periods, converted by Milagro or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion; and

Within 360 days after the receipt of any Net Proceeds from an Asset Sale, Milagro (or the applicable Restricted Subsidiary, as the case may be) may apply such Net Proceeds:

(i) to repay Priority Lien Debt and other outstanding Priority Lien Obligations;provided, that if such Priority Lien Debt is revolving credit Indebtedness, (A) such payment is required under the terms thereof or (B) there is a corresponding reduction in the commitments with respect thereto;

(ii) to acquire all or substantially all of the assets of, or any Capital Stock of, another Oil and Gas Business, if, after giving effect to any such acquisition of Capital Stock, the Oil and Gas Business is or becomes a Restricted Subsidiary of Milagro;

(iii) to make capital expenditures in the Oil and Gas Business; or

(iv) to acquire other assets that are not classified as current assets under GAAP and that are used or useful in the Oil and Gas Business.

Pending the final application of any Net Proceeds, Milagro (or the applicable 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 second paragraph of this covenant will constitute“Excess Proceeds.”When the aggregate amount of Excess Proceeds exceeds $15.0 million, within five days thereafter, Milagro will make an offer (an“Asset Sale Offer”) to all holders of notes and all holders of other Indebtedness that ispari passuwith the notes containing provisions with respect to offers to purchase, prepay or redeem with the proceeds of sales of assets to purchase, prepay or redeem the maximum principal amount of notes and such otherpari passuIndebtedness (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith) that may be purchased, prepaid or redeemed out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount, plus accrued and unpaid interest and Special Interest, if any, to the date of purchase, prepayment or redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, Milagro may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and otherpari passuIndebtedness tendered in (or required to be prepaid or redeemed in connection with) such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such otherpari passuIndebtedness to be purchased on apro ratabasis, based on the amounts tendered or required to be prepaid or redeemed (with such adjustments as may be deemed appropriate by Milagro so that only notes in denominations of $2,000, or an integral multiple of $1,000 in excess thereof, will be purchased). Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

Milagro will comply with the requirements ofRule 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, Milagro 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 compliance.

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The Credit Agreement contains, and future agreements may contain, prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale and including repurchases of or other prepayments in respect of the notes. The exercise by the holders of notes of their right to require Milagro to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on Milagro. In the event a Change of Control or Asset Sale occurs at a time when Milagro is prohibited from purchasing notes, Milagro could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If Milagro does not obtain a consent or repay those borrowings, Milagro will remain prohibited from purchasing notes. In that case, Milagro’s failure to purchase tendered notes would constitute an Event of Default under the indenture which could, in turn, constitute a default under the other indebtedness. Finally, Milagro’s ability to pay cash to the holders of notes upon a repurchase may be limited by Milagro’s then existing financial resources. See “Risk Factors — We may not have the ability to raise the funds necessary to finance the change of control offer required by the indenture governing the notes.”

Selection and Notice

If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption on apro ratabasis (or, in the case of notes issued in global form as discussed under “— Book-Entry, Delivery and Form,” based on a method that most nearly approximates apro rataselection as the trustee deems fair and appropriate) unless otherwise required by law or applicable stock exchange or depositary requirements.

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.

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 notes called for redemption.

Certain Covenants

Restricted Payments

Milagro 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 Milagro’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving Milagro or any of its Restricted Subsidiaries) or to the direct or indirect holders of Milagro’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 Milagro and other than dividends or distributions payable to Milagro or a Restricted Subsidiary of Milagro);

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

(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Subordinated Obligation or Guarantor Subordinated Obligation, except (x) a payment of interest or principal at the Stated Maturity thereof, (y) intercompany Indebtedness between or among Milagro and any Restricted Subsidiary or between or among Restricted Subsidiaries, or (z) the purchase, redemption, defeasance or other acquisition or retirement of any Subordinated Obligations or Guarantor

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Subordinated Obligations in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of such purchase, repurchase, redemption, defeasance or other acquisition or retirement; 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”),

unless, at the time of and after giving effect to such Restricted Payment:

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

(b) Milagro 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 Fixed Charge 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

(c) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by Milagro and its Restricted Subsidiaries since the date of the indenture (excluding Restricted Payments permitted by clauses (2), (3), (4), (5), (6), (7) and (8) of the next succeeding paragraph) is less than the sum, without duplication, of:

(1) 50% of the Consolidated Net Income of Milagro for the period (taken as one accounting period) from April 1, 2011 to the end of Milagro’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

(2) 100% of the aggregate net cash proceeds received by Milagro since the date of the indenture (i) as a contribution to its common equity capital or from the issue or sale of its Equity Interests (other than Disqualified Stock and other than net cash proceeds received from an issuance or sale of such Equity Interests (x) to a Subsidiary of Milagro or (y) to or under an employee stock ownership plan, option plan or similar trust (to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or guaranteed by Milagro or any Restricted Subsidiary except to the extent such loans have been repaid with cash on or prior to the date of determination)) or (ii) from the issue or sale of convertible or exchangeable Disqualified Stock of Milagro or convertible or exchangeable debt securities of Milagro, in each case that have been converted into or exchanged for Equity Interests of Milagro (other than convertible or exchangeable Disqualified Stock or debt securities sold to a Subsidiary of Milagro);plus

(3) to the extent not already included in Consolidated Net Income for such period, (A) if any Restricted Investment that was made by Milagro or any Restricted Subsidiary after the date of the indenture is sold for cash (other than to any Subsidiary of Milagro) or otherwise cancelled, liquidated or repaid for cash, the cash return of capital with respect to such Restricted Investment resulting from such sale, liquidation or repayment (less anyout-of-pocket costs incurred in connection with any such sale) and (B) the amount returned in cash to Milagro or any of its Restricted Subsidiaries from such Restricted Investment resulting from payments of interest, dividends, principal repayments and other transfers, in an amount not to exceed the aggregate amount of such Restricted Investment;plus

(4) in case any Unrestricted Subsidiary has been redesignated a Restricted Subsidiary pursuant to the terms of the indenture or has been merged or consolidated with or into, or transfers or otherwise disposes of all of substantially all of its properties or assets to or is liquidated into, Milagro or a Restricted Subsidiary, the lesser of, at the date of such redesignation, merger, consolidation, transfer, disposition or liquidation (A) the book value (determined in accordance with GAAP) of the aggregate Investments made by Milagro and its Restricted Subsidiaries in such

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Unrestricted Subsidiary (or of the properties or assets disposed of, as applicable) and (B) the Fair Market Value of such Investment in such Unrestricted Subsidiary, in each case after deducting any Indebtedness of such Unrestricted Subsidiary.

The preceding provisions will not prohibit:

(1) the making of any Restricted Payment (including a dividend) within 60 days after the date Milagro or Restricted Subsidiary became legally or contractually obligated to make such Restricted Payment (including the declaration of a dividend), if at the date of becoming so legally or contractually bound, such Restricted Payment would have complied with the provisions of the indenture (and such Restricted Payment shall be deemed to be made on the date of becoming so legally or contractually bound for purposes of any calculation required by this covenant);

(2) the making of any Restricted Payment in exchange for, or out of or with the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of Milagro) of, Equity Interests of Milagro (other than Disqualified Stock and other than Equity Interests issued or sold to a Subsidiary of Milagro or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or guaranteed by Milagro or any Restricted Subsidiary except to the extent such loans have been repaid with cash on or prior to the date of determination) or from the substantially concurrent contribution of common equity capital to Milagro;providedthat the amount of any such net cash proceeds that are utilized for any such Restricted Payment will not be considered to be net proceeds of Equity Interests for purposes of clause (c)(2) of the preceding paragraph;

(3) the payment of any dividend or distribution by a Restricted Subsidiary of Milagro to the holders of its Equity Interests (other than Disqualified Stock) on apro ratabasis;

(4) the repurchase, redemption, defeasance or other acquisition or retirement for value of Subordinated Obligations of Milagro or Guarantor Subordinated Obligations of any Guarantor with the net cash proceeds from a substantially concurrent incurrence of Subordinated Obligations or Guarantor Subordinated Obligations permitted to be incurred under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock;”provided, however,that the Subordinated Obligations or Guarantor Subordinated Obligations being incurred has (a) a final maturity date no earlier than the earlier of (i) the final maturity date of the Subordinated Obligations or the Guarantor Subordinated Obligations being repurchased, redeemed, defeased or otherwise acquired or retired for value and (ii) the date 90 days after the final maturity date of the notes and (b) a Weighted Average Life to Maturity that is equal to or greater than the Weighted Average Life to Maturity of the Subordinated Obligations or the Guarantor Subordinated Obligations being repurchased, redeemed, defeased or otherwise acquired or retired for value;

(5) so long as no Default or Event of Default has occurred and is continuing, the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of Milagro or any Restricted Subsidiary of Milagro held by any current or former officer, director or employee of Milagro or any of its Restricted Subsidiaries pursuant to any equity subscription agreement, stock option agreement, shareholders’ agreement or similar agreement;providedthat the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $2.0 million in any calendar year (with any unused amounts in any calendar year being carried over to succeeding calendar years);provided further, that such amount in any calendar year may be increased by an amount not to exceed (A) the cash proceeds received by Milagro from the sale of Equity Interests (other than Disqualified Stock) of Milagro or any direct or indirect parent company of Milagro to employees, members of management or directors of Milagro or any direct or indirect parent company of Milagro and the Restricted Subsidiaries that occurs after the date of the indenture (to the extent the cash proceeds from the sale of such Equity Interests have not otherwise been applied to the payment of Restricted Payments by virtue of clause (c)(2) of the preceding paragraph), plus (B) the cash proceeds of key man life insurance policies received by Milagro or any direct or indirect parent company of Milagro and the Restricted Subsidiaries after the date of the indenture, less (C) the amount of any Restricted Payments made after the date of the indenture pursuant to clauses (A) and (B) of this clause (5);

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(6) purchases, repurchases, redemptions or other acquisitions for value of Equity Interests deemed to occur upon the exercise of stock options, warrants or rights to acquire Equity Interests to the extent such Equity Interests represent a portion of the exercise or exchange price thereof, and any purchases, repurchases, redemptions or other acquisitions for value of Equity Interests made in lieu of withholding taxes in connection with any exercise or exchange of warrants, options or rights to acquire Equity Interests;

(7) so long as no Default or Event of Default has occurred and is continuing, the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of Disqualified Stock of Milagro or any preferred stock of any Restricted Subsidiary of Milagro issued on or after the date of the indenture in accordance with the covenant described below under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock;”

(8) payments of cash, dividends, distributions, advances or other Restricted Payments by Milagro or any of its Restricted Subsidiaries to allow the payment of cash in lieu of the issuance of fractional shares upon (i) the exercise of options or warrants, (ii) in connection with stock dividends, splits or combinations or (iii) the conversion or exchange of Capital Stock or convertible Indebtedness of any such Person; and

(9) so long as no Default or Event of Default has occurred and is continuing, other Restricted Payments in an aggregate amount not to exceed $10.0 million since the date of the indenture.

In determining whether any Restricted Payment is permitted by the foregoing covenant, Milagro may allocate or re-allocate all or any portion of such Restricted Payment among clauses (1) through (9) of the immediately preceding paragraph or among such clauses and the first paragraph of this covenant;providedthat at the time of such allocation or re-allocation all such Restricted Payments or allocated portions thereof, and all prior Restricted Payments, would be permitted under the various provisions of this covenant. 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 Milagro or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment.

Incurrence of Indebtedness and Issuance of Preferred Stock

Milagro 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 (collectively,“incur”), with respect to any Indebtedness (including Acquired Debt), and Milagro will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock;provided, however, that Milagro may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, and the Guarantors may incur Indebtedness (including Acquired Debt) or issue preferred stock, if the Fixed Charge Coverage Ratio for Milagro’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 or such preferred stock is issued, as the case may be, 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 the Disqualified Stock or the preferred 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) Indebtedness of Milagro or any Restricted Subsidiary Incurred pursuant to one or more Credit Facilities (including the Credit Agreement) in an aggregate principal amount not to exceed the greater of (i) $200.0 million and (ii) 30% of Milagro’s Adjusted Consolidated Net Tangible Assets determined as of the date of the incurrence of such Indebtedness after giving effect to the application of the proceeds therefrom plus, in the case of either of clauses (i) or (ii), all interest and fees and other obligations thereunder;

(2) the incurrence by Milagro and its Restricted Subsidiaries of the Existing Indebtedness;

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(3) the incurrence by Milagro and the Guarantors of Indebtedness represented by the notes and the related Note Guarantees and the exchange notes and the related Note Guarantees to be issued pursuant to the registration rights agreement;

(4) the incurrence by Milagro 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, construction, installation or improvement of property, plant or equipment used in the business of Milagro or any of its Restricted Subsidiaries, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4), not to exceed $10.0 million;providedthat the principal amount of any Indebtedness permitted under this clause (4) did not in each case at the time of incurrence exceed the Fair Market Value, as determined in accordance with the definition of such term, of the acquired, installed or constructed asset or improvement so financed;

(5) the incurrence by Milagro or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge any Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clauses (2), (3), (4), (5) or (16) of this paragraph;

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

(i) if Milagro or any Guarantor is the obligor on such Indebtedness and the payee is not Milagro or a Guarantor, such Indebtedness must be unsecured and expressly subordinated to the prior payment in full in cash of all Obligations then due with respect to the notes, in the case of Milagro, or the Note Guarantee, in the case of a Guarantor; and

(ii) (A) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than Milagro or a Restricted Subsidiary of Milagro and (B) any sale or other transfer of any such Indebtedness to a Person that is not either Milagro or a Restricted Subsidiary of Milagro, will be deemed, in each case, to constitute an incurrence of such Indebtedness by Milagro or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the issuance by any of Milagro’s Restricted Subsidiaries to Milagro or to any of its Restricted Subsidiaries of shares of preferred stock;provided, however,that:

(i) any subsequent issuance or transfer of Equity Interests that results in any such preferred stock being held by a Person other than Milagro or a Restricted Subsidiary of Milagro; and

(ii) any sale or other transfer of any such preferred stock to a Person that is not either Milagro or a Restricted Subsidiary of Milagro,

will be deemed, in each case, to constitute an issuance of such preferred stock by such Restricted Subsidiary that was not permitted by this clause (7);

(8) the incurrence by Milagro or any of its Restricted Subsidiaries of Hedging Obligations in the ordinary course of business and not for speculative purposes;

(9) the guarantee by Milagro or any of the Guarantors of Indebtedness of Milagro or a Restricted Subsidiary of Milagro to the extent that the guaranteed Indebtedness was permitted to be incurred by another provision of this covenant;providedthat if the Indebtedness being guaranteed is subordinated to orpari passuwith the notes, then the Guarantee must be subordinated orpari passu, as applicable, to the same extent as the Indebtedness guaranteed;

(10) the incurrence by Milagro or any of its Restricted Subsidiaries of Indebtedness in respect of (i) self-insurance obligations or bid, plugging and abandonment, appeal, reimbursement, performance,

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surety and similar bonds and completion guarantees provided by Milagro or a Restricted Subsidiary in the ordinary course of business and any Guarantees or letters of credit functioning as or supporting any of the foregoing bonds or obligations and (ii) workers’ compensation claims in the ordinary course of business;

(11) the incurrence by Milagro or any of its Restricted Subsidiaries of Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently drawn against insufficient funds, so long as such Indebtedness is covered within five business days;

(12) the incurrence by Milagro or any of its Restricted Subsidiaries of Indebtedness arising from agreements of Milagro or any of its Restricted Subsidiaries providing for indemnification, obligations in respect of earn-outs or other purchase price adjustments 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 Milagro and its Restricted Subsidiaries in connection with such disposition;

(13) the incurrence by Milagro or any of its Restricted Subsidiaries of obligations relating to gas balancing obligations arising in the ordinary course of business;

(14) Indebtedness of Milagro or any Restricted Subsidiary with respect to the financing of insurance premiums;

(15) Indebtedness to the extent the net proceeds thereof are promptly deposited to defease the notes or to satisfy and discharge the indenture; and

(16) the incurrence by Milagro or any of the Guarantors of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (16), not to exceed, at any time, the greater of $35.0 million and 5% of Milagro’s Adjusted Consolidated Net Tangible Assets, determined as of the date of Incurrence of such Indebtedness after giving effect to such Incurrence and the application of the proceeds therefrom.

Milagro will not incur, and will not permit any Guarantor to incur, any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of Milagro or such Guarantor unless such Indebtedness is also contractually subordinated in right of payment to the notes or the applicable Note Guarantee, as the case may be, on substantially identical terms;provided, however, that no Indebtedness will be deemed to be contractually subordinated in right of payment to any other Indebtedness of Milagro or any Guarantor solely by virtue of being unsecured or by virtue of being secured on a junior priority basis.

For purposes of determining compliance with the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock,” in the event that an item of Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (16) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, Milagro will be permitted to classify such item of Indebtedness on the date of its incurrence, or later reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant. Indebtedness under the Credit Agreement will initially be deemed to have been incurred on such date in reliance on the exception provided by clause (1) of the definition of Permitted Debt. The accrual of interest or preferred stock dividends, 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, the reclassification of preferred stock as Indebtedness due to a change in accounting principles, and the payment of dividends on preferred stock or Disqualified Stock in the form of additional shares of the same class of preferred stock or Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of preferred stock or Disqualified Stock for purposes of this covenant. For purposes of determining compliance with any U.S. dollar-denominated restriction on the incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be utilized, calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was incurred. Notwithstanding any other provision of this covenant, the maximum amount of

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Indebtedness that Milagro or any Restricted Subsidiary may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in exchange rates or currency values.

The amount of any Indebtedness outstanding as of any date will be:

(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;

(2) the principal amount of the Indebtedness, in the case of any other Indebtedness; and

(3) in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:

(a) the Fair Market Value of such assets at the date of determination; and

(b) the amount of the Indebtedness of the other Person.

Liens

Milagro will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, assume or suffer to exist any Lien of any kind (the “Initial Lien”) upon any of its property or assets (including Capital Stock of Restricted Subsidiaries), including any income or profits therefrom, whether owned on the date of the indenture or acquired after that date, securing any Indebtedness, except Permitted Liens. Notwithstanding anything to the contrary contained in the Note Documents, Milagro will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, pledge any Capital Stock of Milagro or any of the Restricted Subsidiaries to secure Indebtedness of Milagro or any Guarantor, other than Liens securing any Priority Lien Debt, any Parity Lien Debt and as otherwise required as a matter of law.

Limitation on Sale and Leaseback Transactions

Milagro will not, and will not permit any of its Restricted Subsidiaries to, enter into any sale and leaseback transaction;providedthat Milagro or any Restricted Subsidiary may enter into a sale and leaseback transaction if:

(1) Milagro or that Restricted Subsidiary, as applicable, could have (a) incurred Indebtedness in an amount equal to the Attributable Debt relating to such sale and leaseback transaction under the Fixed Charge Coverage Ratio test in the first paragraph of the covenant described above under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock” and (b) incurred a Lien to secure such Indebtedness pursuant to the covenant described above under the caption “— Liens;”

(2) the gross cash proceeds of that sale and leaseback transaction are at least equal to the Fair Market Value, as determined in good faith by the Board of Directors of Milagro and set forth in an officers’ certificate delivered to the trustee, of the property that is the subject of that sale and leaseback transaction; and

(3) the transfer of assets in that sale and leaseback transaction is permitted by, and Milagro applies the proceeds of such transaction in compliance with, the covenant described above under the caption “— Repurchase at the Option of Holders — Asset Sales.”

Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries

Milagro 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 Milagro or any of its Restricted Subsidiaries, or with respect to any other interest or participation in, or measured by, its profits, or pay any indebtedness owed to Milagro or any of its Restricted Subsidiaries;

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

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(3) sell, lease or transfer any of its properties or assets to Milagro 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 Credit Facilities as in effect on the date of the indenture and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements;providedthat the amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of Existing Indebtedness are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the date of the indenture;

(2) the indenture, the notes and the Note Guarantees;

(3) agreements governing other Indebtedness permitted to be incurred under the provisions of the covenant described above under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock” and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements;providedthat the restrictions therein are not materially more restrictive, taken as a whole, than those contained in the indenture, the notes and the Note Guarantees;

(4) applicable law, rule, regulation or order;

(5) any instrument governing Indebtedness or Capital Stock of a Person acquired by Milagro 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 in connection with or in contemplation of 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;providedthat, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;

(6) customary non-assignment provisions in contracts and licenses entered into in the ordinary course of business;

(7) in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(a) that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in Oil and Gas Properties), license or similar contract, or the assignment or transfer of any such lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in Oil and Gas Properties), license (including, without limitation, licenses of intellectual property) or other contract;

(b) contained in mortgages, pledges or other security agreements permitted under the indenture securing Indebtedness of Milagro or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements;

(d) pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of Milagro or any Restricted Subsidiary;

(e) restrictions on cash or other deposits imposed by customers under contracts entered into in the ordinary course of business; or

(f) provisions with respect to the disposition or distribution of assets or property in operating agreements, joint venture agreements, development agreements, area of mutual interest agreements and other agreements that are customary in the Oil and Gas Business and entered into in the ordinary course of business;

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

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

(10) Permitted Refinancing Indebtedness;providedthat 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;

(11) Liens 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;

(12) provisions limiting the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements and other similar agreements (including agreements entered into in connection with a Restricted Investment) entered into with the approval of Milagro’s Board of Directors, which limitation is applicable only to the assets that are the subject of such agreements; and

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

Merger, Consolidation or Sale of Assets

Milagro will not, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not Milagro is the surviving corporation), or (2) sell, assign, transfer, convey or otherwise dispose of all or substantially all of the properties or assets of Milagro and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person, unless:

(1) either: (a) Milagro is the surviving corporation; or (b) the Person formed by or surviving any such consolidation or merger (if other than Milagro) or to which such sale, assignment, transfer, conveyance or other disposition has been made is an entity organized or existing under the laws of the United States, any state of the United States or the District of Columbia; and, if such entity is not a corporation, a co-obligor of the notes is a corporation organized or existing under any such laws;

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

(3) immediately after such transaction, no Default or Event of Default has occurred and is continuing;

(4) Milagro or the Person formed by or surviving any such consolidation or merger (if other than Milagro), or to which such sale, assignment, transfer, conveyance or other disposition has been made would, 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, (i) be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge 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” or (ii) have a Fixed Charge Coverage Ratio equal to or greater than the Fixed Charge Coverage Ratio of Milagro immediately prior to such transaction; and

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

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In addition, Milagro 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.

Milagro will not permit any Guarantor to consolidate with or merge with or into, or convey, transfer or lease all or substantially all of its assets to any Person unless:

(1) the resulting, surviving or transferee Person will be an entity organized and existing under the laws of the United States of America, any state of the United States or the District of Columbia and such Person (if not such Guarantor) will expressly assume all of the obligations of such Guarantor under its Note Guarantee and the registration rights agreement pursuant to agreements reasonably satisfactory to the trustee;

(2) immediately after giving effect to such transaction (and treating any Indebtedness which becomes an obligation of the resulting, surviving or transferee Person as a result of such transaction as having been incurred by such Person at the time of such transaction), no Default or Event of Default will have occurred or be continuing; and

(3) Milagro will have delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or transfer and such supplemental agreements (if applicable) comply with the indenture;

provided, however, that the foregoing will not apply to any such consolidation or merger with or into, or conveyance, transfer or lease to, any Person if the resulting, surviving or transferee Person will not be a Subsidiary of Milagro and the other terms of the indenture, including the covenant described under “— Repurchase at the Option of Holders — Asset Sales,” are complied with.

The covenant described under this caption will not apply to any sale, assignment, transfer, conveyance, lease or other disposition of assets between or among Milagro and its Restricted Subsidiaries. Clauses (3) and (4) of the first paragraph of this covenant will not apply to (1) any merger or consolidation of Milagro with or into one of its Restricted Subsidiaries for any purpose or (2) with or into an Affiliate solely for the purpose of reincorporating Milagro in another jurisdiction.

Transactions with Affiliates

Milagro 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 Milagro (each, an“Affiliate Transaction”), unless:

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

(2) Milagro delivers to the trustee:

(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $10.0 million, a resolution of the Board of Directors of Milagro set forth in an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors of Milagro; and

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $25.0 million, an opinion as to the fairness to Milagro or such Subsidiary of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing.

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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 agreement, employee benefit plan, officer or director indemnification agreement or any similar arrangement entered into by Milagro or any of its Restricted Subsidiaries in the ordinary course of business and payments pursuant thereto;

(2) transactions between or among (A) Milagro and one or more Restricted Subsidiaries and (B) any Restricted Subsidiary;

(3) transactions with a Person (other than an Unrestricted Subsidiary of Milagro) that is an Affiliate of Milagro solely because Milagro owns, directly or through a Restricted Subsidiary, an Equity Interest in, or controls, such Person;

(4) payment of reasonable and customary fees and reimbursements of expenses (pursuant to indemnity arrangements or otherwise) of officers, directors, employees or consultants of Milagro or any of its Restricted Subsidiaries;

(5) any issuance of Equity Interests (other than Disqualified Stock) of Milagro to Affiliates of Milagro;

(6) Restricted Payments that do not violate the provisions of the indenture described above under the caption “— Restricted Payments;”

(7) loans or advances to employees in the ordinary course of business in accordance with the past practices of Milagro or the Restricted Subsidiaries, but in any event not to exceed $2.0 million in the aggregate outstanding at any one time;

(8) advances to or reimbursements of employees for moving, entertainment and travel expenses, drawing accounts and similar expenditures, in each case in the ordinary course of business of Milagro or any of the Restricted Subsidiaries;

(9) indemnities of officers, directors and employees of Milagro or any Restricted Subsidiary consistent with applicable charter, by-law or statutory provisions;

(10) transactions with customers, clients, suppliers, or purchasers or sellers of goods or services, in each case in the ordinary course of business and otherwise in compliance with the terms of the indenture,providedthat in the reasonable determination of the Board of Directors of Milagro or the senior management of Milagro, such transactions are on terms not materially less favorable to Milagro or the relevant Restricted Subsidiary than those that could reasonably be expected to be obtained in a comparable transaction at such time on an arm’s — length basis from a Person that is not an Affiliate of Milagro; and

(11) transactions between Milagro or any Restricted Subsidiary and any Person, a director of which is also a director of Milagro or any direct or indirect parent company of Milagro, and such director is the sole cause for such Person to be deemed an Affiliate of Milagro or any Restricted Subsidiary;provided, however, that such director shall abstain from voting as a director of Milagro or such direct or indirect parent company, as the case may be, on any matter involving such other Person.

Business Activities

Milagro will not, and will not permit any of its Restricted Subsidiaries to, engage in any business other than Oil and Gas Businesses, except to such extent as would not be material to Milagro and its Restricted Subsidiaries taken as a whole.

Additional Note Guarantees

If Milagro or any of its Restricted Subsidiaries acquires or creates another Domestic Subsidiary after the date of the indenture, then that newly acquired or created Domestic Subsidiary will become a Guarantor and

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execute a supplemental indenture and deliver an opinion of counsel satisfactory to the trustee within 20 business days of the date on which it was acquired or created;providedthat any Domestic Subsidiary that constitutes an Immaterial Subsidiary need not become a Guarantor until such time as it ceases to be an Immaterial Subsidiary.

Designation of Restricted and Unrestricted Subsidiaries

The Board of Directors of Milagro may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by Milagro and its Restricted Subsidiaries in the Subsidiary designated as an Unrestricted Subsidiary will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption “— Restricted Payments” or under one or more clauses of the definition of Permitted Investments, as determined by Milagro. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

Any designation of a Subsidiary of Milagro as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of a resolution of the Board of Directors 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 Milagro as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock,” Milagro will be in default of such covenant. The Board of Directors of Milagro may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of Milagro;providedthat such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of Milagro of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described 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 applicable reference period; and (2) no Default or Event of Default would be in existence following such designation.

Limitation on Issuances and Sales of Equity Interests in Wholly-Owned Restricted Subsidiaries

Milagro will not, and will not permit any of its Restricted Subsidiaries to, transfer, convey, sell, lease or otherwise dispose of any Equity Interests in any Wholly-Owned Restricted Subsidiary of Milagro to any Person (other than Milagro or a Wholly-Owned Subsidiary of Milagro), unless:

(1) such transfer, conveyance, sale, lease or other disposition is of all the Equity Interests in such Wholly-Owned Restricted Subsidiary; and

(2) the Net Proceeds from such transfer, conveyance, sale, lease or other disposition are applied in accordance with the covenant described above under the caption “— Repurchase at the Option of Holders — Asset Sales.”

In addition, Milagro will not permit any Wholly-Owned Restricted Subsidiary of Milagro to issue any of its Equity Interests (other than, if necessary, shares of its Capital Stock constituting directors’ qualifying shares) to any Person other than to Milagro or a Wholly-Owned Restricted Subsidiary of Milagro.

Payments for Consent

Milagro will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, pay or cause to be paid any consideration to or for the benefit of any holder of notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the notes unless such

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consideration is offered to be paid and is paid to all holders of the notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or agreement.

Reports

Commencing with the fiscal quarter ending June 30, 2011, whether or not required by the rules and regulations of the SEC, so long as any notes are outstanding, Milagro will furnish to the holders of notes or cause the trustee to furnish to the holders of notes (or file with the SEC for public availability), 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 onForms 10-Q and10-K if Milagro were required to file such reports, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to the annual information only, a report thereon by Milagro’s certified independent accountants;

(2) all current reports that would be required to be filed with the SEC onForm 8-K if Milagro were required to file such reports;

(3) within 15 business days after furnishing to the trustee the annual and quarterly reports required by clause (1) of this paragraph, hold a conference call to discuss such reports and the results of operations for the relevant reporting period; and

(4) issue a press release to an internationally recognized wire service no fewer than three business days prior to the date of the conference call required to be held in accordance with this paragraph, announcing the time and date of such conference call and either including all information necessary to access the call or directing noteholders, prospective investors, broker-dealers and securities analysts to contact the appropriate person at Milagro to obtain such information.

All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports. In addition, following the consummation of the exchange offer contemplated by the registration rights agreement, Milagro 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. Milagro will at all times comply with TIA §314(a).

If, at any time after consummation of the exchange offer contemplated by the registration rights agreement, Milagro is no longer subject to the periodic reporting requirements of the Exchange Act for any reason, Milagro 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. Milagro 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 Milagro’s filings for any reason, Milagro will post the reports referred to in the preceding paragraphs on its website within the time periods that would apply if Milagro were required to file those reports with the SEC.

If Milagro 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 Milagro and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of Milagro.

In addition, Milagro and the Guarantors agree that, for so long as any notes remain outstanding, if at any time they are not required to file with the SEC the reports required by the preceding paragraphs, they will furnish to the holders of notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Milagro will be deemed to have furnished such reports to the trustee and the holders of notes if it has filed such reports with the SEC using the EDGAR filing system and such reports are publicly available.

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Delivery of all such reports, information and documents to the trustee is for informational purposes only, and the trustee’s receipt of such reports, information or documents shall not constitute constructive notice of any information contained therein or determinable from information contained therein, including Milagro’s compliance with any of its covenants hereunder (as to which the trustee is entitled to rely exclusively on Officers’ Certificates).

Events of Default and Remedies

Each of the following is an“Event of Default”:

(1) default for 30 days in the payment when due of interest and Special Interest, if any, on the notes;

(2) default in the payment when due (at maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the notes;

(3) failure by Milagro or any of its Restricted Subsidiaries to comply with the provisions described under the captions “— Repurchase at the Option of Holders — Change of Control,” “— Repurchase at the Option of Holders — Asset Sales,” or “— Certain Covenants — Merger, Consolidation or Sale of Assets;”

(4) failure by Milagro to comply for 30 days with the provisions described under “— Certain Covenants — Restricted Payments,” or “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock;”

(5) failure by Milagro or any of its Restricted Subsidiaries for 60 days after notice to Milagro by the trustee or the holders of at least 25% in aggregate principal amount of the notes then outstanding voting as a single class to comply with any of the other agreements in the indenture;

(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 Milagro or any of its Restricted Subsidiaries (or the payment of which is guaranteed by Milagro 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, premium on, if any, or interest, 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 express 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 $10.0 million or more;

(7) failure by Milagro or any of its Restricted Subsidiaries to pay final judgments entered by a court or courts of competent jurisdiction aggregating in excess of $10.0 million, which judgments are not paid, discharged or stayed, for a period of 60 days;

(8) the occurrence of any of the following:

(a) except as permitted by the indenture, any security document ceases for any reason to be enforceable;providedthat it will not be an Event of Default under this clause (8)(a) if the sole result of the failure of one or more security documents to be fully enforceable is that any Parity Lien purported to be granted under such security documents on Collateral, individually or in the aggregate, having a Fair Market Value of not more than $10.0 million ceases to be an enforceable and perfected second-priority Lien, subject only to Priority Liens and other Permitted Prior Liens;

(b) except as permitted by the intercreditor agreement or the indenture, any Parity Lien purported to be granted under any security document on Collateral, individually or in the aggregate,

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having a Fair Market Value in excess of $10.0 million ceases to be an enforceable and perfected second-priority Lien, subject only to Priority Liens and other Permitted Prior Liens; or

(c) Milagro or any Guarantor, or any Person acting on behalf of any of them, denies or disaffirms, in writing, any obligation of Milagro or any Guarantor set forth in or arising under any security document;

(9) except as permitted by the indenture, any Note Guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any Guarantor, or any Person acting on behalf of any Guarantor, denies or disaffirms its obligations under its Note Guarantee; and

(10) certain events of bankruptcy or insolvency described in the indenture with respect to Milagro or any of its Restricted Subsidiaries that is a Significant Subsidiary or any group of its Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

In the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to Milagro, any Restricted Subsidiary of Milagro that is a Significant Subsidiary or any group of Restricted Subsidiaries of Milagro that, taken together, would constitute a Significant 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.

Notwithstanding the foregoing, if an Event of Default specified in clause (6) above shall have occurred and be continuing, such Event of Default and any consequential acceleration (to the extent not in violation of any applicable law or in conflict with any judgment or decree of a court of competent jurisdiction) shall be automatically rescinded if (i) the Indebtedness that is the subject of such Event of Default has been repaid or (ii) if the default relating to such Indebtedness is waived by the holders of such Indebtedness or cured and if such Indebtedness has been accelerated, then the holders thereof have rescinded their declaration of acceleration in respect of such Indebtedness, in each case within 20 days after the declaration of acceleration with respect thereto, and (iii) any other existing Events of Default, except nonpayment of principal, premium or interest on the notes that became due solely because of the acceleration of the notes, have been cured or waived.

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 from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal of, premium on, if any, and interest and Special Interest, 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, premium, if any, or interest or Special Interest, 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 written notice that an Event of Default is continuing;

(2) holders of at least 25% in aggregate principal amount of the then outstanding notes make a written request to the trustee to pursue the remedy;

(3) such holder or holders offer and, if requested, provide to the trustee security or indemnity reasonably satisfactory to the trustee against any loss, liability or expense;

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

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(5) during such60-day period, holders of a majority in aggregate principal amount of the then outstanding notes do not give the trustee a direction inconsistent with such request.

The holders of a majority in aggregate principal amount of the then outstanding notes by written notice to the trustee may, on behalf of the holders of all of the notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the indenture, if the rescission would not conflict with any judgment or decree, except a continuing Default or Event of Default in the payment of principal of, premium on, if any, or interest or Special Interest, if any, on, the notes.

Milagro is required to deliver to the trustee annually a statement regarding compliance with the indenture. Within 30 days after any executive officer of Milagro becomes aware of any Event of Default, Milagro is required to deliver to the trustee a statement specifying such Event of Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder of Milagro or any Guarantor, as such, will have any liability for any obligations of Milagro or the Guarantors under the Note Documents 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.

Legal Defeasance and Covenant Defeasance

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

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

(2) Milagro’s 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 under the indenture, and Milagro’s and the Guarantors’ obligations in connection therewith; and

(4) the Legal Defeasance and Covenant Defeasance provisions of the indenture.

In addition, Milagro may, at its option and at any time, elect to terminate its and the Guarantors’ obligations under “— Repurchase at the Option of Holders — Change of Control” and “— Repurchase at the Option of Holders — Asset Sales” and under covenants described under “Certain Covenants” (other than “— Certain Covenants — Merger, Consolidation or Sale of Assets”), the operation of the cross default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision, the Note Guarantee provision described in clause (9) of the first paragraph under “— Events of Default and Remedies” above and the limitations contained in clause (4) under “— Certain Covenants — Merger, Consolidation or Sale of Assets”(“Covenant Defeasance”). In the event Covenant Defeasance occurs, all Events of Default described under “— Events of Default and Remedies” (except those relating to payments on the notes or bankruptcy, receivership, rehabilitation or insolvency events) will no longer constitute an Event of Default with respect to the notes.

In order to exercise either Legal Defeasance or Covenant Defeasance:

(1) Milagro 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 thereof, in amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of

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independent public accountants, to pay the principal of, premium on, if any, and interest and Special Interest, if any, on, the outstanding notes on the stated date for payment thereof or on the applicable redemption date, as the case may be, and Milagro must specify whether the notes are being defeased to such stated date for payment or to a particular redemption date;

(2) in the case of Legal Defeasance, Milagro must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that (a) Milagro 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, Milagro must deliver 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 (and any similar concurrent deposit relating to other Indebtedness), and the granting of Liens to secure such borrowings);

(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 and the agreements governing any other Indebtedness being defeased, discharged or replaced) to which Milagro or any of the Guarantors is a party or by which Milagro or any of the Guarantors is bound;

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

(7) Milagro 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.

The Collateral will be released from the Lien securing the notes, as provided under the caption “— Collateral Trust Agreement — Release of Liens in Respect of Notes,” upon a Legal Defeasance or Covenant Defeasance in accordance with the provisions described above.

Amendment, Supplement and Waiver

Except as provided in the next two succeeding paragraphs, the indenture or the notes or the Note Guarantees may be amended or supplemented with the consent of the holders of at least a majority in aggregate principal amount of the then outstanding notes voting as a single class (including, without limitation, consents obtained in connection with a tender offer or exchange offer for, or purchase of, the notes), and any existing Default or Event of Default (other than a Default or Event of Default in the payment of the principal of, premium on, if any, or interest or Special Interest, if any, on, the notes, except a payment default resulting from an acceleration that has been rescinded) or compliance with any provision of the indenture or the notes or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes voting as a single class (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

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Without the consent of each holder of notes 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 or waive any of the provisions with respect to the redemption of the notes (except those 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 default interest, on any note;

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

(5) make any note payable in money other than that stated in the notes;

(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, premium on, if any, or interest or Special Interest, if any, on, the notes;

(7) waive a redemption 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 Note Guarantee or the indenture, except in accordance with the terms of the indenture; or

(9) make any change in the amendment and waiver provisions contained in clauses (1) through (8) above.

In addition, any amendment to, or waiver of, the provisions of the indenture or any security document that has the effect of releasing all or substantially all of the Collateral from the Liens securing the notes will require the consent of the holders of at least 662/3% in aggregate principal amount of the notes then outstanding

Notwithstanding the preceding, without the consent of any holder of notes, Milagro, the Guarantors and the trustee may amend or supplement the indenture, the notes or the Note Guarantees:

(1) to cure any ambiguity, defect or inconsistency;

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

(3) to provide for the assumption of Milagro’s or a Guarantor’s obligations to holders of notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of Milagro’s or such Guarantor’s assets, as applicable;

(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;

(5) to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;

(6) to conform the text of the indenture, the notes or the Note Guarantees to any provision of this Description of Notes to the extent that such provision in this Description of Notes was intended to be a verbatim recitation of a provision of the indenture, the notes or the Note Guarantees, which intent may be evidenced by an officers’ certificate to that effect;

(7) to allow any Person to execute a supplemental indentureand/or a Note Guarantee in order to Guarantee the notes;

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(8) to provide for the issuance of additional notes in accordance with the limitations set forth in the indenture; and

(9) to make, complete or confirm any grant of Collateral permitted or required by the indenture or any of the security documents or any release of Collateral pursuant to the terms of the indenture or any of the security documents.

Satisfaction and Discharge

The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder, when:

(1) either:

(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 Milagro or discharged from such trust as provided in the indenture, 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 by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year and Milagro, any Guarantor or any other Person on behalf of Milagro 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 thereof, 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 of, premium on, if any, and interest and Special Interest, if any, on, the notes to the date of maturity or redemption;

(2) in respect of clause 1(b), no Default or Event of Default has occurred and is continuing on the date of the deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit and any similar deposit relating to other Indebtedness and, in each case, the granting of Liens to secure such borrowings) and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which Milagro or any Guarantor is a party or by which Milagro or any Guarantor is bound (other than with respect to the borrowing of funds to be applied concurrently to make the deposit required to effect such satisfaction and discharge and any similar concurrent deposit relating to other Indebtedness, and in each case the granting of Liens to secure such borrowings);

(3) Milagro or any Guarantor has paid or caused to be paid all sums payable by it under the indenture; and

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

In addition, Milagro 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.

The Collateral will be released from the Lien securing the notes, as provided under the caption “— Collateral Trust Agreement — Release of Liens in Respect of Notes,” upon a satisfaction and discharge in accordance with the provisions described above.

Concerning the Trustee

If the trustee becomes a creditor of Milagro or any Guarantor, the indenture limits the right of the trustee 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

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acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as trustee (if the indenture has been 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. The indenture provides that in case an Event of Default has occurred and is continuing, the trustee will be required, in the exercise of its power, 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 reasonable indemnity or security satisfactory to it against any loss, liability or expense.

Governing Law

The indenture, the notes and each Note Guarantee are governed by, and will be construed in accordance with, the laws of the State of New York.

Additional Information

Anyone who receives this prospectus may obtain a copy of the indenture, the registration rights agreement, the collateral trust agreement, the intercreditor agreement and the security documents without charge by writing to Milagro Oil & Gas, Inc., 1301 McKinney Street, Suite 500, Houston, TX77010-3089, Attention: Chief Financial Officer.

Book-Entry, Delivery and Form

The old notes were offered and sold to qualified institutional buyers in reliance on Rule 144A(“Rule 144A Notes”)and were offered and sold in offshore transactions in reliance on Regulation S(“Regulation S Notes”). Except as set forth below, the notes will be issued in registered, global form in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. Notes were issued at the closing of this offering only against payment in immediately available funds.

Rule 144A Notes initially will be represented by one or more notes in registered, global form without interest coupons (collectively, the“Rule 144A Global Notes”). Regulation S Notes initially will be represented by one or more temporary notes in registered, global form without interest coupons (collectively, the“Regulation S Temporary Global Notes”). The Rule 144A Global Notes and the Regulation S Temporary Global Notes will be deposited upon issuance with the trustee as custodian for The Depository Trust Company(“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. Through and including the 40th day after the later of the commencement of this offering and the closing of this offering (such period through and including such 40th day, the“Restricted Period”), beneficial interests in the Regulation S Temporary Global Notes may be held only through the Euroclear System(“Euroclear”)and Clearstream Banking, S.A.(“Clearstream”)(as indirect participants in DTC), unless transferred to a person that takes delivery through a Rule 144A Global Note in accordance with the certification requirements described below. Within a reasonable time period after the expiration of the Restricted Period, the Regulation S Temporary Global Notes will be exchanged for one or more permanent notes in registered, global form without interest coupons (collectively, the“Regulation S Permanent Global Notes”and, together with the Regulation S Temporary Global Notes, the“Regulation S Global Notes”) upon delivery to DTC of certification of compliance with the transfer restrictions applicable to the notes and pursuant to Regulation S as provided in the indenture. Beneficial interests in the Rule 144A Global Notes may not be exchanged for beneficial interests in the Regulation S Global Notes at any time except in the limited circumstances described below. See “— Exchanges Between Regulation S Notes and Rule 144A Notes.” The exchange notes will also initially be represented by one or more notes in registered, global form without interest coupons (collectively with the Regulation S Global Notes and the Rule 144A Global Notes, the“Global Notes”).

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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.

Rule 144A Notes (including beneficial interests in the Rule 144A Global Notes) will be subject to certain restrictions on transfer and will bear a restrictive legend as described under “Transfer Restrictions.” Regulation S Notes will also bear the legend as described under “Transfer Restrictions.” In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

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. Milagro takes no responsibility for these operations and procedures and urges investors to contact the system or their participants directly to discuss these matters.

DTC has advised Milagro 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 (including the initial purchasers), 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.

DTC has also advised Milagro that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of the Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Notes).

Investors in the Rule 144A Global Notes who are Participants may hold their interests therein directly through DTC. Investors in the Rule 144A Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants. Investors in the Regulation S Global Notes must initially hold their interests therein through Euroclear or Clearstream, if they are participants in such systems, or indirectly through organizations that are participants. After the expiration of the Restricted Period (but not earlier), investors may also hold interests in the Regulation S Global Notes through Participants in the DTC system other than Euroclear and Clearstream. Euroclear and Clearstream will hold interests in the Regulation S Global Notes on behalf of their participants through customers’ securities accounts in their respective names on the books of their respective depositories, which are Euroclear Bank S.A./N.V., as operator of Euroclear, and Citibank, N.A., as operator of Clearstream. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be

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subject to the procedures and requirements of such systems. The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

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, premium on, if any, and interest and Special Interest, if any, 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, Milagro 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. Consequently, neither Milagro, the trustee nor any agent of Milagro or the trustee 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 Milagro 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 or Milagro. Neither Milagro nor the trustee 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 Milagro and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Subject to certain transfer restrictions, transfers between the Participants will be effected in accordance with DTC’s procedures, and will be settled insame-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 forsame-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 Milagro 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

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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 Rule 144A Global Notes and the Regulation S 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 Milagro, 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.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes if:

(1) DTC (a) notifies Milagro 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, Milagro fails to appoint a successor depositary;

(2) Milagro, at its option, notifies the trustee in writing that it elects to cause the issuance of the Certificated Notes;providedthat in no event shall the Regulation S Temporary Global Note be exchanged for Certificated Notes prior to (a) the expiration of the Restricted Period and (b) the receipt of any certificates required under the provisions of Regulation S; or

(3) there has occurred and is continuing a Default or Event of Default with respect to the notes and DTC requests such exchange.

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) and will bear the applicable restrictive legend, unless that legend is not required by applicable law.

Exchange of Certificated Notes for Global Notes

Certificated Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such notes.

Exchanges Between Regulation S Notes and Rule 144A Notes

Prior to the expiration of the Restricted Period, beneficial interests in the Regulation S Global Note may be exchanged for beneficial interests in the Rule 144A Global Note only if:

(1) such exchange occurs in connection with a transfer of the notes pursuant to Rule 144A; and

(2) the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that the notes are being transferred to a Person:

(a) who the transferor reasonably believes to be a qualified institutional buyer within the meaning of Rule 144A;

(b) purchasing for its own account or the account of a qualified institutional buyer in a transaction meeting the requirements of Rule 144A; and

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Beneficial interests in a Rule 144A Global Note may be transferred to a Person who takes delivery in the form of an interest in the Regulation S Global Note, whether before or after the expiration of the Restricted Period, only if the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that such transfer is being made in accordance with Rule 903 or 904 of Regulation S or Rule 144 (if available) and that, if such transfer occurs prior to the expiration of the Restricted Period, the interest transferred will be held immediately thereafter through Euroclear or Clearstream.

Transfers involving exchanges of beneficial interests between the Regulation S Global Notes and the Rule 144A Global Notes will be effected by DTC by means of an instruction originated by the trustee through the DTC Deposit/Withdraw at Custodian system. Accordingly, in connection with any such transfer, appropriate adjustments will be made to reflect a decrease in the principal amount of the Regulation S Global Note and a corresponding increase in the principal amount of the Rule 144A Global Note or vice versa, as applicable. Any beneficial interest in one of the Global Notes that is transferred to a Person who takes delivery in the form of an interest in the other Global Note will, upon transfer, cease to be an interest in such Global Note and will become an interest in the other Global Note and, accordingly, will thereafter be subject to all transfer restrictions and other procedures applicable to beneficial interests in such other Global Note for so long as it remains such an interest. The policies and practices of DTC may prohibit transfers of beneficial interests in the Regulation S Global Note prior to the expiration of the Restricted Period.

Certifications by Holders of the Regulation S Temporary Global Notes

A holder of a beneficial interest in the Regulation S Temporary Global Notes must provide Euroclear or Clearstream, as the case may be, with a certificate in the form required by the indenture certifying that the beneficial owner of the interest in the Regulation S Temporary Global Note is either anon-U.S. person or a U.S. person that has purchased such interest in a transaction that is exempt from the registration requirements under the Securities Act, and Euroclear or Clearstream, as the case may be, must provide to the trustee (or the paying agent if other than the trustee) a certificate in the form required by the indenture, prior to any exchange of such beneficial interest for a beneficial interest in the Regulation S Permanent Global Notes.

Same Day Settlement and Payment

Milagro will make payments in respect of the notes represented by the Global Notes (including principal, premium, if any, and interest and Special Interest, if any) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. Milagro will make all payments of principal, premium, if any, and interest and Special Interest, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the holders of the Certificated Notes or, if no such account is specified, by mailing a check to each such holder’s registered address. The notes represented by the Global Notes are expected to be eligible to trade in DTC’sSame-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. Milagro expects that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised Milagro that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

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Certain Definitions

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

“Acquired Debt”means, with respect to any specified Person:

(1) Indebtedness of any other Person existing at the time such other Person is 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 Restricted Subsidiary of, such specified Person; and

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

“Act of Parity Lien Debtholders”means, as to any matter at any time, a direction in writing delivered to the collateral trustee by or with the written consent of the holders of Parity Lien Debt representing the Required Parity Lien Debtholders.

“Additional Secured Debt Designation”means the written agreement of the holders of any Series of Parity Lien Debt, as set forth in the indenture, credit agreement or other agreement governing such Series of Parity Lien Debt, for the benefit of, and enforceable by, all holders of each existing and future Series of Priority Lien Debt, the Priority Lien Collateral Agent and each existing and future holder of Permitted Prior Liens:

(1) that all Parity Lien Obligations will be and are secured equally and ratably by all Parity Liens at any time granted by Milagro or any Guarantor to secure any Obligations in respect of such Series of Parity Lien Debt, whether or not upon property otherwise constituting collateral for such Series of Parity Lien Debt, and that all such Parity Liens will be enforceable by the collateral trustee for the benefit of all holders of Parity Lien Obligations equally and ratably;

(2) that the holders of Obligations in respect of such Series of Parity Lien Debt are bound by the provisions of the collateral trust agreement, including the provisions relating to the ranking of Parity Liens and the order of application of proceeds from the enforcement of Parity Liens; and

(3) consenting to and directing the collateral trustee to perform its obligations under the collateral trust agreement and the other security documents.

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

(a) the sum of:

(i) the discounted future net revenues from proved oil and natural gas reserves of Milagro and its Restricted Subsidiaries calculated in accordance with SEC guidelines (but giving effect to applicable Oil and Gas Hedging Agreements in place as of the date of determination (whether positive or negative)), before any state or federal income taxes, as estimated by Milagro and reviewed by independent petroleum engineers in a reserve report prepared as of the end of Milagro’s most recently completed fiscal year for which audited financial statements are available, asincreased by, as of the date of determination, the discounted future net revenues, calculated in accordance with SEC guidelines, but giving effect to applicable Oil and Gas Hedging Agreements in place as of the date of determination (whether positive or negative), from

(A) estimated proved oil and natural gas reserves of Milagro and its Restricted Subsidiaries acquired since the date of such year-end reserve report; and

(B) estimated oil and natural gas reserves of Milagro and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior period end) since the date of such year-end reserve

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report due to exploration, development or exploitation, production or other activities which would, in accordance with standard industry practice, cause such revisions;

and decreased by, as of the date of determination, the discounted future net revenue, attributable to:

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

(D) reductions in estimated oil and natural gas reserves of Milagro and its Restricted Subsidiaries reflected in such reserve report attributable to downward revisions of estimates of proved oil and natural gas reserves since such year-end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions;

in the case of each of the determinations made pursuant to clauses (A) through (D) utilizing prices and costs calculated in accordance with SEC guidelines as if the end of the most recent fiscal quarter preceding the date of determination for which such information is available to Milagro were year end;provided, however, that in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be as estimated by Milagro’s petroleum engineers;

(ii) the capitalized costs that are attributable to Oil and Gas Properties of Milagro and its Restricted Subsidiaries to which no proved oil and natural gas reserves are attributable, based on Milagro’s books and records as of a date no earlier than the date of Milagro’s most recently available internal quarterly financial statements;

(iii) the Consolidated Net Working Capital of Milagro as of a date no earlier than the date of Milagro’s most recently available internal quarterly financial statements; and

(iv) the greater of

(A) the net book value as of a date no earlier than the date of Milagro’s most recently available internal quarterly financial statements and

(B) the appraised value, as estimated by independent appraisers, of other tangible assets (including Investments in unconsolidated Subsidiaries) of Milagro and its Restricted Subsidiaries, in either case, as of a date no earlier than the date of Milagro’s most recently available internal quarterly financial statements;providedthat if no such appraisal has been performed Milagro shall not be required to obtain such an appraisal and only clause (iv)(A) of this definition shall apply,

minus

(b) the sum of:

(i) minority interests;

(ii) to the extent not otherwise taken into account in determining Adjusted Consolidated Net Tangible Assets, any net gas balancing liabilities of Milagro and its Restricted Subsidiaries reflected in Milagro’s latest annual or quarterly financial statements;

(iii) to the extent included in clause (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in Milagro’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of Milagro and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto; and

(iv) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of Milagro and its consolidated

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Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.

If Milagro changes its method of accounting from the full cost method to the successful efforts method or a similar method of accounting, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if Milagro were still using the full cost method of accounting.

“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;providedthat 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.

“Applicable Premium”means, with respect to any note on any redemption date, the greater of:

(1) 1.0% of the principal amount of the note; or

(2) the excess of:

(a) the present value at such redemption date of (i) the redemption price of the note at May 15, 2014 (such redemption price being set forth in the table appearing above under the caption “— Optional Redemption”) plus (ii) all required interest payments due on the note from such redemption date through May 15, 2014 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(b) the principal amount of the note.

Calculation of the Applicable Premium will be made by Milagro or on behalf of Milagro by such Person as Milagro shall designate, and in any event, such calculation shall not be a duty or obligation of the trustee. Milagro will deliver an Officers’ Certificate to the trustee prior to the applicable redemption date advising the trustee of the Applicable Premium, together with the basis for such calculation in reasonable detail.

“Asset Sale”means:

(1) the sale, lease, conveyance or other disposition of any assets or rights by Milagro or any of Milagro’s Restricted Subsidiaries;providedthat the sale, lease, conveyance or other disposition of all or substantially all of the assets of Milagro 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 by any of Milagro’s Restricted Subsidiaries or the sale by Milagro or any of Milagro’s Restricted Subsidiaries of Equity Interests in any of Milagro’s Subsidiaries.

Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:

(1) any single transaction or series of related transactions that involves assets having a Fair Market Value of less than $5.0 million;

(2) a transfer of assets between or among Milagro and its Restricted Subsidiaries;

(3) an issuance of Equity Interests by a Restricted Subsidiary of Milagro to Milagro or to a Restricted Subsidiary of Milagro;

(4) the sale or other disposition of surplus, damaged, unserviceable, worn-out or obsolete assets in the ordinary course of business;

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(5) licenses and sublicenses by Milagro or any of its Restricted Subsidiaries of intellectual property, including, without limitation, licenses for seismic data, in the ordinary course of business and which do not materially interfere with the business of Milagro and its Restricted Subsidiaries;

(6) any surrender or waiver of contract rights or settlement, release, recovery on or surrender of contract, tort or other claims in the ordinary course of business and the liquidation of any assets received in settlement of claims owed to Milagro or any of its Restricted Subsidiaries;

(7) the granting of Liens not prohibited by the covenant described above under the caption “— Certain Covenants — Liens;”

(8) the sale or other disposition of cash or Cash Equivalents;

(9) a Restricted Payment (or any transaction that would be a Restricted Payment but for an exclusion from the definition thereof) that does not violate the covenant described above under the caption “— Certain Covenants — Restricted Payments” or a Permitted Investment;

(10) the sale or transfer of Hydrocarbons or other mineral products in the ordinary course of business;

(11) the trade or exchange by Milagro or any Restricted Subsidiary of any oil and gas lease, oil or gas property or interest therein and any related assets owned or held by Milagro or such Restricted Subsidiary or the capital stock of a Subsidiary for (a) any oil and gas lease, oil or gas property or interest therein and any related assets owned or held by another Person or (b) the Capital Stock of another Person that becomes a Restricted Subsidiary as a result of such trade or exchange or the Capital Stock of another Person that is a joint venture, partnership or other similar entity, in each case all or substantially all of whose assets consist of crude oil or natural gas properties, including in the case of either of clauses (a) or (b), any cash or cash equivalents necessary in order to achieve an exchange of equivalent value;provided, however, that (i) the property is useful, or the Person that becomes a Restricted Subsidiary is engaged, in the Oil and Gas Business and (ii) the value of the property or Capital Stock received by Milagro or any Restricted Subsidiary in such trade or exchange (including any cash or cash Equivalents) is substantially equal to the Fair Market Value of the property (including any cash or cash equivalents so traded or exchanged);

(12) the abandonment, farm-out, lease, sublease or other disposition of developed or undeveloped Oil and Gas Properties and related equipment in the ordinary course of business; and

(13) any issuance or sale of Capital Stock of Milagro.

“Asset Sale Offer”has the meaning assigned to that term in the indenture governing the notes.

“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;provided, however, that if such sale and leaseback transaction results in a Capital Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capital Lease Obligation.”

“Banking Services”means each and any of the following bank services provided to Milagro or any Restricted Subsidiary by any lender under the Credit Agreement or affiliate thereof: (a) commercial credit cards, (b) stored value cards and (c) treasury management services (including controlled disbursement, automated clearinghouse transactions, return items, overdrafts and interstate depository network services).

“Banking Services Obligations”means any and all obligations of Milagro or any Restricted Subsidiary, whether absolute or contingent and howsoever and whensoever created, arising, evidenced or acquired (including all renewals, extensions and modifications thereof and substitutions therefor) in connection with Banking Services.

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“Beneficial Owner”has the meaning assigned to such term inRule 13d-3 andRule 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 after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.

“Board of Directors”means:

(1) with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;

(2) with respect to a partnership, the Board of Directors of the general partner of the partnership;

(3) with respect to a limited liability company, the manager or managers, or if there are no managers of such limited liability company, the managing member or members or any controlling committee of managers or managing members thereof, as the case may be; and

(4) with respect to any other Person, the board or committee of such Person serving a similar function.

“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 prepared 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.

“Capital Stock”means:

(1) in the case of a corporation, corporate stock;

(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 interests (whether general or limited) or membership interests; 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.

“Cash Equivalents”means:

(1) United States dollars;

(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 (providedthat the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than one year from the date of acquisition;

(3) certificates of deposit and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers’ acceptances with maturities not exceeding one year, overnight bank deposits, and demand and time deposits, in each case, with any lender party to the Credit Agreement or another Credit Facility 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;

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(5) commercial paper having one of the two highest ratings obtainable from Moody’s or S&P and, in each case, maturing within one year 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.

“Change of Control”means the occurrence of any of the following:

(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 of Milagro and its Subsidiaries taken as a whole to any Person (including any “person” (as that term is used in Section 13(d)(3) of the Exchange Act));

(2) the adoption of a plan relating to the liquidation or dissolution of Milagro;

(3) the consummation of any transaction (including, without limitation, any merger or consolidation), the result of which is that any Person (including any “person” as defined above), other than Milagro Holdings, LLC or any Permitted Holder, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of Milagro, measured by voting power rather than number of shares; or

(4) the first day on which a majority of the members of the Board of Directors of Milagro are not Continuing Directors.

“Change of Control Offer”has the meaning assigned to that term in the indenture governing the notes.

“Collateral”means all properties and assets at any time owned or acquired by Milagro or any of the Guarantors (or, in the case of Milagro’s and the Guarantors’ Oil and Gas Properties, all Oil and Gas Properties that secure the Priority Lien Obligations, but in any event not less than 80% of the total Recognized Value of Milagro’s and the Guarantors’ proved Oil and Gas Properties located in the United States or in adjacent Federal waters), except:

(1) Excluded Assets;

(2) any properties and assets in which the collateral trustee is required to release its Liens pursuant to the provisions described above under the captions “— The Intercreditor Agreement — Automatic Release of Parity Liens” and “— Collateral Trust Agreement — Release of Liens on Collateral;” and

(3) any properties and assets that no longer secure the notes or any Obligations in respect thereof pursuant to the provisions described above under the captions “— The Intercreditor Agreement — Automatic Release of Parity Liens” and “— Collateral Trust Agreement — Release of Liens in Respect of Notes,”

providedthat, in the case of clauses (2) and (3), if such Liens are required to be released as a result of the sale, transfer or other disposition of any properties or assets of Milagro or any Guarantor, such assets or properties will cease to be excluded from the Collateral if Milagro or any Guarantor thereafter acquires or reacquires such assets or properties.

“collateral trustee”means Wells Fargo Bank, N.A., in its capacity as collateral trustee under the collateral trust agreement, together with its successors in such capacity.

“Consolidated EBITDA”means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such periodplus, without duplication:

(1) an amount equal to any extraordinary or non-recurring loss plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, to the extent such losses were deducted in computing such Consolidated Net Income;plus

(2) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income;plus

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(3) the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income;plus

(4) depreciation, amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period) and other non-cash charges and expenses (excluding any such non-cash charge or expense to the extent that it represents an accrual of or reserve for cash charges or expenses in any future period or amortization of a prepaid cash charge or expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, amortization and other non-cash charges or expenses were deducted in computing such Consolidated Net Income;minus

(5) non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business,

in each case, on a consolidated basis and determined in accordance with GAAP.

“Consolidated Net Income”means, with respect to any specified Person for any period, the aggregate of the net income (loss) of such Person and its Restricted Subsidiaries for such period, on a consolidated basis (excluding the net income (loss) of any Unrestricted Subsidiary of such Person), determined in accordance with GAAP and without any reduction in respect of preferred stock dividends;providedthat:

(1) all extraordinary or non-recurring gains (but not losses) and all gains (but not losses) realized in connection with any Asset Sale or the disposition of securities or the early extinguishment of Indebtedness, together with any related provision for taxes on any such gain, will be excluded;

(2) the net income (but not loss) of any Person that is not a Restricted Subsidiary will be included only to the extent of the amount of dividends or similar distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

(3) the net income (but not loss) of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that net income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders;

(4) the cumulative effect of a change in accounting principles will be excluded;

(5) non-cash gains and losses attributable to movement in themark-to-market valuation of Hedging Obligations pursuant to Financial Accounting Standards Board Statement No. 133 will be excluded;

(6) any non-cash compensation charge arising from any grant of stock, stock options or other equity based awards will be excluded;providedthat the proceeds resulting from any such grant will be excluded from clause (c)(2) of the first paragraph of the covenant described under “— Certain Covenants — Restricted Payment.”

(7) any asset impairment writedowns of Oil and Gas Properties under GAAP or SEC guidelines will be excluded; and

(8) any after-tax effect of income (loss) from the early extinguishment of Indebtedness will be excluded.

“Consolidated Net Working Capital”of any Person as of any date of determination means the difference (shown on the balance sheet of such Person and its Subsidiaries determined on a consolidated basis in accordance with GAAP as of the end of the most recent fiscal quarter of such Person for which internal financial statements are available) between (i) all current assets of such Person and its Subsidiaries (other than current assets arising out of any agreement related to Milagro’s or any Restricted Subsidiary’s Hedging Obligations) and (ii) all current liabilities of such Person and its Subsidiaries except the current portion of

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long-term Indebtedness and current liabilities arising out of any agreement related to Milagro’s or any Restricted Subsidiary’s Hedging Obligations.

“continuing”means, with respect to any Default or Event of Default, that such Default or Event of Default has not been cured or waived.

“Continuing Directors”means, as of any date of determination, any member of the Board of Directors of Milagro who:

(1) was a member of such Board of Directors on the date of the indenture; or

(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 of Directors at the time of such nomination or election.

“Credit Agreement”means that certain Credit Agreement, to be entered into on or before the date of the indenture, by and among Milagro Exploration, LLC, Milagro Producing LLC, Milagro Oil & Gas, Inc., the lenders party thereto from time to time, and Wells Fargo Bank, N.A., as administrative agent, swing line lender and issuer of letters of credit, providing for up to $300 million of revolving credit borrowings, 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 in any manner (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.

“Credit Agreement Agent”means, at any time, the Person serving at such time as the “Agent” or “Administrative Agent” under the Credit Agreement or any other representative then most recently designated in accordance with the applicable provisions of the Credit Agreement, together with its successors in such capacity.

“Credit Facilities”means, one or more debt facilities (including, without limitation, the Credit Agreement) or commercial paper facilities, in each case, with banks or other institutional lenders 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 borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.

“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.

“Discharge of Priority Lien Obligations”means the occurrence of all of the following:

(1) termination or expiration of all commitments to extend credit that would constitute Priority Lien Debt;

(2) payment in full in cash of the principal of and interest and premium (if any) on all Priority Lien Debt (other than any undrawn letters of credit);

(3) discharge or cash collateralization (at the lower of (a) 105% of the aggregate undrawn amount and (b) the percentage of the aggregate undrawn amount required for release of liens under the terms of the applicable Priority Lien Document) of all outstanding letters of credit constituting Priority Lien Debt;

(4) payment of Hedging Obligations constituting Priority Lien Obligations (and, with respect to any particular Hedge Agreement, termination of such agreement and payment in full in cash of all obligations thereunder or such other arrangements as have been made by counterparty thereto (and communicated to the Priority Lien Collateral Agent) pursuant to the terms of the Credit Agreement);

(5) payment in full in cash of all other Priority Lien Obligations that are outstanding and unpaid at the time the Priority Lien Debt is paid in full in cash (other than any obligations for taxes, costs,

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indemnifications, reimbursements, damages and other liabilities in respect of which no claim or demand for payment has been made at or prior to such time);

providedthat, if, at any time after the Discharge of Priority Lien Obligations has occurred, Milagro enters into any Priority Lien Document evidencing a Priority Lien Debt which incurrence is not prohibited by the applicable Secured Debt Documents, then such Discharge of Priority Lien Obligations shall automatically be deemed not to have occurred for all purposes of the intercreditor agreement with respect to such new Priority Lien Debt (other than with respect to any actions taken as a result of the occurrence of such first Discharge of Priority Lien Obligations), and, from and after the date on which Milagro designates such Indebtedness as Priority Lien Debt in accordance with the intercreditor agreement, the obligations under such Priority Lien Document shall automatically and without any further action be treated as Priority Lien Obligations for all purposes of the intercreditor agreement, including for purposes of the Lien priorities and rights in respect of Collateral set forth in the intercreditor agreement and any Parity Lien Obligations shall be deemed to have been at all times Parity Lien Obligations and at no time Priority Lien Obligations.

“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 Milagro to repurchase 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 Milagro 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.” The amount of Disqualified Stock deemed to be outstanding at any time for purposes of the indenture will be the maximum amount that Milagro and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.

“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 Milagro 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 Milagro.

“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 a public or private sale either (1) of Equity Interests of Milagro by Milagro (other than Disqualified Stock and other than to a Subsidiary of Milagro) or (2) of Equity Interests of a direct or indirect parent entity of Milagro (other than to Milagro or a Subsidiary of Milagro) to the extent that the net proceeds therefrom are contributed to the common equity capital of Milagro.

“Existing Indebtedness”means all Indebtedness of Milagro and its Subsidiaries (other than Indebtedness under the Credit Agreement) in existence on the date of the indenture, until such amounts are repaid.

“Fair Market Value”means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of Milagro.

“Fixed Charge Coverage Ratio”means with respect to any specified Person for any period, the ratio of the Consolidated EBITDA of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than borrowings pursuant to any working capital or other revolving facility) or issues, repurchases or redeems preferred stock subsequent to

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the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the“Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect (in accordance withRegulation S-X under the Securities Act) to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period.

In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

(1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations, or any Person or any of its Restricted Subsidiaries acquired by the specified Person or any of its Restricted Subsidiaries, and including all related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date, or that are to be made on the Calculation Date, will be given pro forma effect (in accordance withRegulation S-X under the Securities Act) as if they had occurred on the first day of the four-quarter reference period;

(2) the Consolidated EBITDA attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of on or prior to the Calculation Date, will be excluded;

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of on or prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

(4) any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period;

(5) any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period; and

(6) if any Indebtedness bears a floating rate of interest, the interest expense on such Indebtedness will be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligation applicable to such Indebtedness if such Hedging Obligation has a remaining term as at the Calculation Date in excess of 12 months).

“Fixed Charges”means, with respect to any specified Person for any period, the sum, without duplication, of:

(1) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued, including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings, and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates;plus

(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;plus

(3) any interest on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon;plus

(4) all dividends paid in cash on any series of preferred stock of such Person or any of its Restricted Subsidiaries.

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“Foreign Subsidiary”means any Restricted Subsidiary of Milagro that is not a Domestic Subsidiary.

“GAAP”means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect from time to time.

“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 (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise).

“Guarantors”means:

(1) each of Milagro’s Domestic Subsidiaries as of the Issue Date;

(2) each of Milagro’s Domestic Subsidiaries that becomes a guarantor of the notes pursuant to the covenant described above under “— Certain Covenants — Additional Note Guarantees;” and

(3) each of Milagro’s other Restricted Subsidiaries executing a supplemental indenture in which such Restricted Subsidiary agrees to guarantee the obligations of Milagro under, or to be bound by the terms of the indenture;

providedthat any Person constituting a Guarantor as described above shall cease to constitute a Guarantor when its respective Subsidiary Guarantee is released in accordance with the terms of the indenture.

“Guarantor Subordinated Obligation”means, with respect to a Guarantor, any Indebtedness of such Guarantor which is expressly subordinate in right of payment to the obligations of such Guarantor under its Note Guarantee pursuant to a written agreement.

“Hedge Agreement”means any Interest Rate Agreement or any Oil and Gas Hedging Agreement;providedthat (i) the obligations under such agreement constitute Priority Lien Obligations pursuant to the Credit Agreement or (ii) the obligations under such agreement have been designated as Priority Lien Obligations pursuant to the intercreditor agreement and the counterparty has delivered a joinder in respect thereof.

“Hedging Obligations”means, with respect to any specified Person, the obligations of such Person under any (a) Interest Rate Agreement and (b) Oil and Gas Hedging Agreement.

“Hydrocarbons”means crude oil, natural gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Immaterial Subsidiary”means, as of any date, any Restricted Subsidiary whose total assets, as of that date, are less than $500,000 and whose total revenues for the most recent12-month period do not exceed $500,000;providedthat a Restricted Subsidiary will not be considered to be an Immaterial Subsidiary if it, directly or indirectly, guarantees or otherwise provides direct credit support for any Indebtedness of Milagro

“Indebtedness”means, with respect to any specified Person, any indebtedness of such Person (excluding accrued expenses and trade payables), whether or not contingent:

(1) in respect of borrowed money;

(2) evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);

(3) in respect of banker’s acceptances;

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(4) representing Capital Lease Obligations or Attributable Debt in respect of sale and leaseback transactions;

(5) representing the balance deferred and unpaid of the purchase price of any property or services due more than six months after such property is acquired or such services are completed; or

(6) representing the net amount due under any Hedging Obligations,

if and to the extent any of the preceding items (other than letters of credit, Attributable Debt 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. Indebtedness shall be calculated without giving effect to the effects of Statement of Financial Accounting Standards No. 133 and related interpretations to the extent such effects would otherwise increase or decrease an amount of Indebtedness for any purpose under the indenture as a result of accounting for any embedded derivatives created by the terms of such Indebtedness.

“Initial Reserve Report”means, that certain reserve report prepared by W.D. Von Gonten & Co., dated February 23, 2011, evaluating the Oil and Gas Properties of Milagro and its subsidiaries prepared as of December 31, 2010, true and correct copies of which have been delivered to the Credit Agreement Agent.

“insolvency or liquidation proceeding”means:

(1) any case commenced by or against Milagro or any Guarantor under Title 11, U.S. Code or any similar federal or state law for the relief of debtors, any other proceeding for the reorganization, recapitalization or adjustment or marshalling of the assets or liabilities of Milagro or any Guarantor, any receivership or assignment for the benefit of creditors relating to Milagro or any Guarantor or any similar case or proceeding relative to Milagro or any Guarantor or its creditors, as such, in each case whether or not voluntary;

(2) any liquidation, dissolution, marshalling of assets or liabilities or other winding up of or relating to Milagro or any Guarantor, in each case whether or not voluntary and whether or not involving bankruptcy or insolvency; or

(3) any other proceeding of any type or nature in which substantially all claims of creditors of Milagro or any Guarantor are determined and any payment or distribution is or may be made on account of such claims.

“Interest Rate Agreement”means any interest rate swap agreement (whether from fixed to floating or from floating to fixed), interest rate cap agreement, interest rate collar agreement or other similar agreement or arrangement designed to protect Milagro or any of its Restricted Subsidiaries against fluctuations in interest rates and is not for speculative purposes.

“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 Milagro or any Restricted Subsidiary of Milagro sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of Milagro such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of Milagro, Milagro will be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of Milagro’s Investments in such Subsidiary that were 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 Milagro or any Restricted Subsidiary of Milagro of a Person that holds an Investment in a third Person will be deemed to be an Investment by Milagro or such Restricted Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments

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held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption “— Certain Covenants — Restricted Payments.” Except as otherwise provided in the indenture, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value.

“Issue Date”means the date of the first issuance of notes under the indenture.

“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.

“Mortgaged Property”means any property owned by Milagro or any Guarantor that is subject to the Liens existing and to exist under the terms of the security documents.

“Mortgages”means all mortgages, deeds of trust and similar documents, instruments and agreements (and all amendments, modifications and supplements thereof) creating, evidencing, perfecting or otherwise establishing the Liens on Mortgaged Property to secure payment of the notes and the Note Guarantees or any party thereof.

“Net Proceeds”means the aggregate cash proceeds and Cash Equivalents received by Milagro or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash or Cash Equivalents received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale, taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements, and amounts required to be applied to the repayment of Indebtedness, secured by a Lien on the asset or assets that were the subject of such Asset Sale and any reserve for adjustment or indemnification obligations in respect of the sale price of such asset or assets established in accordance with GAAP.

“Non-Recourse Debt”means Indebtedness:

(1) as to which neither Milagro nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable as a guarantor or otherwise; and

(2) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of Milagro or any of its Restricted Subsidiaries (other than the Equity Interests of an Unrestricted Subsidiary).

“Note Documents”means the indenture, the notes and the security documents.

“Note Guarantee”means the Guarantee by each Guarantor of Milagro’s obligations under the indenture and the notes, executed pursuant to the provisions of the indenture.

“Obligations”means any principal (including reimbursement obligations with respect to letters of credit whether or not drawn), interest (including, to the extent legally permitted, all interest accrued thereon after the commencement of any insolvency or liquidation proceeding at the rate, including any applicable post-default rate, specified in the Priority Lien Documents, even if such interest is not enforceable, allowable or allowed as a claim in such proceeding), premium (if any), fees, indemnifications, reimbursements, expenses and other liabilities payable under the documentation governing any Indebtedness.

“Officers’ Certificate”means, in the case of any Person, a certificate signed by any two of the chief executive officer, president, chief financial officer or any vice president of such Person.

“oil”means crude oil, condensate, natural gas liquids or other liquid Hydrocarbons.

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“Oil and Gas Business”means:

(1) the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, liquefied natural gas and other Hydrocarbon and mineral properties or products produced in association with any of the foregoing;

(2) the business of gathering, marketing, distributing, treating, processing (but not refining), storing, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of oil, natural gas, other Hydrocarbons and minerals obtained from unrelated Persons; and

(3) any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (1) and (2) of this definition.

“Oil and Gas Hedging Agreement”means any puts, cap transactions, floor transactions, collar transactions, forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons to be used, produced, processed or sold by Milagro or any Restricted Subsidiary that are customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbons prices and not for speculative purposes.

“Oil and Gas Liens”means:

(1) Liens on any specific property or any interest therein, construction thereon or improvement thereto to secure all or any part of the costs (other than indebtedness) incurred for surveying, exploration, drilling, extraction, development, operation, production, construction, alteration, repair or improvement of, in, under or on such property and the plugging and abandonment of wells located thereon (it being understood that, in the case of oil and gas producing properties, or any interest therein, costs incurred for “development” will include costs incurred for all facilities relating to such properties or to projects, ventures or other arrangements of which such properties form a part or that relate to such properties or interests);

(2) Liens on an oil or gas producing property to secure obligations incurred or Guarantees of obligations incurred (in each case, other than indebtedness) in connection with or necessarily incidental to commitments for the purchase or sale of, or the transportation or distribution of, the products derived from such property;

(3) Liens arising under partnership agreements, oil and gas leases, overriding royalty agreements, net profits agreements, production payment agreements, royalty trust agreements, incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologist, geophysicists and other providers of technical services to Milagro or a Restricted Subsidiary, farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of oil, gas or other hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, operating agreements, gas balancing or deferred production agreements, production sharing agreements, area of mutual interests agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements that are customary in the Oil and Gas Business;provided, however, that in all instances such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;

(4) Liens securing Production Payments and Reserve Sales;provided, however, that such Liens are limited to the property that is subject to such Production Payments and Reserve Sales, and such Production Payments and Reserve Sales either:

(a) were in existence on the Issue Date,

(b) were created in connection with the acquisition of property after the Issue Date and such Lien was incurred in connection with the financing of, and within 90 days after, the acquisition of the property subject thereto, or

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(c) constitute Asset Sales made in compliance with the provisions described under “— Repurchases at the Option of Holders — Asset Sales;” and

(5) Liens on pipelines or pipelines facilities that arise by operation of law.

“Oil and Gas Properties”means, with respect to any Person, all properties, including equity or other ownership interest therein, owned by such Person or any of its Restricted Subsidiaries which contain “proved oil and gas reserves” as defined inRule 4-10 ofRegulation S-X of the Securities Act

“Parity Lien”means a Lien granted by a security document to the collateral trustee, at any time, upon any property of Milagro or any Guarantor to secure Parity Lien Obligations.

“Parity Lien Cap”means, as of any date of determination, the amount of Parity Lien Debt that may be incurred by Milagro such that, after giving pro forma effect to the incurrence thereof and the application of the proceeds therefrom, the aggregate principal amount of all Parity Lien Debt shall not exceed the greater of (a) $275.0 million and (b) an amount equal to 50% of the Adjusted Consolidated Net Tangible Assets determined as of the date of incurrence;provided, in the case of this clause (b), that after giving pro forma effect to the incurrence of such Parity Lien Debt and the application of the proceeds therefrom, the Senior Secured Leverage Ratio as at the end of Milagro’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such Parity Lien Debt is incurred would have been not greater than 3.5 to 1.0, determined on a pro forma basis (including pro forma application of the net proceeds therefrom) as if such additional Parity Lien Debt had been incurred on the last day of such period.

“Parity Lien Debt”means:

(1) the notes issued on the date of the indenture (including any related exchange notes); and

(2) any other Indebtedness of Milagro (including additional notes) that is secured equally and ratably with the notes by a Parity Lien that was permitted to be incurred and so secured under each applicable Secured Debt Document;providedthat, in the case of any Indebtedness referred to in clause (2) of this definition:

(a) on or before the date on which such Indebtedness is incurred by Milagro, such Indebtedness is designated by Milagro, in an officers’ certificate delivered to each Parity Lien Representative and the collateral trustee, as “Parity Lien Debt” for the purposes of the indenture and the collateral trust agreement;providedthat no Series of Secured Debt may be designated as both Parity Lien Debt and Priority Lien Debt;

(b) such Indebtedness is governed by an indenture, credit agreement or other agreement that includes an Additional Secured Debt Designation; and

(c) all requirements set forth in the collateral trust agreement as to the confirmation, grant or perfection of the collateral trustee’s Liens to secure such Indebtedness or Obligations in respect thereof are satisfied (and the satisfaction of such requirements and the other provisions of this clause (c) will be conclusively established if Milagro delivers to the collateral trustee an officers’ certificate stating that such requirements and other provisions have been satisfied and that such Indebtedness is “Parity Lien Debt”).

“Parity Lien Documents”means, collectively, the Note Documents and any additional indenture, credit agreement or other agreement governing each other Series of Parity Lien Debt and the security documents (other than any security documents that do not secure Parity Lien Obligations).

“Parity Lien Obligations”means Parity Lien Debt and all other Obligations in respect thereof.

“Parity Lien Representative”means:

(1) in the case of the notes, the trustee; or

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(2) in the case of any other Series of Parity Debt, the trustee, agent or representative of the holders of such Series of Parity Lien Debt who (a) is appointed as a Parity Lien Representative (for purposes related to the administration of the security documents) pursuant to the indenture, credit agreement or other agreement governing such Series of Parity Lien Debt, together with its successors in such capacity, and (b) has become a party to the collateral trust agreement by executing a joinder in the form required under the collateral trust agreement.

“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:

(1) ownership of 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 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 (including for limited liability companies), 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.

“Permitted Holder”means each of ACON Milagro Investors, LLC, ACON-Bastion Partners II, LP, ACON Milagro Second Lien Investors, LLC or any Affiliated funds and investment vehicles managed by ACON Funds Management or ACON Investments LLC; 1888 Fund, Ltd., Copper River CLO Ltd., Green Lane CLO Ltd., NZC Guggenheim Master Fund Limited, Sands Point Funding Ltd., Guggenheim Energy Opportunities Fund, LP, Kennecott Funding Ltd., IN-FP1, LLC, New Energy LLC and any Affiliated fund managed by Guggenheim Investment Management, LLC; and West Coast Energy Partners and West Coast Milagro Partners LLC.

“Permitted Investments”means:

(1) any Investment in Milagro or in a Guarantor;

(2) any Investment in Cash Equivalents;

(3) any Permitted Business Investment and any Investment by Milagro or any Restricted Subsidiary of Milagro in a Person whose primary business is the Oil and Gas Business, if as a result of such Investment:

(a) such Person becomes a Guarantor; or

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, Milagro or a Guarantor;

(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 acquisition of assets or Capital Stock solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of Milagro;

(6) any Investments received in compromise or resolution of (a) obligations of trade creditors or customers that were incurred in the ordinary course of business of Milagro or any of its Restricted

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Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; or (b) litigation, arbitration or other disputes;

(7) Investments represented by Hedging Obligations;

(8) loans or advances to employees made in the ordinary course of business of Milagro or any Restricted Subsidiary of Milagro in an aggregate principal amount not to exceed $1.0 million at any one time outstanding;

(9) repurchases of the notes;

(10) any guarantee of Indebtedness permitted to be incurred by the covenant entitled “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” other than a guarantee of Indebtedness of an Affiliate of Milagro that is not a Restricted Subsidiary of Milagro;

(11) any Investment existing on, or made pursuant to binding commitments existing on, the date of the indenture and any Investment consisting of an extension, modification or renewal of any Investment existing on, or made pursuant to a binding commitment existing on, the date of the indenture;providedthat the amount of any such Investment may be increased (a) as required by the terms of such Investment as in existence on the date of the indenture or (b) as otherwise permitted under the indenture;

(12) Investments acquired after the date of the indenture as a result of the acquisition by Milagro or any Restricted Subsidiary of Milagro of another Person, including by way of a merger, amalgamation or consolidation with or into Milagro or any of its Restricted Subsidiaries in a transaction that is not prohibited by the covenant described above under the caption “— Certain Covenants — Merger, Consolidation or Sale of Assets” after the date of the indenture to the extent that such Investments were not made in contemplation of such acquisition, merger, amalgamation or consolidation and were in existence on the date of such acquisition, merger, amalgamation or consolidation;

(13) Investments in any Person organized for and engaged in the business of installing, operating and maintaining geothermal power generation facilities and any related activities for use solely in connection with Oil and Gas Properties in which Milagro or any Restricted Subsidiary has an interest having an aggregate Fair Market Value (measured on the date each such Investment is made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (13) that are at the time outstanding not to exceed the greater of (a) $10.0 million and (b) 2.5% of Adjusted Consolidated Net Tangible Assets; and

(14) other Investments in any Person other than an Affiliate of Milagro that is not a Subsidiary of Milagro having an aggregate Fair Market Value (measured on the date each such Investment is made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (14) that are at the time outstanding not to exceed the greater of (a) $15.0 million and (b) 2.5% of Adjusted Consolidated Net Tangible Assets.

“Permitted Liens”means:

(1) Liens held by the Priority Lien Collateral Agent securing (a) Priority Lien Debt in an aggregate principal amount (as of the date of incurrence of any Priority Lien Debt and after giving pro forma effect to the application of the net proceeds therefrom) not exceeding, on the date of incurrence, the Priority Lien Cap and (b) all other Priority Lien Obligations;

(2) Parity Liens securing (a) Parity Lien Debt in an aggregate principal amount (as of the date of incurrence of such Parity Lien Debt and after giving pro forma effect to the application of the net proceeds therefrom), not exceeding the Parity Lien Cap and (b) all other Parity Lien Obligations;

(3) Liens in favor of Milagro or the Guarantors;

(4) Liens on property (including Capital Stock) existing at the time of acquisition of the property by Milagro or any Subsidiary of Milagro or Liens on property or Equity Interests of another Person at the

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time such other Person becomes a Subsidiary of Milagro or a Restricted Subsidiary;providedthat such Liens were in existence prior to such acquisition and not incurred in contemplation of, such acquisition;

(5) Liens to secure the performance of statutory obligations, insurance, surety or appeal bonds, workers compensation obligations, performance bonds or other obligations of a like nature incurred in the ordinary course of business (including Liens to secure letters of credit issued to assure payment of such obligations);

(6) Liens to secure Indebtedness (including Capital Lease Obligations) permitted by clause (4) of the second paragraph of the covenant entitled “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” covering only the assets acquired with or financed by such Indebtedness and the proceeds thereof;

(7) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded;providedthat any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;

(8) Liens imposed by law, such as carriers’, warehousemen’s, landlord’s and mechanics’ Liens, in each case, incurred in the ordinary course of business;

(9) survey exceptions, easements or reservations of, or rights of others for, licenses,rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions as to the use of real property that were not incurred in connection with Indebtedness and that do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

(10) Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the indenture;provided, however,that:

(a) the new Lien is limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and

(b) the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (i) the outstanding principal amount, or, if greater, committed amount, of the Indebtedness renewed, refunded, refinanced, replaced, defeased or discharged with such Permitted Refinancing Indebtedness and (ii) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge;

(11) Liens on insurance policies and proceeds thereof, or other deposits, to secure insurance premium financings;

(12) filing of Uniform Commercial Code financing statements as a precautionary measure in connection with operating leases;

(13) bankers’ Liens, rights of setoff, Liens arising out of judgments or awards not constituting an Event of Default and notices oflis pendensand associated rights related to litigation being contested in good faith by appropriate proceedings and for which adequate reserves have been made;

(14) Liens on cash, Cash Equivalents or other property arising in connection with the defeasance, discharge or redemption of Indebtedness;

(15) Liens on specific items of inventory or other goods (and the proceeds thereof) of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created in the ordinary course of business for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(16) grants of software and other technology licenses in the ordinary course of business;

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(17) Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into in the ordinary course of business;

(18) any (a) interest or title of a lessor or sublessor under any lease, liens reserved in oil, gas or other Hydrocarbons or minerals leases for bonus, royalty or rental payments and for compliance with the terms of such leases; (b) restriction or encumbrance that the interest or title of such lessor or sublessor may be subject to (including, without limitation, ground leases or other prior leases of the demised premises, mortgages, mechanics’ liens, tax liens, and easements); or (c) subordination of the interest of the lessee or sublessee under such lease to any restrictions or encumbrance referred to in the preceding clause (b);

(19) Oil and Gas Liens;

(20) Liens on pipelines or pipeline facilities that arise by operation of law; and

(21) Liens incurred in the ordinary course of business of Milagro or any Restricted Subsidiary of Milagro with respect to obligations that do not exceed the greater of $10.0 million and 1% of Milagro’s Adjusted Consolidated Net Tangible Assets, determined as of the date of incurrence of such obligations, at any one time outstanding.

“Permitted Prior Liens”means those Liens which, under each of the Priority Lien Documents, are permitted to be incurred on a priority basis to the Priority Liens.

“Permitted Refinancing Indebtedness”means any Indebtedness of Milagro or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge other Indebtedness of Milagro or any of its Restricted Subsidiaries (other than intercompany Indebtedness);providedthat:

(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 renewed, refunded, refinanced, replaced, defeased or discharged (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness has (a) a final maturity date not earlier than the earlier of (i) the final maturity date of the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged and (ii) more than 90 days after the final maturity date of the notes, and (b) has a Weighted Average Life to Maturity that is equal to or greater than the Weighted Average Life to Maturity of the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged;

(3) if the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged is subordinated in right of payment to the notes, such Permitted Refinancing Indebtedness is subordinated in right of payment to the notes on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged; and

(4) such Indebtedness is incurred either by Milagro or by the Restricted Subsidiary of Milagro that was the obligor on the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged and is guaranteed only by Persons who were obligors on the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged.

“Person”means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Priority Lien”means a Lien granted by a security document to the Priority Lien Collateral Agent, at any time, upon any property of Milagro or any Guarantor to secure Priority Lien Obligations.

“Priority Lien Cap”means, as of any date, (a) the principal amount of Indebtedness under the Credit Agreementand/or any other Credit Facility that may be incurred under clause (1) of the definition of Permitted Debt as of such date,plus(b) the amount of all Hedging Obligations and Indebtedness and Obligations under

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Hedge Agreements, to the extent such Obligations and Indebtedness are secured by the Priority Liens,plus(c) the amount of all Banking Services Obligations, to the extent such Obligations are secured by the Priority Liens. For purposes of this definition, all letters of credit will be valued at the face amount thereof, whether or not drawn.

“Priority Lien Collateral Agent”means Wells Fargo Bank, N.A., as agent under the Credit Agreement and any successor thereof in such capacity under the Credit Agreement, or if the Credit Agreement ceases to exist, the collateral agent or other representative of lenders or holders of Priority Lien Obligations designated pursuant to the terms of the Priority Lien Documents and the intercreditor agreement.

“Priority Lien Debt”means:

(1) Indebtedness of Milagro under the Credit Agreement (including letters of credit and reimbursement obligations with respect thereto) that was permitted to be incurred and secured under each applicable Secured Debt Document (or as to which the lenders under the Credit Agreement obtained an officers’ certificate at the time of incurrence to the effect that such Indebtedness was permitted to be incurred and secured by all applicable Secured Debt Documents); and

(2) additional Indebtedness of Milagro under any other Credit Facility that is secured with the Credit Agreement by a Priority Lien that was permitted to be incurred and so secured under each applicable Secured Debt Document;provided, in the case of any Indebtedness referred to in this clause (2), that:

(a) on or before the date on which such Indebtedness is incurred by Milagro, such Indebtedness is designated by Milagro, in an officers’ certificate delivered to the Priority Lien Collateral Agent and the collateral trustee, as “Priority Lien Debt” for the purposes of the Secured Debt Documents and the intercreditor agreement;providedthat no Series of Secured Debt may be designated as both Parity Lien Debt and Priority Lien Debt;

(b) the collateral agent or other representative with respect to such Indebtedness, the Priority Lien Collateral Agent, the collateral trustee, the issuers and each applicable Guarantor have duly executed and delivered the intercreditor agreement (or a joinder to the intercreditor agreement or a new intercreditor agreement substantially similar to the intercreditor agreement, as in effect on the date of the indenture, and in a form reasonably acceptable to each of the parties thereto); and

(c) all other requirements set forth in the intercreditor agreement as to the confirmation, grant or perfection of the Priority Lien Collateral Agent’s Liens to secure such Indebtedness or Obligations in respect thereof are satisfied.

“Priority Lien Documents”means the Credit Agreement and any other Credit Facility pursuant to which any Priority Lien Debt is incurred and the security documents (other than any security documents that do not secure Priority Lien Obligations).

“Priority Lien Obligations”means the Priority Lien Debt and all other Obligations in respect of Priority Lien Debt together with Hedging Obligations and the Banking Services Obligations.

“Priority Lien Representative”means (1) the Credit Agreement Agent or (2) in the case of any other Series of Priority Lien Debt, the trustee, agent or representative of the holders of such Series of Priority Lien Debt who maintains the transfer register for such Series of Priority Lien Debt and is appointed as a representative of the Priority Debt (for purposes related to the administration of the security documents) pursuant to the credit agreement or other agreement governing such Series of Priority Lien Debt.

“Production Payments and Reserve Sales”means the grant or transfer by Milagro or any of its Restricted Subsidiaries to any Person of a royalty, overriding royalty, net profits interest, production payment, partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or to use reasonable efforts to cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard and subject to the obligation of the

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grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business.

“Recognized Value”means, with respect to the Oil and Gas Properties of Milagro and the Guarantors constituting proved reserves, the discounted present value of the estimated net cash flow to be realized from the production of Hydrocarbons from all such Oil and Gas Properties which the Credit Agreement Agent attributes to such Oil and Gas Properties for the purposes of the most recent redetermination of the borrowing base under the Credit Agreement (or for purposes of determining the initial borrowing base in the event no such redetermination has occurred);provided, that if the Credit Agreement is terminated and not restated, renewed, refunded, replaced or refinanced Milagro, acting in good faith, shall continue to make redeterminations of Recognized Value from time to time in the same manner as if the Credit Agreement were still in effect;provided, further, that in making the redeterminations required by the preceding proviso, present value shall be determined using a 10% discount factor and SEC pricing.

“Required Parity Lien Debtholders”means, at any time, the holders of a majority in aggregate principal amount of all Parity Lien Debt then outstanding, calculated in accordance with the provisions described above under the caption “— Collateral Trust Agreement — Voting.” For purposes of this definition, Parity Lien Debt registered in the name of, or beneficially owned by, Milagro or any Affiliate of Milagro will be deemed not to be outstanding.

“Reserve Report”means a report setting forth, as of each December 31st and June 30th, the oil and gas reserves attributable to the proved Oil and Gas Properties of Milagro and the Guarantors, together with a projection of the rate of production and future net income, taxes, operating expenses and capital expenditures with respect thereto as of such date. Until superseded, the Initial Reserve Report will be considered the Reserve Report.

“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.

“Sale of Collateral”means any Asset Sale involving a sale or other disposition of Collateral.

“SEC”means the United States Securities and Exchange Commission.

“Secured Debt”means Parity Lien Debt and Priority Lien Debt.

“Secured Debt Documents”means the Parity Lien Documents and the Priority Lien Documents.

“security documents”means the collateral trust agreement, each joinder agreement required by the collateral trust agreement, and all security agreements, pledge agreements, collateral assignments, mortgages, deeds of trust, collateral agency agreements, control agreements or other grants or transfers for security executed and delivered by Milagro or any Guarantor creating (or purporting to create) a Lien upon Collateral in favor of the collateral trustee, in each case, as amended, modified, renewed, restated or replaced, in whole or in part, from time to time, in accordance with its terms and the provisions described above under the caption “— Collateral Trust Agreement — Amendment of Security Documents.”

“Senior Secured Debt” means the aggregate outstanding principal amount of all Priority Lien Debt and Parity Lien Debt, determined in accordance with GAAP.

“Senior Secured Leverage Ratio” means the ratio of the Senior Secured Debt as of the last day of any period of four full fiscal quarters to Milagro’s Consolidated EBITDA for such period. In the event that Milagro or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Senior Secured Debt (other than borrowings pursuant to any working capital or other revolving facility) subsequent to the commencement of the period for which the Senior Secured Leverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Senior Secured Leverage Ratio is made (the “Calculation Date”), then the Senior Secured Leverage Ratio will be calculated giving pro forma effect (in accordance withRegulation S-X under the Securities Act) to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of

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Indebtedness and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period.

In addition, for purposes of calculating the Senior Secured Leverage Ratio:

(1) acquisitions that have been made by Milagro or any of its Restricted Subsidiaries, including through mergers or consolidations, or any Person or any of its Restricted Subsidiaries acquired by Milagro or any of its Restricted Subsidiaries, and including all related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date, or that are to be made on the Calculation Date, will be given pro forma effect (in accordance withRegulation S-X under the Securities Act) as if they had occurred on the first day of the four-quarter reference period;

(3) any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period; and

(4) any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period.

“Series of Parity Lien Debt”means, severally, the notes and each other issue or series of Parity Lien Debt for which a single transfer register is maintained.

“Series of Priority Lien Debt”means, severally, the Indebtedness outstanding under the Credit Agreement and any other Credit Facility that constitutes Priority Lien Debt.

“Series of Secured Debt”means each Series of Parity Lien Debt and each Series of Priority Lien Debt.

“Significant Subsidiary”means any Restricted Subsidiary that would be a “significant subsidiary” as defined in Article 1,Rule 1-02 ofRegulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the indenture.

“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 documentation governing such Indebtedness as of the date of the indenture, 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.

“Subordinated Obligation”means any Indebtedness of Milagro which is expressly subordinate or junior in right of payment to the notes.

“Subsidiary”means, with respect to any specified Person:

(1) any corporation, association or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency and after giving effect to any voting agreement or stockholders’ agreement that effectively transfers voting power) to vote in the election of directors, managers or trustees of the corporation, association or other business entity is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership or limited liability company of which (a) more than 50% of the capital accounts, distribution rights, total equity and voting interests or general and limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof, whether in the form of membership, general, special or limited partnership interests or otherwise, and (b) such Person or any Subsidiary of such Person is a controlling general partner or otherwise controls such entity.

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“Treasury Rate”means, as of any redemption date, the yield to maturity as of such redemption date 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 of similar market data)) most nearly equal to the period from the redemption date to May 15, 2014;provided, however, that if the period from the redemption date to May 15, 2014 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.

“Unrestricted Subsidiary”means any Subsidiary of Milagro that is designated by the Board of Directors of Milagro as an Unrestricted Subsidiary pursuant to a resolution of the Board of Directors, but only to the extent that such Subsidiary:

(1) has no Indebtedness other than Non-Recourse Debt;

(2) except as permitted by the covenant described above under the caption “— Certain Covenants — Transactions with Affiliates,” is not party to any agreement, contract, arrangement or understanding with Milagro or any Restricted Subsidiary of Milagro unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to Milagro or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of Milagro;

(3) is a Person with respect to which neither Milagro 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

(4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of Milagro or any of its Restricted Subsidiaries.

“Volumetric Production Payments”means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock”of any specified Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

“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

(2) the then outstanding principal amount of such Indebtedness.

“Wholly-Owned Restricted Subsidiary”of any specified Person means a Restricted Subsidiary of such Person all of the outstanding Capital Stock or other ownership interests of which (other than directors’ qualifying shares) will at the time be owned by such Person or by one or more Wholly-Owned Restricted Subsidiaries of such Person.

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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of certain U.S. federal income tax consequences relevant to the exchange of the exchange notes for the old notes, but does not purport to be a complete analysis for all potential tax effects. The summary is based upon the Internal Revenue 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 the exchange notes. The description does not consider the effect of any applicable foreign, state, local or other tax laws or estate or gift tax considerations.Each holder is encouraged to consult, and depend on, his own tax advisor in analyzing the particular tax consequences of exchanging such holder’s old notes for the exchange notes, including the applicability and effect of any federal, state, local and foreign tax laws.

The exchange of the exchange notes for the old notes will not be a taxable event to a holder for United States federal income tax purposes. Accordingly, a holder will have the same adjusted issue price, adjusted basis and holding period in the exchange notes as it had in the old notes immediately before the exchange.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives exchange 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 exchange 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 exchange notes received in exchange for unregistered notes where such unregistered notes were acquired as a result of market-making activities or other trading activities. To the extent any such broker-dealer participates in the exchange offer, we have agreed that for a period of up to 180 days we will use commercially reasonable efforts to make this prospectus, as amended or supplemented, available to such broker-dealer for use in connection with any such resale, and will deliver as many additional copies of this prospectus and each amendment or supplement to this prospectus and any documents incorporated by reference in this prospectus as such broker-dealer may reasonably request.

We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own accounts pursuant to the exchange offer may be sold from time to time in one or more transactions in theover-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of these methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. 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 exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under 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 have agreed to pay all expenses incident to the exchange offer and will indemnify the holders of outstanding notes, including any broker-dealers, against certain liabilities, including liabilities under the Securities Act.

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LEGAL MATTERS

The validity of the exchange notes and certain legal matters in connection with this exchange offer will be passed upon for us by Porter Hedges LLP, Houston, Texas, and Garvey Schubert Barer, New York, New York.

EXPERTS

The consolidated financial statements of Milagro Oil & Gas, Inc. and subsidiaries as of December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes explanatory paragraphs referring to (1) the Company’s ability to continue as a going concern; and (2) the adoption of oil and gas reserve estimation and disclosure rules effective December 31, 2009). Such financial statements are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

Certain information with respect to the oil and gas reserves of Milagro Oil & Gas, Inc. and its subsidiaries is derived from the reports of W.D. Von Gonten & Co., independent consulting petroleum engineers, and has been included in this prospectus upon the authority of said firm as experts with respect to the matters covered in such report and in giving such report.

WHERE YOU CAN FIND MORE INFORMATION

Prior to the consummation of the exchange offer, we were not required to file periodic reports and other information with the SEC pursuant to the informational requirements of the Exchange Act. As a result of the offering of the exchange notes and the effectiveness of the registration statement onForm S-4 of which this prospectus is a part, we will be subject to the reporting and informational requirements of the Exchange Act.

Any filing that we make with the SEC may be inspected and copied at the public reference room maintained by the SEC at 100 F. Street, N.E., Washington, D.C. Please call the SEC at1-800-SEC-0330 for further information relating to the public reference room. In addition, certain reports and other information regarding us will be available on the SEC’s website,http://www.sec.gov. You may also request a copy of such information at no cost, by writing or telephoning us, at the following: Milagro Oil & Gas, Inc., 1301 McKinney Street, Suite 500, Houston, Texas 77010, telephone number:(713) 750-1600, Attn: General Counsel.

This prospectus, which constitutes a part of a registration statement onForm S-4 filed by us with the SEC under the Securities Act, omits certain information contained in the registration statement. Accordingly, you should refer to the registration statement and its exhibits for further information with respect to us and the new notes offered for exchange. Furthermore, statements contained in this prospectus regarding any contract or other document are not necessarily complete, and, in each instance, you should refer to the copy of the contract or other document filed with the SEC as an exhibit to the registration statement.

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GLOSSARY OF OIL & GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and in this prospectus. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained inRule 4-10(a) ofRegulation S-X.

3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid.3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.

BBbl. One billion Bbls.

Bcf. One billion cubic feet of natural gas.

Boe. One barrel equivalent of crude oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

Boe/d. Boe per day.

Completion. The installation of permanent equipment for the production of oil or natural gas. Completion of the well does not necessarily mean the well will be profitable.

Completion Rate. The number of wells on which production casing has been run for a completion attempt as a percentage of the number of wells drilled.

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 Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of an oil or natural gas well.

Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

Fault. A break in the rocks along which there has been movement of one side relative to the other side.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.

Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

MBoe/d. MBoe per day.

Mcf. One thousand cubic feet of natural gas.

MMBbl. One million barrels of oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

192

MMcf. One million cubic feet of natural gas.

Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage working interest we own.

Net Production. Production that we own less royalties and production due others.

Oil. Crude oil, condensate or other liquid hydrocarbons.

Operator. The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.

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.

Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Reserves. The estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved Undeveloped Reserves. 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.

Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized Measure. The after-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

Trend. A geographical area that has been known to contain certain types of combinations of reservoir rock, sealing rock and trap types containing commercial amounts of hydrocarbons.

Undeveloped Acreage. Acreage which is not allocated or assignable to producing wells or wells capable of production.

Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

193

INDEX TO FINANCIAL STATEMENTS


	Page

Report of Independent Registered Public Accounting Firm		F-2
Consolidated Financial Statements as of December 31, 2010 and 2009, and for the Years Ended December 31, 2010, 2009, and 2008:
Balance sheets		F-3
Statements of operations		F-4
Statements of changes in equity (deficit)		F-5
Statements of cash flows		F-6
Notes to consolidated financial statements		F-7
Condensed Consolidated Unaudited Financial Statements as of June 30, 2011, and for the Three and Six Months Ended June 30, 2011 and June 30, 2010:
Balance sheets		F-26
Statements of operations		F-27
Statements of changes in equity (deficit)		F-28
Statements of cash flows		F-29
Notes to consolidated unaudited financial statements		F-30
Supplemental Disclosure About Oil & Gas Producing Activities		F-45

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Milagro Oil & Gas, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Milagro Oil & Gas, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in equity (deficit), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the 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.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Milagro Oil & Gas, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for oil and gas reserves and disclosures on December 31, 2009.

The accompanying financial statements for the year ended December 31, 2010 have been prepared assuming that the Company will continue as a going concern. As discussed in Note 11 to the financial statements, the Company has substantial debt maturing in November 2011, which raises substantial doubt about its ability to continue as a going concern. Management’s plans concerning these matters are also described in Note 11. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Deloitte & Touche LLP

Houston, Texas

March 31, 2011 (October 26, 2011 as to the disclosure of the corrections of errors in Note 1, and also as to Note 12, Note 17, Note 18, and Note 19)

F-2

MILAGRO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2010 AND 2009


	2010			2009
	(Amounts in thousands)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,734		$	10,531
Accounts receivable:
Oil and gas sales		18,480			19,179
Joint interest billings and other — net of allowance for doubtful accounts of $615 and $620 in 2010 and 2009, respectively		2,530			1,661
Derivative assets — current		18,834			22,378
Deferred income taxes		—			4,235
Prepaid expenses and other		2,518			2,028

Total current assets		60,096			60,012

PROPERTY, PLANT AND EQUIPMENT:
Oil and gas properties — full cost method:
Proved properties		1,181,948			1,037,129
Unproved properties		13,156			43,887
Less accumulated depreciation, depletion and amortization		(743,637	)		(691,564	)

Net oil and gas properties		451,467			389,452
Other property and equipment — net of accumulated depreciation of $5,436 and $3,237 in 2010 and 2009, respectively		1,718			3,452

Net property, plant and equipment		453,185			392,904

DERIVATIVE ASSETS		2,646			12,241

OTHER ASSETS:
Deferred income taxes		—			53,187
Advance to affiliate		2,248			2,115
Other		4,023			5,601

Total other assets		6,271			60,903

TOTAL	$	522,198		$	526,060


LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	39,672		$	34,905
Current portion of long-term debt		244,580			—
Accrued interest payable		1,959			20,146
Derivative liabilities		9,427			10,304
Asset retirement obligation — current		2,921			5,664

Total current liabilities		298,559			71,019

NONCURRENT LIABILITIES:
Long-term debt		92,390			491,550
Series A preferred stock (Note 10)		223,630			—
Asset retirement obligation — noncurrent		37,350			24,457
Derivative liabilities — noncurrent		2,926			4,923
Other		3,173			1,143

Total noncurrent liabilities		359,469			522,073

Total liabilities		658,028			593,092
COMMITMENTS AND CONTINGENCIES (Note 13)
EQUITY
Common shares (par value, $0.01 per share; shares authorized:
1,000,000; shares issued and outstanding: 280,400 as of December 31, 2010 and 2009, respectively)		3			3
Additionalpaid-in-capital		(66,813	)		(68,603	)
Accumulated (deficit)/retained earnings		(69,020	)		1,568

Total deficit		(135,830	)		(67,032	)

TOTAL	$	522,198		$	526,060

See notes to consolidated financial statements.

F-3

MILAGRO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008


	2010			2009			2008
	(Amounts in thousands)

REVENUES:
Oil and gas revenues	$	134,207		$	128,782		$	360,294
Gain on commodity derivatives		22,943			25,606			50,259

Total revenues		157,150			154,388			410,553

COSTS AND EXPENSES:
Gathering and transportation		1,282			1,925			4,348
Lease operating		34,283			32,542			42,078
Taxes other than income		10,904			9,017			24,585
Depreciation, depletion, and amortization		54,272			68,899			143,648
Full cost ceiling impairment		—			39,638			429,926
General and administrative		17,469			18,849			19,499
Accretion		2,627			2,712			2,793

Total costs and expenses		120,837			173,582			666,877

OTHER (INCOME) EXPENSE:
Net loss on interest rate derivatives		2,127			5,725			14,137
Other (income) expense		(669	)		552			(2,000	)
Interest and related expenses, net of amounts capitalized		48,021			40,587			35,400
Loss on extinguishment of debt		—			—			15,051

Total other expense		49,479			46,864			62,588

LOSS BEFORE INCOME TAX		(13,166	)		(66,058	)		(318,912	)
INCOME TAX EXPENSE (BENEFIT)		57,422			(57,422	)		—

NET LOSS	$	(70,588	)	$	(8,636	)	$	(318,912	)

See notes to consolidated financial statements.

F-4

MILAGRO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (DEFICIT)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008


	Total							Additional						Total
	Members’			Common Stock				Paid in			Accumulated			Stockholders’
	Equity*			Shares		Par Value		Capital			Earnings (Deficit)			Equity (Deficit)
	(Amounts in thousands)
	(In thousands, except for share amounts)

BALANCE — December 31, 2007	$	256,710			—	$	—	$	—		$	—		$	—
Net loss		(318,912	)												—
Stock based compensation		1,951													—

BALANCE — December 31, 2008		(60,251	)		—		—		—			—			—
Net loss January 1, 2009 through July 31, 2009		(10,204	)												—
Distributions		(96	)												—
Stock based compensation		1,136													—

Equity at July 31, 2009		(69,415	)												—
Entity conversion from LLC toC-Corp.		69,415							(69,415	)					(69,415	)
Issuance of common stock					280,400		3		(3	)					—
Net income August 1, 2009 through December 31 ,2009												1,568			1,568
Stock based compensation									815						815

BALANCE — December 31, 2009		—			280,400		3		(68,603	)		1,568			(67,032	)
Net loss												(70,588	)		(70,588	)
Stock based compensation									1,788						1,788
Contributions									2						2

BALANCE — December 31, 2010	$	—			280,400	$	3	$	(66,813	)	$	(69,020	)	$	(135,830	)


*		Upon written consent of the Board of Directors and Members of the Company, effective on August 1, 2009, the Company converted from an LLC to a corporation under Sub Chapter C of the Internal Revenue Code.

See notes to consolidated financial statements.

F-5

MILAGRO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008


	2010			2009			2008
	(Amounts in thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(70,588	)	$	(8,636	)	$	(318,912	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion and amortization		54,272			68,899			143,648
Full cost ceiling impairment					39,638			429,926
Amortization of deferred financing costs		1,752			1,737			2,028
Accretion of asset retirement obligation		2,627			2,712			2,793
Accrued second lien forbearance fee		—			4,998			—
Deferred income taxes		56,811			(57,217	)		39
PIK note interest		29,003						(1,250	)
Unrealized loss (gain) on commodity derivatives		16,412			18,521			(67,864	)
Unrealized (gain) loss on interest rate derivatives		(6,148	)		(3,173	)		12,512
Amortization of recapitalization of debt loss		1,135			—			—
Stock-based compensation expense		1,788			1,951			1,951
Loss on debt extinguishment		—			—			15,051
Changes in assets and liabilities — net of acquisitions:
Accounts receivable and accrued revenue		(170	)		22,061			14,882
Prepaid expenses and other		(490	)		5,081			893
Accounts payable and accrued liabilities		8,913			(3,341	)		(10,231	)

Net cash from operating activities		95,317			93,231			225,466

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and gas properties		(66,194	)					(7,550	)
Additions of oil and gas properties		(34,539	)		(61,230	)		(200,538	)
Additions of other property		(573	)					(4,104	)
Proceeds from sale of oil and gas properties		235			32,117			14,719

Net cash from investing activities		(101,071	)		(29,113	)		(197,473	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Cash overdraft		—			—			2,141
Proceeds from borrowings		60,000			14,500			171,500
Payments of Petrohawk note		—			—			(100,000	)
Payments of borrowings		(47,048	)		(67,872	)		(91,078	)
Deferred financing costs paid		—			(119	)		(10,556	)
Other long-term liabilities		3			—			—
Capital contributions (distributions)		2			(96	)		—

Net cash from financing activities		12,957			(53,587	)		(27,993	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		7,203			10,531			—
CASH AND CASH EQUIVALENTS — Beginning of year		10,531			—			—

CASH AND CASH EQUIVALENTS — End of year	$	17,734		$	10,531		$	—

INCOME TAX PAID — Net of refunds	$	—		$	—		$	—

INTEREST PAID — Net of interest capitalized of $2,391, $4,587, and $6,272 in 2010, 2009, and 2008, respectively	$	11,358		$	13,901		$	40,049

SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Acquisition:
Acquisitions of oil and gas properties	$	—		$	—		$	(22,444	)

Acquisitions of other assets and liabilities	$	(750	)	$	—		$	(2,556	)

Forgiveness of PIK note	$	—		$	—		$	(25,000	)

Recapitalization:
Issuance of series A preferred stock	$	198,712		$	—		$	—

Interest paid in kind — series A preferred stock	$	23,783		$	—		$	—

Forgiveness of forbearance fee	$	4,000		$	—		$	—

Settlement of second lien debt	$	(194,712	)	$	—		$	—

Interest paid in kind — second lien	$	5,220		$	—		$	—

Interest and fees converted to debt	$	21,960		$	—		$	—

Accrued capital and seismic costs included in proved properties	$	5,604		$	283		$	32,435

Asset retirement obligations incurred	$	3,359		$	14		$	1,669

See notes to consolidated financial statements.

F-6

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008


1.	ORGANIZATION

Milagro Oil & Gas, Inc. (the “Company” or “Milagro”) is an independent oil and gas exploration and production company. The Company was organized as a Delaware limited liability company on November 30, 2007. Upon written consent of the Board of Directors and Members of the Company, effective on August 1, 2009, the Company converted from an LLC to a corporation under Sub Chapter C of the Internal Revenue Code, and thereby changed its tax status, and is now a taxable entity. As a result, most operations of the Company are subject to federal income taxes.

The Company owns 100% of Milagro Exploration, LLC, Milagro Resources, LLC, Milagro Producing, LLC and Milagro Mid-Continent, LLC and is a subsidiary of Milagro Holdings, LLC, (Parent). Each of these subsidiaries is included in the consolidated financial statements. All intercompany accounts and transactions are eliminated in consolidation.

Milagro’s historic geographic focus has been along the onshore Gulf Coast area, primarily in Texas, Louisiana and Mississippi. The Company operates a significant portfolio of oil and gas producing properties and mineral interests in this region and has expanded its footprint through the acquisition and development of additional producing or prospective properties in North Texas and Western Oklahoma.

Restatement

Subsequent to the issuance of the 2009 financials, the Company determined that a reporting error had occurred on the balance sheet due to classification errors between the current and non-current portions of the deferred tax assets. This error had no impact on retained earnings or net loss as previously reported and were determined not to be material to the 2009 consolidated financial statements. The balance sheet amounts as previously reported and as restated are as follows:


	As
	Previously					As
	Reported		Adjustment			Restated

Balance Sheet – December 31, 2009
Deferred income taxes — current		6,294		(2,059	)		4,235
Total current assets		62,071		(2,059	)		60,012
Deferred income taxes — noncurrent		50,518		2,669			53,187
Total assets		525,450		610			526,060
Accounts payable and accrued liabilities		34,295		610			34,905
Total liabilities		592,482		610			593,092

The Company determined that an error was reported in the 2010 income tax disclosure of total gross deferred tax assets and liabilities. The Company has recorded a full valuation allowance as of December 31, 2010. This error had no impact on the balance sheet as of December 31, 2010 and impacted footnote disclosure only. See Note 12 for the corrected disclosure.

The Company has corrected a calculation error that was identified on the 2010 balance sheet relating to the asset retirement obligations.

The Company also determined that the supplemental disclosure of cash paid for interest during 2010 was incorrect. The correction had no effect on any of the categories presented in the statement of cash flows.

F-7

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

These errors had no impact on retained earnings or net loss, as previously reported and were determined not to be material to the 2010 consolidated financial statements. The balance sheet and cash flow amounts as previously reported and as restated are as follows:


	As Previously
	Reported		Adjustment			As Restated

Balance Sheet – December 31, 2010
Oil and gas properties — proved		1,180,674		1,274			1,181,948
Total assets		520,924		1,274			522,198
Asset retirement obligation — noncurrent		36,076		1,274			37,350
Total liabilities		656,754		1,274			658,028
Supplemental Cash Flow Disclosure – December 31, 2010
Interest paid — net of interest capitalized of $2,391		20,195		(8,837	)		11,358


2.	ACQUISITIONS

Management considers the most significant fair value estimates associated with acquisitions to be proved oil and gas properties and derivatives. The fair value of proved properties was estimated utilizing the value of underlying oil and gas reserves as of the transaction date. The estimation of the fair value of derivatives is described in Note 9.

RAM — On December 8, 2010, the Company completed the acquisition of certain North Texas assets from RWG Energy, Inc., a wholly-owned subsidiary of RAM Energy Resources, Inc. for a purchase price of $43.75 million, subject to normal and customary purchase price adjustments. The assets acquired in the transaction include producing wells in Jack and Wise Counties, Texas. The acquisition was accounted for using the acquisition method of accounting using the accounting standards established in Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC or the “Codification”) 805,Business Combinations(ASC 805). The estimated fair values of the assets acquired and liabilities assumed were oil and natural gas properties of $44.5 million, other assets of $91,000, asset retirement obligations of $766,000 and other liabilities of $2.4 million. The acquisition was funded with cash on hand and proceeds from borrowings.

Venoco — On May 14, 2010, the Company completed the acquisition of certain Gulf Coast assets of TexCal Energy South Texas, L.P., a subsidiary of Venoco, Inc., for a purchase price of $24.0 million, subject to normal and customary purchase price adjustments. The assets acquired in the transaction included producing wells in various counties along the Texas Gulf Coast. The acquisition was accounted for using the acquisition method of accounting using ASC 805. The estimated fair values of the assets acquired and liabilities assumed were oil and natural gas properties of $22.4 million, other assets of $34,000, asset retirement obligations of $1.8 million and other liabilities of $0.5 million. The acquisition was funded with proceeds from borrowings.

The following table reflects pro forma oil and gas revenues and net loss for the year ended December 31, 2010 as if these acquisitions had taken place on January 1, 2009. There were no acquisitions in 2009. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.


	2010			2009
	(Unaudited)			(Unaudited)

Oil and gas revenues	$	144,864		$	146,445
(Net loss)/income		(62,461	)		3,711

Actual oil and gas revenues and net income before taxes recorded in 2010 from the acquisitions were $6.3 million and $3.6 million, respectively.

F-8

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


3.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates — The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America “U.S. GAAP” requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. These estimates include oil and natural gas reserve quantities that form the basis for (i) the allocation of purchase price to proved and unproved properties, (ii) calculation of amortization of oil and natural gas properties and (iii) the full cost ceiling test. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Other significant estimates include (i) estimated quantities and prices of oil and gas sold, but not collected, as of period-end; (ii) accruals of capital and operating costs; (iii) current plug and abandonment costs, settlement date, inflation rate and credit-adjusted risk-free rate used in estimating asset retirement obligations; (iv) those assumptions and calculation techniques that relate to the determination of the fair value of stock-based compensation, as detailed in Note 7; and (v) those assumptions and calculation techniques used in estimating the fair value of derivative financial instruments, as considered in Note 9. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.

Oil and Gas Properties:

Full Cost Accounting — The Company utilizes the full cost method to account for its investment in oil and gas properties. Under the full cost method, which is governed by the U.S. Securities and Exchange Commission “SEC”Rule 4-10 ofRegulation S-X, all costs of acquisition, exploration, and development of oil and gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and gas properties when incurred. Direct internal costs that are capitalized are primarily the salary and benefits of geologists, landmen, and engineers directly involved in acquisition, exploration and development activities. There were approximately $3.8 million, $5.6 million, and $4.5 million of direct internal costs capitalized for the years ended December 31, 2010, 2009, and 2008, respectively.

Depreciation, Depletion, and Amortization — The cost of oil and gas properties; the estimated future expenditures to develop proved reserves; and estimated future abandonment, site remediation and dismantlement costs are depleted and charged to operations using theunit-of-production method based on the ratio of current production to proved oil and gas reserves as estimated by independent engineering consultants. The Company’s depletion rate for the years ended December 31, 2010, 2009 and 2008 was $15.75, $15.93 and $24.96 per Mboe, respectively.

Impairment — Full cost ceiling impairment is calculated, whereby net capitalized costs related to proved and unproved properties less related deferred income taxes may not exceed a ceiling limitation. The ceiling limitation is the amount equal to the present value discounted at 10% of estimated future net revenues from estimated proved reserves plus the lower of cost or fair value of unproved properties less estimated future production and development costs and net of related income tax effect. For 2010 and 2009, the full cost ceiling limitation is calculated using12-month average price of oil and natural gas as of the first day of each month for the period ending as of the balance sheet date and is adjusted for “basis” or location differentials. For 2008, the price is based on the spot price as of December 31, 2008. Price is held constant over the life of the reserves. If net capitalized costs related to proved properties less related deferred income taxes exceed the ceiling limitation, the excess is impaired and a permanent write-down is recorded in the consolidated statements of operations.

F-9

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company assesses all items classified as unproved property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Such unproved property costs fall into four broad categories:


	•	Projects that are in the last one to two years of seismic evaluation

	•	Leasehold costs for projects not yet evaluated

	•	Drilling and completion costs for projects in progress at period end that have not resulted in the recognition of reserves for that period

	•	Interest costs related to financing such activities

At December 31, 2010, the Company made the decision to focus on developing the proved undeveloped reserves acquired in the Venoco and RAM acquisitions during 2010, therefore, $26.9 million of unproved lease costs remaining from the Petrohawk acquisition in 2007 was reclassified into the full cost pool to be amortized as there are no future plans to evaluate this acreage.

Sales of Properties — Dispositions of oil and gas properties held in the full cost pool are recorded as adjustments to net capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.

Property, Plant and Equipment Other Than Oil and Natural Gas Properties — Other operating property and equipment are stated at cost. The provision for depreciation is calculated using the straight-line method over the estimated useful lives of the respective assets. The cost of normal maintenance and repairs is charged to operating expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of properties sold or otherwise disposed of and the related accumulated depreciation or amortization are removed from the accounts, and any gains or losses are reflected in current operations.

Revenue Recognition and Gas Imbalances — Revenues are recognized and accrued as production occurs and physical possession and title pass to the customer.

The Company uses the sales method of accounting for revenue. Under this method, oil and gas revenues are recorded for the amount of oil and natural gas production sold to purchasers. Gas imbalances are created, but not recorded, when the sales amount is not equal to the Company’s entitled share of production unless there are insufficient reserves. The Company’s entitled share is calculated as gross production from the property multiplied by the Company’s net revenue interest in the property. No provision is made for an imbalance unless the oil and gas reserves attributable to a property have depleted to the point that there are insufficient reserves to satisfy existing imbalance positions. At that point, a payable or a receivable, as appropriate, is recorded equal to the net value of the imbalance. As of December 31, 2010 and 2009, the Company had recorded a liability of $725,000 and $1,418,000, respectively.

Accounts Receivable — The Company sells crude oil and natural gas to various customers. Substantially all of the Company’s accounts receivable are due from purchasers of crude oil and natural gas or from reimbursable expenses billed to the other participants in oil and gas wells for which the Company serves as operator. Crude oil and natural gas sales are generally unsecured.

F-10

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As is common industry practice, collateral or other security is generally not required as a condition of sale; rather, the Company relies on credit approval, balance limitation, and monitoring procedures to control the credit approval on accounts receivable. The Company also grants credit to joint owners of oil and gas properties, which the Company operates through its subsidiaries. Such amounts are secured by the underlying ownership interests in the properties. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from all customers for collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to allowance. As of December 31, 2010 and 2009, the Company had an allowance of $0.6 million. During the year ended December 31, 2009, the Company recovered approximately $1.5 million of previously reserved bad debts. This recovery is reflected as a reduction to general and administrative expense in the accompanying consolidated statements of operations.

The Company records receivables at their net realizable value with specific write-offs of receivables that are deemed to be uncollectible. There were no significant write-offs of receivables for the years ended December 31, 2010, 2009, and 2008.

Prepaid and Other Current Assets:

Prepaid Expenses — The Company will occasionally prepay certain costs that may include insurance, maintenance agreements or rent. These costs are then amortized or expensed in the period the work or service is performed. As of December 31, 2010 and 2009, the Company had prepaid expense of $1.5 million and $1.4 million, respectively, primarily related to insurance.

Other — The Company is required to make advances to operators for costs incurred on aday-to-day basis to develop and operate ventures in which the Company has an ownership interest. These advances totaled approximately $0.2 million and $0.6 million as of December 31, 2010 and 2009, respectively. Such costs are capitalized to the full cost pool at the time the operator develops the properties. Other assets included a prepaid escrow of $0.8 million as of December 31, 2010.

Income Taxes — Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before being deductible in the income tax returns or when income items are recognized in the income tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset future taxable income. Deferred tax liabilities arise when income items are recognized in the financial statements before the income tax returns or when expenses are deducted in the tax return prior to recognition in the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the date when the change in the tax rate was enacted.

The Company routinely assesses the realizability of its deferred tax assets. If it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax asset is reduced by a valuation allowance.

As a result of the conversion to a corporation on August 1, 2009, pursuant to IRS Sec. 351, a tax free reorganization, the Company stepped into the “shoes” of the parent company as to the tax value of the net assets. Therefore, in effect, the income tax years of 2007, through the conversion date, through the current year remain open and subject to examination by Federal tax authoritiesand/or the tax authorities in Texas, Oklahoma, Mississippi, and Louisiana which are the Company’s principal operating jurisdictions. These audits can result

F-11

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

in adjustments of taxes due or adjustments of the net operating loss carry forwards that are available to offset future taxable income.

ASC 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities.

The Company’s policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in its Consolidated Statements of Operations. For the years ended December 31, 2010 and 2009, respectively, no interest expense or penalties related to unrecognized tax benefits associated with uncertain tax positions have been recognized in the provision for income taxes.

The total amount of unrecognized tax benefit if recognized that would affect the effective tax rate was zero.

The Parent files a consolidated tax return in Texas for the Texas Margin Tax, and is the legally responsible party for such taxes. Therefore, any income tax associated with the Texas Margin Tax is the responsibility of Parent, and has not been recognized in the Company’s financial statements. There are no income tax sharing agreements between Parent and the Company

See Note 12 — “Income Taxes” for further information.

Cash and Cash Equivalents — The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents are maintained with major financial institutions and such deposits may exceed the amount of federally backed insurance provided. While the Company regularly monitors the financial stability of such institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of such institutions.

Derivative Financial Instruments —The Company purchases derivative financial instruments, specifically, commodity swaps and collars and interest rate collars. Commodity swaps and collars are used to manage market price exposures associated with sales of oil and gas. Interest rate collars are used to manage interest rate risk arising from interest payments associated with floating rate debt. Such instruments are entered into for non-trading purposes.

The Company incorporates credit valuation adjustments to appropriately reflect both its nonperformance risk and the respective counterparty’s nonperformance risk in the fair value measurements. In adjusting the fair value of its derivative contracts for the effect of nonperformance risk, any impacts of netting and any applicable credit enhancements, such as collateral postings, thresholds, and guarantees, are considered.

Asset Retirement Obligation — The Company records a liability for the estimated fair value of its asset retirement obligations, primarily comprised of its plugging and abandonment liabilities, in the period in which it is incurred. The liability is accreted each period through charges to accretion expense. The asset retirement cost is included in the full cost pool. If the liability is settled for an amount other than the recorded amount, the difference is recognized in oil and gas properties in the consolidated balance sheet.

F-12

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Stock-Based Compensation — The Company utilizes ASC 718,Compensation — Stock Compensation, and estimates the fair value of stock-based compensation provided to employees. When and if issued, the Company estimates the fair value of stock-based compensation at the grant date, and recognizes compensation expense over the period that the employees provide the required service.

Recently Issued Accounting Pronouncements — In January 2010, the FASB issued Accounting Standards Update (ASU)2010-06, “Improving Disclosures About Fair Value Measurements” (ASU2010-06), which amends the Fair Value Measurements and Disclosures Topic of the ASC (ASC Topic 820). Among other provisions, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. This amendment requires new disclosures on the value of, and the reason for, transfers in and out of Levels 1 and 2 of the fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements. ASU2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques. ASU2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements which is effective for interim and annual reporting periods beginning after December 15, 2010. See Note 9. The Company adopted the applicable provisions of the rule effective January 1, 2010.

In December 31, 2008, the SEC issued“Modernization of Oil and Gas Reporting”(ASC2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section toRegulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of the final release is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by the release are now required to price proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. The final release is effective for financial statements with fiscal years ending on or after December 31, 2009. The Company adopted the provisions of the rule effective December 31, 2009.

In January 2010, the FASB issued ASUNo. 2010-03,Oil and Gas Reserve Estimations and Disclosures(ASUNo. 2010-03). This update aligns the current oil and gas reserve estimation and disclosure requirements of ASC 932,Extractive Activities— Oil and Gaswith the changes required by the SEC final rule discussed above. ASUNo. 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or gas, amends the definition of proved oil and gas reserves to require12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASUNo. 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Company adopted ASU2010-03 effective December 31, 2009.


4.	CONCENTRATION OF CREDIT RISK

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments, trade accounts receivable and derivative instruments.

The Company places its excess cash investments with high quality financial institutions. The Company’s receivables relate to customers in the oil and gas industry, and as such, the Company is directly affected by the

F-13

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

economy of the industry. The credit risk associated with the receivables is mitigated by monitoring customer creditworthiness.

For the years ended December 31, 2010, 2009, and 2008, the Company’s most significant customers by reference to oil and gas revenue were as follows:


	2010			2009			2008

Shell Trading (US) Company		19	%		16	%		17	%
Enterprise Crude Oil, LLC		11			8			—
Plains Marketing, L.P.		6			8			12
Smaller customers		64			68			71


5.	ASSET RETIREMENT OBLIGATION

In general, the amount of an asset retirement obligation (ARO) and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using a credit-adjusted risk-free rate.

Activity related to the ARO liability for the years ended December 31, 2010, 2009, and 2008, is as follows (in thousands):


Liability for asset retirement obligation — December 31, 2007	$	35,195
Liabilities settled and divested		(1,039	)
Liabilities incurred		1,669
Accretion expense		2,793

Liability for asset retirement obligation — December 31, 2008		38,618
Liabilities settled and divested		(1,345	)
Liabilities incurred		14
Revisions to cash flow estimates		(9,878	)
Accretion expense		2,712

Liability for asset retirement obligation — December 31, 2009		30,121
Liabilities settled and divested		(2,617	)
Liabilities incurred		3,359
Revisions to cash flow estimates		6,781
Accretion expense		2,627

Liability for asset retirement obligation — December 31, 2010	$	40,271

The liability comprises a current balance of $2.9 million and $5.7 million and a noncurrent balance of $37.4 million and $24.4 million as of December 31, 2010 and 2009, respectively.

Revisions to asset retirement obligations reflect changes in abandonment cost estimates, and reserve lives based on current information and considering the Company’s current plans.


6.	COMMON STOCK

The Company is authorized to issue up to 1,000,000 shares of Common Stock, par value $0.01 per share. On August 1, 2009, 280,400 shares of Common Stock were issued and outstanding and held by Milagro Holdings, LLC. Holders of Common Stock are entitled to, in the event of liquidation, to share ratably in the distribution of assets

F-14

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

remaining after payment of liabilities. Holders of Common Stock have no cumulative rights. The holders of a plurality of the outstanding shares of the Common Stock have the ability to elect all of the directors. Holders of Common Stock have no preemptive or other rights to subscribe for shares. Holders of Common Stock are entitled to such dividends as may be declared by the Board out of funds legally available therefore. The Company has never paid cash dividends on the Common Stock and does not anticipate paying any cash dividends in the foreseeable future.


7.	STOCK-BASED COMPENSATION

On November 30, 2007, the Company’s parent issued six Class C partnership units to Milagro Management Pool, LP with stated values of $0 per unit. No further units have been issued. The maximum number of units that can be allocated to the employees from the Management Pool is one million units. The Management Pool units vest upon the earlier of (i) change of control or (ii) ratably over five years from the date of the initial issuance of the units. If a Management Pool unit owner leaves the employment of the Company, all of such employee’s Management Pool units that are not vested shall be automatically forfeited and shall automatically be redeemed by the partnership for no consideration.

Stock-based compensation expense for share based compensation granted by the parent to employees of the subsidiary are reflected in the Company’s financial statements. Stock-based compensation is measured at the grant date based on the estimated fair value of the award and is recognized as an expense over the requisite employee service period, which management estimates to be approximately three years due to management’s expectations at issuance that there would be a change of control.

The fair value associated with the Management Pool units was estimated at the grant date (November 30, 2007) using the Black-Scholes model. The following assumptions were used in this model:


Expected holding period		3 years
Expected volatility		38%
Expected dividends		—
Risk free rate		3%

Since Milagro Holdings LLC is not a public company, there is no market value for any of its equity units. As such, it is not possible to determine the expected volatility of the share price. As a proxy for such volatility, the Company has used volatilities for a peer group of six public companies and calculated the average volatility.

As of December 31, 2010, no Management Pool Units had fully vested since the aforementioned conditions had not been met.

Compensation expense is recognized over the expected term of three years. The grant-date fair value of the Class C partnership units granted in 2007 was $5.9 million. At December 31, 2010, there was no unrecognized compensation expense.


8.	DERIVATIVE FINANCIAL INSTRUMENTS

The Company produces and sells crude oil, natural gas and natural gas liquids. As a result, its operating results can be significantly affected by fluctuations in commodity prices caused by changing market forces. The Company periodically seeks to reduce its exposure to price volatility of a portion of its production by acquiring swaps, options and other commodity derivative instruments. A combination of options, structured as a collar, is the Company’s preferred derivative instrument because there are no up-front costs and protection is provided against low prices. Such derivatives provide assurance that Milagro receives NYMEX prices no lower than the price floor and no higher than the price ceiling. For 2010, the Company had over 13 BCFE, roughly 68% of production, hedged through a series of gas collars, gas swaps and oil collars. As of December 31, 2010, the Company has approximately 10 BCFE of production hedged for 2011 which relates to approximately 60% of projected production.

F-15

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

According to its Senior Credit Facility, the Company is required to hedge a certain percentage of outstanding debt using interest rate derivatives. As of December 31, 2010, the Company had interest rate derivatives covering $150 million of outstanding indebtedness which is approximately roughly 81% of the total outstanding First Lien debt.

All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of December 31, 2010 and 2009 (in thousands):


			Fair Value
Description		Location in Balance Sheet	2010		2009

Asset derivatives:
Natural gas collars and swaps — current portion		Derivative assets — current	$	18,834	$	21,740
Noncurrent portion		Derivative assets		2,646		11,823
Oil collars — current portion		Derivative assets — current		—		638
Noncurrent portion		Derivative assets		—		418

			$	21,480	$	34,619

Liability derivatives:
Oil collars — current portion		Derivative liabilities	$	5,917	$	2,311
Noncurrent portion		Derivative liabilities — noncurrent		2,926		3,268
Interest rate collars:
Current portion		Derivative liabilities		3,510		7,993
Noncurrent portion		Derivative liabilities — noncurrent		—		1,655

			$	12,353	$	15,227
	��

The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations:


	Location in Statements
Description	of Operations	2010			2009			2008

Commodity contracts:
Realized gain (loss) on commodity contracts	Gain on commodity derivatives	$	39,355		$	44,127		$	(17,605	)
Unrealized (loss) gain on commodity contracts	Gain on commodity derivatives		(16,412	)		(18,521	)		67,864

Total net gain on commodity contracts			22,943			25,606			50,259

Interest rate swaps:
Realized loss on interest rate swaps	Net loss on interest rate derivatives		(8,275	)		(8,898	)		(1,625	)
Unrealized gain (loss) on interest rate swaps	Net loss on interest rate derivatives		6,148			3,173			(12,512	)

Total net loss on interest rate swaps			(2,127	)		(5,725	)		(14,137	)

Total net gain on derivative contracts		$	20,816		$	19,881		$	36,122

F-16

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2010, the Company had the following natural gas collar positions:


	Collars
			Floors				Ceilings
					Weighted-				Weighted-
	Volume in		Price/		Average		Price/		Average
Period	MMbtu’s		Price Range		Price		Price Range		Price

January 2011 — December 2011		760,164	$	7.00	$	7.00	$	10.60	$	10.60
January 2012 — December 2012		1,800,000		6.50		6.50		8.10		8.10

At December 31, 2010, the Company had the following natural gas swap positions:


	Swaps
			Weighted-
	Volume in	Price/	Average
Period	MMbtu’s	Price Range	Price

January 2011 — December 2011	5,136,265	$7.69 – $8.61	$7.91
January 2012 — December 2012	1,596,914	5.00	5.00

At December 31, 2010, the Company had the following crude oil collar positions:


	Collars
		Floors		Ceilings
			Weighted-		Weighted-
	Volume in	Price/	Average	Price/	Average
Period	Bbl’s	Price Range	Price	Price Range	Price

January 2011 — December 2011	625,193	$68.00 — $80.00	$73.45	$80.71 — $103.00	$87.72
January 2012 — December 2012	421,563	80.00	80.00	$86.00 — $93.24	90.73

At December 31, 2010, the Company had the following interest rate collar positions (notional amount in thousands):


Interest Rate Collars
	Floor	From and	To but	Notional
Cap Rate	Rate	Including	Excluding	Amount

4.90%	3.49%	01/01/11	09/05/11	$150,000

In March 2011, the Company liquidated natural gas hedges for the period April 2011 through October 2011, consisting of 2.9 BCFEs of production at $7.69, for $10.2 million in net proceeds.


9.	FAIR VALUES OF FINANCIAL INSTRUMENTS

The table below presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2010 and 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

In general, fair values determined by Level 1 inputs utilize quoted prices (unadjusted) in active markets the Company has the ability to access for identical assets or liabilities. Fair values determined by Level 2 inputs utilize inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar assets and liabilities in active markets and inputs other than quoted prices observable for the asset or liability, such as interest rates and yield curves observable at commonly quoted intervals. Level 3 inputs are unobservable inputs for the asset or liability and include situations where there is little, if any, market activity for the asset or liability. In instances in which the inputs used to measure fair value may fall into different levels of the fair value hierarchy, the level in the fair value hierarchy within which the fair value measurement in its entirety has been determined is based on the lowest level input significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair

F-17

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Disclosures concerning financial assets and liabilities measured at fair value are as follows:


	Assets and Liabilities Measured at
	Fair Value on a Recurring Basis
	Quoted Once		Significant
	in Active		Other			Significant
	Markets for		Observable			Unobservable
	Identical Assets		Inputs			Inputs		Total
	(Level 1)		(Level 2)			(Level 3)		Balance

December 31, 2010:
Commodity derivatives — gas	$	—	$	21,480		$	—	$	21,480
Commodity derivatives — oil		—		(8,843	)		—		(8,843	)
Interest rate collars		—		(3,510	)		—		(3,510	)
December 31, 2009:
Commodity derivatives — gas		—		33,563			—		33,563
Commodity derivatives — oil		—		(4,523	)		—		(4,523	)
Interest rate collars		—		(9,648	)		—		(9,648	)

To obtain fair values, observable market prices are used if available. In some instances, observable market prices are not readily available for certain financial instruments and fair value is determined using present value or other techniques appropriate for a particular financial instrument using observable inputs (such as forward commodity price and interest rate curves). These techniques involve some degree of judgment and as a result are not necessarily indicative of the amounts the Company would realize in a current market exchange. The use of different assumptions or estimation techniques may have a material effect on the estimated fair value amounts.

Derivative Financial Instruments — The majority of the inputs used to value the Company’s derivatives fall within Level 2 of the fair value hierarchy; however, the credit valuation adjustments associated with these derivatives utilize Level 3 inputs, such as estimates of current credit spreads to evaluate the likelihood of nonperformance. As of December 31, 2010 and 2009, the impact of the credit valuation adjustments on the overall valuation of the Company derivative positions is not significant to the overall valuation. As a result, derivative valuations in their entirety are classified in Level 2 of the fair value hierarchy.

Debt Instruments — All of the Company’s debt instruments, with the exception of the Series A Preferred Stock, accrue interest on a variable-rate basis. The Company estimates the carrying values in Note 10 to represent an approximation to its fair value based on the terms of similar instruments that would be available to the Company.

Cash and Cash Equivalents, Trade Receivables, and Payables — The fair value approximates carrying value given the short-term nature of these investments.


10.	DEBT

The Company’s debt as of December 31, 2010 and 2009, comprises the following amounts (in thousands):


	2010		2009

Revolver — current	$	184,580	$	—
Revolver — long term		—		231,628
Second lien — current		60,000		—
Second lien — long term		92,390		259,922
Series A preferred stock — long term		223,630		—

Total debt	$	560,600	$	491,550

F-18

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Scheduled maturities or mandatory redemption dates by fiscal year are as follows (amounts in thousands):


Years Ending December 31

2011	$	244,580
2012		92,390
2013		—
2014		—
2015		—
2016		223,630

	$	560,600

First Lien Credit — As of December 31, 2010, the First Lien Credit Agreement, the “Senior Credit Agreement”, among Milagro Exploration, LLC and Milagro Producing, LLC, each an indirect wholly-owned subsidiary of the Company (collectively, the “Borrowers”), Milagro Oil & Gas, Inc., each of the lenders from time to time party thereto the “Lenders” and Wells Fargo Bank, N.A. as administrative agent for the Lenders, provided for a borrowing base of $179 million. The borrowing base is based on the estimated value of the Borrowers’s oil and natural gas properties and is redetermined on a semi-annual basis (with the Company and the Lenders each having the right to one annual interim unscheduled redetermination) and adjusted based on the Company’s oil and natural gas properties, reserves, other indebtedness and other relevant factors. At the time of the latest redetermination, the Company had approximately $191 million outstanding under the First Lien Agreement thereby creating a $12 million borrowing base deficiency. It was agreed that the deficiency would be reduced by six monthly payments of $2 million beginning December 1, 2010.

Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the London InterBank Offered Rate (LIBOR) of between 3.00% and 3.75% for Eurodollar loans or at specified margins over the Alternate Base Rate (ABR) of between 2.00% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. As of December 31, 2010, the interest rate was 4.04%. Borrowings under the Senior Credit Agreement are secured by all of the Company’s oil and gas properties. The Lenders’ commitments to extend credit will expire, and amounts drawn under the Senior Credit Agreement will mature, in November 2011.

The Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused availability of the borrowing base under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0, minimum coverage of interest expenses (as defined) of not less than 2.5 to 1.0 and maximum debt balances as compared to earnings before interest, taxes, depreciation, depletion, and amortization (EBITDA) of not greater than 3.5 to 1.0. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt and liens, changes of control and asset sales.

In January 2010, the Senior Credit Agreement provided for a borrowing base of $179 million through May 1, 2011. The borrowing base will be redetermined and adjusted based on the Company’s oil and natural gas properties, reserves, other indebtedness and other relevant factors at that time. The outstanding principal balance under the Senior Credit Agreement is $184.6 million as of December 31, 2010. Amounts outstanding under the Senior Credit Agreement continue to bear interest at specified margins over the LIBOR of between 3.00% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 2.00% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. The average interest rate for the Senior Credit Agreement was 4.02% on LIBOR based loans and 6.00% on base rate loans at December 31, 2010. The Lenders’ commitments to extend credit expire, and amounts borrowed under the facility mature in November 2011. There were no changes made to the covenants required under the Senior Credit Agreement as disclosed above.

F-19

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During 2010, the Company notified the Lenders that the Borrowers were in violation or default of the minimum working capital level covenant in the Senior Credit Agreement, but were in compliance with all other covenants. The Borrowers obtained a waiver from the Lenders whereas the Lenders agreed not to exercise their rights under the Senior Credit Agreement as a result of such violations.

Second Lien — As of December 31, 2010, debt outstanding under the Second Lien Credit Agreement dated November 30, 2007, was $152.4 million, among Milagro Exploration, LLC and Milagro Producing, LLC, each an indirect wholly-owned subsidiary of the Company (collectively, the “Borrowers”), Milagro Oil & Gas, Inc., each of the lenders from time to time party thereto the “Lenders” and Wells Fargo Bank, N.A. as administrative agent for the Lenders. A $60.0 million tranche of this indebtedness, the Delayed Draw and New Term Loans, matures in November 2011. The remaining $92.4 million of Second Lien debt matures in November 2012. Interest on the Second Lien debt accrues at a rate of LIBOR plus 7.25% where LIBOR is deemed to have a floor rate of 3.00% per annum and is payable quarterly in arrears. An additional 2.0% is added to the applicable margin when the Company is required to pay interest at the default rate. As of December 31, 2010, the interest rate was 10.25%. The Second Lien Credit Agreement is secured behind the First Lien Credit Agreement, by all of the Company’s oil and gas properties.

The Second Lien Credit Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused availability of the borrowing base under the Senior Credit Agreement to current liabilities) of not less than 0.85 to 1.0, minimum coverage of interest expenses of not less than 2.125 to 1.0 and maximum debt balances as compared to EBITDA of not greater than 4.025 to 1.0. There is also a minimum coverage of PV10 value to total debt of not less than 1.5 to 1.0 which is required to be calculated as of the borrowing base redetermination dates under the Senior Credit Agreement.

During 2010, the Company was in compliance with all covenants of the Second Lien Credit Agreement. The terms of the Second Lien Credit Agreement were amended on April 28, 2008, such that the borrowing base increased to $260 million from $200 million in the original agreement. The impact of a change in terms was such that a loss on extinguishment of $15.1 million was recorded.

The Company is authorized to issue up to 3,000,000 shares of Preferred Stock at a par value of $0.01 per share. On January 13, 2010 the Company, entered into agreements to exchange $194.7 million of the Second Lien Debt and accrued interest for $205.5 million of Series A Mandatorily Redeemable Preferred Equity consisting of 2,700,000 of preferred shares issued at $76.12 per share mandatorily redeemable in 2016. The preferred shareholders receive a 12% dividend each year paid in cash or in-kind, which is determined solely at the option of the Company. There was an increase of approximately $28.9 million of Series A from issuance to December 31, 2010, which was primarily related to the accrual of the in-kind dividend that was recorded as interest expense. There were no dividends paid during 2010 and the Company is not expecting to pay dividends in 2011. The recapitalization transaction was accounted for under theASC 470-60,Troubled Debt Restructuring by Debtors, and is considered to be a modification of terms of debt. Any gain or loss on the exchange was deferred given the related party aspects of the transaction. These preferred shares are classified as a liability in the financial statements as they are mandatorily redeemable for cash.

In conjunction with the recapitalization, the Borrowers and the Second Lien debt holders entered into a Second Lien Wells Fargo Energy Capital (WFEC)payable-in-kind (PIK) Facility Agreement in which each remaining Second Lien Credit Agreement debt holder agreed to continue their existing loans (Existing Loans) consisting of principal and accrued interest totaling $62.4 million as of December 31, 2010. Amounts outstanding under the Amended and Restated Second Lien Credit Agreement bear interest at an initially specified margin of 4.75% over the LIBOR for Eurodollar loans or over the ABR for ABR loans provided that the minimum LIBOR is 3.0%. The average interest rate for the Second Lien Credit Agreement was 10.25% at December 31, 2010. However, interest expense on these loans is PIK and not payable in cash. Since the maturity date was not impacted by the recapitalization, amounts outstanding under the Second Lien Credit Agreement mature in November 2012.

F-20

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As part of the recapitalization, the Borrowers also entered into a Term Loan Agreement between the Borrowers, each of the lenders from time to time party thereto (the Term Loan Lenders) and Guggenheim Corporate Funding, LLC, as administrative agent for the Term Loan Lenders. The Term Loan Agreement provides for three types of loans which are the Term Loans (new loans advanced in full on the closing date), the Delayed Draw Loans (term loans available to be drawn in the future based on certain terms and conditions), and the Converted Loans (existing loans converted from the Second Lien Credit Agreement). The Converted Loans total $30.0 million, initially accrued cash interest at a specified margin of 4.75% over the LIBOR for Eurodollar loans provided that the minimum LIBOR is 3.0% and mature on November 30, 2012. The average interest rate for the Second Lien Credit Agreement was 10.25% at December 31, 2010. The Term Loans provided $25.0 million of additional credit to the Company and proceeds from these Loans were used to repay outstanding indebtedness under the Senior Credit Agreement and for transaction fees and expenses. The Term Loans accrue cash interest at a specified margin of 4.75% over LIBOR for Eurodollar loans provided that the minimum LIBOR is 3.0% and mature on November 30, 2011. The average interest rate for the Second Lien Credit Agreement was 10.25% at December 31, 2010. The Delayed Draw Loan provided $35.0 million of additional credit to the Company. Proceeds from these loans were used in acquisitions made by the Company in 2010. See Note 2. Delayed Draw Loans accrue interest at the same rate as the Term Loans and mature on November 30, 2011. The average interest rate for the Second Lien Credit Agreement was 10.25% at December 31, 2010.

In June 2010, the interest margin on all Second Lien loans increased from 4.75% to 7.25%. The Second Lien WFEC PIK Facility, Converted Loans, Term Loans and the Delayed Draw Loans all contain customary financial and other covenants. There were no changes made to the covenants required under the Senior Credit Agreement as disclosed above.

PIK Note — On November 30, 2007, the Company issued an unsecured five-year seller-financed PIK note payable to Petrohawk for $125 million payable in full at maturity. Interest accrued monthly at 12%, but was not paid in cash. The PIK Note provided a $25 million principal discount if the note was redeemed within the first 12 months of its term. In addition, any interest incurred would also be waived if the note was redeemed within five months of issuance. In April 2008, the PIK note was repaid in full for $100 million, and all interest accrued was forgiven. The forgiveness of interest of $5.1 million was recorded in operations during 2008, and the gain on debt forgiveness was recorded as an adjustment to the full cost pool as an adjustment to the overall purchase price of the Petrohawk assets.

The Company capitalizes certain direct costs associated with the issuance of long-term debt (see Note 14).

For the years ended December 31, 2010, 2009 and 2008, the Company capitalized interest of $2.4 million, $4.6 million and $6.3 million, respectively.


11.	LIQUIDITY AND GOING CONCERN

At December 31, 2010, current liabilities exceeded current assets by $238.5 million due primarily to the classification of the Revolving Senior Credit Facility of $184.6 million, Term Loans of $25.0 million and Delayed Draw Loan of $35.0 million as current debt. All of these loans currently mature in November 2011. The Company is currently in the process of renegotiating a new Senior Credit Agreement and a debt offering.

The accompanying financial statements have been prepared assuming the Company will continue as a going concern; however, due to the deficiency in short-term and long-term liquidity, the Company’s ability to continue as a going concern is dependent on its success in renegotiating a new Senior Credit Agreement and refinancing or extending the maturity dates of the debt that is due in 2011. Waivers were obtained for violations of the covenants of our Senior Credit Agreement and Second Lien Facilities as of December 31, 2010 whereas the Lenders agreed not to exercise their rights under the credit agreement as a result of such violations.

F-21

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


12.	INCOME TAXES

We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We record net deferred tax assets to the extent we believe these assets will more likely than not be realized. In making such determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax planning strategies and recent financial operations. In the event we were to determine that we would be able to realize our deferred income tax assets in the future in excess of their net recorded amount, we would make an adjustment to the valuation allowance, which would reduce the provision for income taxes.

In July 2006, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation (“FIN”) 48, “Accounting for Uncertainty in Income Taxes,” (codified primarily in FASB ASC Topic 740, Income Taxes) which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with Statement of Financial Accounting Standards (“SFAS”) 109, “Accounting for Income Taxes” (codified primarily in FASB ASC Topic 740, Income Taxes). FIN 48 provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted FIN 48 effective August 1, 2009, the first day of converting from a partnership to a taxable corporation. We evaluated our tax positions as of December 31, 2010, the most recent reporting date, and have concluded that the positions meet the more-likely-than-not recognition threshold and no expense or benefit is recognized from uncertain tax positions.

The income tax expense (benefit) in the Company’s consolidated statements of operations consisted of the following:


	2010		2009			2008

Current Income Tax
Expense (Benefit)
Federal	$	—	$	—		$	—
State	$	—	$	—		$	—
Deferred Income Tax
Expense (Benefit)
Federal	$	54,854	$	(54,854	)	$	—
State		2,568		(2,568	)		—

	$	57,422	$	(57,422	)	$	—

F-22

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The differences between income taxes computed using the statutory federal income tax rate and that shown in the statement of operations are summarized as follows:


	For Years Ended December 31,
	2010			2009			2008
	Estimated Tax			Estimated Tax			Estimated Tax
Income Items	(Benefit)/Expense			(Benefit)/Expense			(Benefit)/Expense

Income tax expense (benefit) at federal statutory rate	$	(4,608	)	$	(23,120	)	$	—
Adjustments:
Effect of flow-through entity		—			3,571			—
Accrued Dividend on Series A Preferred Shares		8,324			—			—
State Income tax net of federal tax		1,807			724			—
Income Taxes Related to Prior Periods		(6,090	)		—			—
Non-Deductible/Non-Taxable Items and Other		(276	)		6			—
Establish deferred tax asset at conversion		—			(54,843	)		—
Valuation Allowance		58,265			16,240			—

Total Tax Expense (Benefit)	$	57,422		$	(57,422	)	$	—

Significant components of the Company’s deferred tax assets as of December 31, 2010 and 2009 are as follows:


	2010						2009
	FED			State			FED			State

Current Deferred Tax Assets
Accrued Interest Payable	$	217		$	4		$	6,783		$	126
Accrued Liabilities & Other		248			5			77			2
Less: Valuation Allowance		(465	)		(9	)		(2,703	)		(50	)

Total Current Deferred Tax Asset	$	—		$	—		$	4,157		$	78

Non-Current Deferred Tax Assets
Oil & Gas Properties Basis Differences	$	43,206		$	853		$	53,789		$	2,849
Deferred Financing Costs		2,130			42			3,764			70
Abandonment Liability		12,626			249			8,560			159
Derivative Financial Instruments		98			2			(2,561	)		44
Net Operating Loss Carryforward		14,537			287			—			—
Less: Valuation Allowance		(72,597	)		(1,433	)		(12,855	)		(632	)

Total Non-Current Deferred Tax Asset	$	—		$	—		$	50,697		$	2,490

The Company has net operating loss (“NOL”) carryforwards of $41.5 million for tax purposes which will begin to expire in 2030.

The valuation allowance for deferred tax assets increased by $58.3 million and $16.2 million for the years ended December 31, 2010 and 2009 respectively. In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As the Company has incurred net operating losses in 2010 and prior years, relevant

F-23

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. Therefore, we have reduced the carrying value of our net deferred tax asset to zero. The valuation allowance has no impact on our NOL position for tax purposes, and if we generate taxable income in future periods, we will be able to use the NOL’s to offset taxes due at that time. The Company will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

The amount of unrecognized tax benefits did not materially change as of December 31, 2010. The amount of unrecognized tax benefits may change in the next twelve months; however we do not expect the change to have a significant impact on our financial position.

The Company files income tax returns in the United States and in various state jurisdictions. The Company is subject to U.S. federal and state income tax examinations by tax authorities for tax periods 2007 and forward.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statement of Operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.


13.	COMMITMENTS AND CONTINGENCIES

Commitments — The Company leases corporate office space in Houston, Texas. In 2009, the Company entered into a contract with UBS for acquisition services to be provided in 2010 for guaranteed fees of $1.0 million, this contract has been extended to 2011. Rental expense was $2.1 million, $2.4 million, and $2.1 million, for the years ended December 31, 2010, 2009, and 2008, respectively.

The following table summarizes the Company’s contractual obligations and commitments at December 31, 2010, by fiscal year (amounts in thousands):


	2011		2012		2013		2014		2015		Thereafter		Total

UBS(1)	$	1,000	$	—	$	—	$	—	$	—	$	—	$	1,000
Office lease		1,765		1,798		1,884		1,913		1,913		3,188		12,461


(1)		UBS commitments are included in accounts payable and accrued liabilities.

Contingencies:

There are currently various suits and claims pending against the Company that have arisen in the ordinary course of the Company’s business, including contract disputes, personal injury and property damage claims and title disputes. Management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material effect on the Company’s consolidated financial position, results of operations or cash flow. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.


14.	OTHER ASSETS

The Company capitalizes certain direct costs associated with the issuance of long-term debt, which is then amortized over the lives of the respective debt using the straight-line method, which approximates the interest method. The Company was carrying debt issuance costs, net of amortization, of $1.8 million and $3.4 million as of December 31, 2010 and 2009, respectively.


15.	EMPLOYEE BENEFIT PLANS

The Company operates a discretionary bonus plan and a 401(k) savings plan via a third-party service provider.

F-24

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Upon hire, an individual is immediately eligible to participate in the 401(k) plan. The Company, under its sole discretion, may contribute an employer-matching contribution equal to a percentage not to exceed 3% of each eligible participant’s contributions. The Company contributed $283,000, $356,000, and $621,000, in the years ended December 31, 2010, 2009, and 2008, respectively.

On February 1, 2010, the Company reinstated its cash contributions to the plan, that was suspended on July 1, 2009.


16.	RELATED PARTY TRANSACTIONS

As of December 31, 2010 and 2009, the Company had a receivable of $2.2 million for monitoring fees on behalf of Milagro Holdings, LLC, to Milagro Holdings, LLC’s owners, ACON Milagro Investors, LLC, Milagro Investors, LLC and West Coast Milagro Partners, LLC, in 2008 and 2007, which are recognized as an advance to affiliates in the accompanying balance sheet.


17.	SEGMENT INFORMATION

The FASB issued authoritative guidance establishing standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses. Separate financial information is available and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance. The Company measures financial performance as a single enterprise, allocating capital resources on a project by project basis across its entire asset base to maximize profitability. The Company utilizes a company-wide management team that administers all enterprise operations encompassing the exploration, development and production of natural gas and oil. Since the Company follows the full cost of method of accounting and all its oil and gas properties and operations are located in the United States, the Company has determined that it has one reporting unit. In as much as the Company, is one enterprise, it does not maintain comprehensive financial statement information by area but does track basic operational data by area.


18.	GUARANTOR AND NON-GUARANTOR

The Company is not required to disclose condensed consolidating financial information as the parent company has no independent assets or operations and owns 100% of each of the Borrowers, Milagro Resources, LLC and Milagro Mid-Continent, LLC. The subsidiary guarantees are full and unconditional guarantees of the Company’s outstanding debt on a joint and several basis. There are no non-guarantor subsidiaries. These subsidiaries are included in the consolidated financial statements.


19.	SUBSEQUENT EVENTS

The Company evaluated subsequent events through March 31, 2011, the original issuance date, and October 26, 2011.

On May 11, 2011, the Company entered into a new first lien credit agreement and sold $250 million of bonds, with the proceeds being used to pay off the existing first and second lien debt. Also on May 11, 2011, the Company amended the terms of the Series A. The amendment made the Series A a perpetual instrument and removed the mandatory redemption. Therefore, as a result of the amendment, the Series A was reclassified from long-term debt to mezzanine equity.

F-25

MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

				��
	June 30,			December 31,
	2011			2010
	(In thousands,
	except share data)
	(Unaudited)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,941		$	17,734
Accounts receivable:
Oil and gas sales		15,872			18,480
Joint interest billings and other — net of allowance for doubtful accounts of $527 and $615 in 2011 and 2010, respectively (Note 2)		2,236			2,530
Derivative assets		9,097			18,834
Prepaid expenses and other		4,514			2,518

Total current assets		35,660			60,096
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties — full cost method:
Proved properties		1,207,066			1,181,948
Unproved properties		16,839			13,156
Less accumulated depreciation, depletion and amortization		(768,445	)		(743,637	)

Net oil and gas properties		455,460			451,467
Other property and equipment, net of accumulated depreciation of $5,760 and $5,436 in 2011 and 2010, respectively		1,474			1,718

Net property, plant and equipment		456,934			453,185
DERIVATIVE ASSETS		1,558			2,646

OTHER ASSETS:
Deferred financing cost		8,859			1,813
Advance to affiliate		2,231			2,248
Other		2,593			2,210

Total other assets		13,683			6,271

TOTAL	$	507,835		$	522,198

LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	29,997		$	39,672
Current portion of debt		—			244,580
Accrued interest payable		4,023			1,959
Derivative liabilities		6,280			9,427
Asset retirement obligation		2,921			2,921

Total current liabilities		43,221			298,559
NONCURRENT LIABILITIES:
Long-term debt		339,186			92,390
Series A preferred stock (Note 7)		—			223,630
Asset retirement obligation		35,770			37,350
Derivative liabilities		7,732			2,926
Other		3,177			3,173

Total noncurrent liabilities		385,865			359,469
Total liabilities		429,086			658,028

MEZZANINE EQUITY
Redeemable series A preferred stock (Note 9)		233,989			—

COMMITMENT AND CONTINGENCIES (Note 12)
DEFICIT:
Common shares, (par value, $.01 per share; shares authorized: 1,000,000; shares issued and outstanding: 280,400 as of June 30, 2011 and December 31, 2010, respectively		3			3
Additional paid-in capital		(66,813	)		(66,813	)
Accumulated deficit		(88,430	)		(69,020	)

Total stockholder’s deficit		(155,240	)		(135,830	)
TOTAL	$	507,835		$	522,198

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

F-26

MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Six Months Ended
	June 30,
	2011			2010
	(In thousands, except per share data)
	(Unaudited)

REVENUES:
Oil and natural gas revenues	$	69,465		$	68,670
Gain (Loss) on commodity derivatives, net		(3,564	)		22,018

Total revenues		65,901			90,688

COSTS AND EXPENSES:
Gathering and transportation		697			661
Lease operating		18,591			16,400
Environmental remediation		1,984			—
Taxes other than income		4,285			5,581
Depreciation, depletion and amortization		25,131			26,292
General and administrative		7,122			8,689
Accretion		1,573			1,237

Total costs and expenses		59,383			58,860

Operating income		6,518			31,828

OTHER EXPENSE (INCOME):
Net loss on interest rate derivatives		914			1,259
Other income		(70	)		(611	)
Interest and related expenses, net of amounts capitalized		24,057			24,081
Loss on extinguishment of debt		1,027			—

Total other expense		25,928			24,729

INCOME (LOSS) BEFORE INCOME TAX		(19,410	)		7,099

INCOME TAX EXPENSE		—			57,422

NET INCOME (LOSS)		(19,410	)		(50,323	)

Preferred dividends		3,844			—

NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$	(23,254	)	$	(50,323	)

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

F-27

MILAGRO OIL & GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN DEFICIT


					Additional						Total
	Common Stock				Paid in			Accumulated			Stockholders’
	Shares		Par Value		Capital			Deficit			Deficit
	(In thousands, except for share amounts)

BALANCE — December 31, 2010		280,400	$	3	$	(66,813	)	$	(69,020	)	$	(135,830	)
Net loss		—		—		—			(19,410	)		(19,410	)

BALANCE — June 30, 2011		280,400	$	3	$	(66,813	)	$	(88,430	)	$	(155,240	)

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

F-28

MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
	2011			2010
	(In thousands)
	(Unaudited)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income/ (loss)	$	(19,410	)	$	(50,323	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization		25,131			26,292
Amortization of deferred financing costs		921			880
Loss on extinguishment of debt		1,027			—
Accretion of asset retirement obligations		1,573			1,237
Deferred income taxes		—			56,812
PIK note interest		10,015			13,446
Recapitalization interest		568			567
Original interest discount on notes		231			—
Unrealized (gain)/loss on commodity derivatives		14,297			(4,574	)
Unrealized (gain)/loss on interest rate derivatives		(1,812	)		(3,416	)
Stock based compensation		—			894
Changes in assets and liabilities — net of acquisitions:
Accounts receivable and accrued revenue		2,902			255
Prepaid expenses and other		(1,985	)		(4,353	)
Accounts payable and accrued liabilities		(6,762	)		2,867

Net cash provided by operating activities		26,696			40,584
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and gas properties		(2,737	)		(22,248	)
Additions to oil and gas properties		(30,300	)		(10,569	)
Additions of other long-term assets		(80	)		69
Net sales of oil and gas properties		37			127

Net cash used in investing activities		(33,080	)		(32,621	)
CASH FLOWS FROM FINANCING ACTITVITIES:
Proceeds from borrowings		351,955			49,000
Credit facility payments		(350,193	)		(28,749	)
Deferred financing costs paid		(9,171	)		—
Capital contributions (distributions)		—			(6	)

Net cash (used in) provided by financing activities		(7,409	)		20,245

NET DECREASE IN CASH AND CASH EQUIVALENTS	$	(13,793	)	$	28,208

CASH AND CASH EQUIVALENTS — Beginning of period	$	17,734		$	10,531

CASH AND CASH EQUIVALENTS — End of period	$	3,941		$	38,739

INCOME TAX PAID, Net of refunds	$	—		$	—

INTEREST PAID — Net of interest capitalized of $419 and $1,038 in 2011 and 2010, respectively	$	10,178		$	5,036

SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Recapitalization:
Issuance of series A preferred stock	$	—		$	198,712

Interest paid in kind — series A preferred stock	$	9,800		$	11,351

Forgiveness of forbearance fee	$	—		$	4,000

Settlement of second lien debt	$	—		$	(194,712	)

Interest paid in kind — second lien	$	214		$	2,095

Interest and fees converted to debt	$	—		$	21,960

Accrued capital and seismic costs included in proved properties	$	4,556		$	1,104

Asset retirement obligations incurred	$	242		$	—

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

F-29

MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


1.	ORGANIZATION

Milagro Oil & Gas, Inc. (the “Company” or “Milagro”) is an independent oil and gas exploration and production company. The Company was organized as a Delaware limited liability company on November 30, 2007. The Company owns 100% of Milagro Exploration, LLC, Milagro Resources, LLC, Milagro Producing, LLC and Milagro Mid-Continent, LLC and is a subsidiary of Milagro Holdings, LLC (“Parent”). Each of these subsidiaries is included in the consolidated financial statements. All intercompany accounts and transactions are eliminated in consolidation.

The consolidated financial statements of the Company, included herein, have been prepared by management without audit, and they reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods presented. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). However, management believes that the disclosures included either on the face of the financial statements or in these notes are sufficient to make the interim information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto for the year ended December 31, 2010.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and six months ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year.

Restatement

Subsequent to the issuance of the June 30, 2011 financials, the Company identified an error in the supplemental disclosure of cash paid for interest related to the period ending June 30, 2010. The correction of this error had no effect on any of the categories presented in the statement of cash flows. This error had no impact on the balance sheet or statement of operations as previously reported and was determined not to be material to the 2010 consolidated financial statements. The amounts as previously reported and as restated are as follows:

Previously

Reported

Adjustment

Restated

Supplemental Cash Flow Disclosure

Interest paid — net of interest capitalized of $1,038

25,976

(20,940

)

5,036


2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates — The preparation of the Company’s consolidated financial statements in conformity with U.S. GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. These estimates include oil and natural gas reserve quantities that form the basis for (i) the allocation of purchase price to proved and unproved properties, (ii) calculation of amortization of oil and natural gas properties and (iii) the full cost ceiling test. Management emphasizes that reserve estimates are inherently imprecise

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Other significant estimates include (a) estimated quantities and prices of oil and gas sold, but not collected, as of period-end; (b) accruals of capital and operating costs; (c) current plug and abandonment costs, settlement date, inflation rate and credit-adjusted risk-free rate used in estimating asset retirement obligations; (d) those assumptions and calculation techniques used in estimating the fair value of derivative financial instruments, as considered in Note 6. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.

Oil and Gas Properties:

Full Cost Accounting — The Company utilizes the full cost method to account for its investment in oil and gas properties. Under the full cost method, which is governed byRule 4-10 ofRegulation S-X of the SEC, all costs of acquisition, exploration, exploitation, and development of oil and gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible exploration and development costs and direct internal costs) are capitalized as the cost of oil and gas properties when incurred. Direct internal costs that are capitalized are primarily the salary and benefits of geologists, landmen, and engineers directly involved in acquisition, exploration and development activities. For the six months ended June 30, 2011 and 2010, direct internal costs capitalized were approximately $2.4 million and $1.8 million, respectively.

Depreciation, Depletion, and Amortization — The cost of oil and gas properties; the estimated future expenditures to develop proved reserves; and estimated future abandonment, site remediation and dismantlement costs are depleted and charged to operations using theunit-of-production method based on the ratio of current production to proved oil and gas reserves as estimated by independent engineering consultants. The Company’s depletion rate for the six months ended June 30, 2011 and 2010 was $16.65 and $15.12 per Mboe, respectively.

Impairment — Full cost ceiling impairment is calculated as of each reporting period, whereby net capitalized costs related to proved and unproved properties less related deferred income taxes may not exceed a ceiling limitation. The ceiling limitation is the amount equal to the present value discounted at 10% of estimated future net revenues from estimated proved reserves plus the lower of cost or fair value of unproved properties less estimated future production and development costs and net of related income tax effect. As of December 31, 2009, the full cost ceiling limitation is calculated using12-month simple average price of oil and natural gas as of the first day of each month for the period ending as of the balance sheet date and is adjusted for “basis” or location differentials. Price and operating costs are held constant over the life of the reserves. If net capitalized costs related to proved properties less related deferred income taxes exceed the ceiling limitation, the excess is impaired and a permanent write-down is recorded in the consolidated statements of operations. As of June 30, 2011 and 2010, no ceiling impairment was recorded.

Unproved property costs fall into four broad categories:


	•	Projects that are in the last one to two years of seismic evaluation

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	•	Leasehold costs for projects not yet evaluated

	•	Drilling and completion costs for projects in progress at period end that have not resulted in the recognition of reserves for that period

	•	Interest costs related to financing such activities

Property, Plant and Equipment Other Than Oil and Natural Gas Properties — Other operating property and equipment are stated at cost. The provision for depreciation is calculated using the straight-line method over the estimated useful lives of the respective assets. The cost of normal maintenance and repairs is charged to operating expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of properties sold or otherwise disposed of and the related accumulated depreciation or amortization is removed from the accounts, and any gains or losses are reflected in current operations.

Revenue Recognition and Gas Imbalances — Revenues are recognized and accrued as production occurs and physical possession and title pass to the customer. The Company uses the sales method of accounting for revenue. Under this method, oil and gas revenues are recorded for the amount of oil and natural gas production sold to purchasers. Gas imbalances are created when the sales amount is not equal to the Company’s entitled share of production. The Company’s entitled share is calculated as gross production from the property multiplied by the Company’s net revenue interest in the property. No provision is made for an imbalance unless the oil and gas reserves attributable to a property have depleted to the point that there are insufficient reserves to satisfy existing imbalance positions. At that point, a payable or a receivable, as appropriate, is recorded equal to the net value of the imbalance. The Company had recorded a liability of approximately $0.7 million as of both June 30, 2011 and December 31, 2010.

As is common industry practice, collateral or other security is generally not required as a condition of sale; rather, the Company relies on credit approval, balance limitation, and monitoring procedures to control the credit approval on accounts receivable. The Company also grants credit to joint owners of oil and gas properties, which the Company operates through its subsidiaries. Such amounts are secured by the underlying ownership interests in the properties. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from all customers for collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to allowance. As of June 30, 2011 and December 31, 2010, the Company had an allowance of approximately $0.5 million and $0.6 million, respectively. There were no significant write-offs of receivables for the six months ended June 30, 2011 or the year ended December 31, 2010 and no significant bad debt expense recorded for the same periods.

Prepaid and Other Current Assets:

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

is performed. As of June 30, 2011 and December 31, 2010, the Company had prepaid expense of approximately $3.3 million and $1.5 million, respectively, primarily related to insurance.

Other — The Company is required to make advances to operators for costs incurred on aday-to-day basis to develop and operate ventures in which the Company has an ownership interest. These advances totaled approximately $0.3 million and $0.2 million as of June 30, 2011 and December 31, 2010, respectively. Such costs are capitalized to the full cost pool at the time the operator develops the properties. Other assets included a prepaid escrow of approximately $0.8 million as of both June 30, 2011 and December 31, 2010.

Derivative Financial Instruments — The Company purchases derivative financial instruments, specifically, commodity swaps and collars and interest rate collars. Commodity swaps and collars are used to manage market price exposures associated with sales of oil and natural gas. Interest rate collars are used to manage interest rate risk arising from interest payments associated with floating rate debt. Such instruments are entered into for non-trading purposes.

Stock-Based Compensation — The Company estimates the fair value of stock-based compensation provided to employees. When and if issued, the Company estimates the fair value of stock-based compensation at the grant date, and recognizes compensation expense over the period that the employees provide the required service.

Subsequent Events — The Company evaluated subsequent events through October 26, 2011, which is the date the financial statements were issued and no significant events had occurred.

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements. ASU2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques. ASU2010-06 became effective for interim and annual reporting periods beginning after December 15, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements which became effective for interim and annual reporting periods beginning after December 15, 2010. See Note 6. The Company adopted the applicable provisions of the rule effective January 1, 2010 and January 1, 2011, respectively.


3.	ASSET RETIREMENT OBLIGATION

In general, the amount of an asset retirement obligation (“ARO”) and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using a credit-adjusted risk-free rate.

Activity related to the ARO liability for the six months ended June 30, 2011 is as follows (in thousands):


Liability for asset retirement obligation — December 31, 2010	$	40,271
Revisions		(2,302	)
Additions		242
Settlements		(1,093	)
Accretion expense		1,573

Liability for asset retirement obligation — June 30, 2011	$	38,691

The liability comprises a current balance of approximately $2.9 million and a noncurrent balance of approximately $35.8 million as of June 30, 2011.


4.	STOCK-BASED COMPENSATION

On November 30, 2007, Parent issued six Class C units to Milagro Management Pool, LP (“Management Pool”) with stated values of $0 per unit. No further Class C units have been issued. Management Pool in turns issues limited partnership interests to the Company’s management and other employees. The maximum number of units that can be allocated to the employees from the Management Pool is one million units. The Management Pool units vest upon the earlier of (i) change of control or (ii) ratably over five years from the date of the initial issuance of the units. If a Management Pool unit owner leaves the employment of the Company, all of such employee’s Management Pool units that are not vested shall be automatically forfeited and shall automatically be redeemed by Management Pool for no consideration.

The fair value associated with the Management Pool units was estimated at the grant date (November 30, 2007) using the Black-Scholes model. The following assumptions were used in this model:


Expected holding period		3 years
Expected volatility		38%
Expected dividends		—
Risk free rate		3%

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Since Parent is not a public company, there is no market value for any of its equity units. As such, it is not possible to determine the expected volatility of the share price. As a proxy for such volatility, the Company has used volatilities for a peer group of six public companies and calculated the average volatility.

Compensation expense was recognized over the expected term of three years. The grant-date fair value of the Class C units granted in 2007 was $5.9 million. At June 30, 2011, there was no unrecognized compensation expense.


5.	DERIVATIVE FINANCIAL INSTRUMENTS

The Company produces and sells crude oil, natural gas and natural gas liquids. As a result, its operating results can be significantly affected by fluctuations in commodity prices caused by changing market forces. The Company periodically seeks to reduce its exposure to price volatility for a portion of its production by entering into swaps, options and other commodity derivative instruments. A combination of options, structured as a collar, is the Company’s preferred derivative instrument because there are no up-front costs and the instruments set a floor price for a portion of the Company’s hydrocarbon production. Such derivatives provide assurance that the Company receives NYMEX prices no lower than the price floor and no higher than the price ceiling. For the six months ended June 30, 2011, the Company had hedges in place for 3.4 MMCFe, approximately 38% of production, in the form of natural gas, crude oil and NGL collars and swaps. In March 2011, the Company liquidated a series of natural gas swaps for the period from April 2011 through and including October 2011. These natural gas swaps carried a strike price of $7.69/Mcf which was significantly above the market prices of natural gas prevailing at that time. The liquidation resulted in cash proceeds of $10.2 million to the Company.

As of June 30, 2011, the Company had interest rate collars covering $112.5 million of floating interest rate exposure. See Note 7. These interest rate collars, which expire in September 2011, set a LIBOR ceiling of 4.90% and a LIBOR floor of 3.49% for the $112.5 million notional amount under contract. As a result of current market conditions, the Company is currently a net payer under these arrangements to our counterparties. As a part of the 2011 Refinancing as described in Note 7, we terminated $37.5 million of notional amount hedged . The expiration date for the remaining interest rate collars continues to be September 5, 2011.

On June 20, 2011, the Company entered into a $100 million interest rate derivative arrangement with a single counterparty where by the Company agrees to pay floating rate interest of three month LIBOR plus 863 basis points in exchange for receiving a fixed rate of 10.50% through May 15, 2016. This reverse interest rate swap is settled semi-annually on the interest payment dates of our 10.500% Senior Secured Second Lien due 2016.

On August 9, 2011, as the result of significant turmoil in the global capital markets, the Company terminated the $100 million reverse interest rate swap. As a result of this termination event, Milagro realized a cash settlement of $2.0 million from its counterparty.

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

All derivative contracts are recorded at fair market value and included in the consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of June 30, 2011 and December 31, 2010 (in thousands):


		Fair Value
		June 30,		December 31,
Description	Location in Balance Sheet	2011		2010

Asset derivatives:
Natural gas collars and swaps — current portion	Derivative assets — current	$	7,733	$	18,834
Noncurrent portion	Derivative assets — noncurrent		1,553		2,646
Natural gas liquids swaps — current portion	Derivative assets — current		—		—
Noncurrent portion	Derivative assets — noncurrent		5		—
Interest rate collars:
Current portion	Derivative assets — current		1,364		—
Noncurrent portion	Derivative assets — noncurrent		—		—

		$	10,655	$	21,480

Liability derivatives:
Oil collars and swaps — current portion	Derivative liabilities — current	$	5,300	$	5,917
Noncurrent portion	Derivative liabilities — noncurrent		5,594		2,926
Natural gas liquids swaps — current portion	Derivative liabilities — current		56		—
Noncurrent portion	Derivative liabilities — noncurrent		—		—
Interest rate collars:
Current portion	Derivative liabilities — current		924		3,510
Noncurrent portion	Derivative liabilities — noncurrent		2,138		—

		$	14,012	$	12,353

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations:


	Location in Statements	Six Months Ended June 30,
Description	of Operations	2011			2010
		(In thousands)

Commodity contracts:
Realized (loss)/gain on commodity contracts	Gain/(Loss) on commodity derivatives	$	10,733		$	17,444
Unrealized gain/(loss) on commodity contracts	Gain/(Loss) on commodity derivatives		(14,297	)		4,574

Total net gain/(loss) on commodity contracts		$	(3,564	)	$	22,018
Interest rate swaps:
Realized loss on interest rate swaps	Net loss on interest rate derivatives	$	2,726		$	4,676
Unrealized gain on interest rate swaps	Net loss interest rate derivatives		(1,812	)		(3,417	)

Total net loss on interest rate swaps			914			1,259

Total net gain/(loss) on derivative contracts		$	(4,478	)	$	20,759

At June 30, 2011, the Company had the following natural gas collar positions:


	Collars
			Floors				Ceilings
					Weighted-				Weighted-
	Volume in		Price/		Average		Price/		Average
Period	MMbtu’s		Price Range		Price		Price Range		Price

July 2011 — December 2011		2,260,164	$	3.50	$	5.08	$	10.60	$	7.06
January 2012 — December 2012		2,400,000		4.25		5.94		8.10		7.41
January 2013 — December 2013		2,040,000		4.70		4.80		5.85		5.77
January 2014 — December 2014		480,000		5.10		5.10		6.20		6.20

At June 30, 2011, the Company had the following natural gas swap positions:


	Swaps
					Weighted-
	Volume in		Price/		Average
Period	MMbtu’s		Price Range		Price

July 2011 — December 2011		1,059,911	$	7.93-8.43	$	8.09
January 2012 — December 2012		2,496,914		5.00-5.15		5.05
January 2013 — December 2013		1,200,000		5.20		5.20
January 2014 — December 2014		1,200,000		5.20		5.20

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At June 30, 2011, the Company had the following crude oil collar positions:


	Collars
			Floors				Ceilings
					Weighted-				Weighted-
	Volume in		Price/		Average		Price/		Average
Period	Bbl’s		Price Range		Price		Price Range		Price

July 2011 — December 2011		238,740	$	68.00	$	71.92	$	93.24	$	84.50
January 2012 — December 2012		481,563		80.00		81.25		96.50		91.44
January 2013 — December 2013		276,000		90.00		91.78		102.95		100.33
January 2014 — December 2014		276,000		90.00		92.13		101.00		99.24

At June 30, 2011, the Company had the following crude oil swap positions:


	Swaps
					Weighted-
	Volume in		Price/		Average
Period	Bbl’s		Price Range		Price

July 2011 — December 2011		63,462	$	99.85-101.60	$	100.08
January 2012 — December 2012		29,021		101.60		101.60
January 2013 — December 2013		24,000		91.00-91.50		91.25
January 2014 — December 2014		24,000		91.00-91.50		91.25

At June 30, 2011, the Company had the following natural gas liquids swap positions:


	Swaps
					Weighted-
	Volume in		Price/		Average
Period	Bbl’s		Price Range		Price

July 2011 — December 2011		75,000	$	56.79	$	56.79
January 2012 — December 2012		60,000		51.00		51.00

At June 30, 2011, the Company had the following interest rate collar positions (notional amount in thousands):


Interest Rate Collars
Cap	Floor	From and	To but	Notional
Rate	Rate	Including	Excluding	Amount

4.90%	3.49%	01/01/11	09/05/11	$112,500

Reverse Interest Rate Swap


Company Pays	Company Receives	From	Final Payment	Notional Amount

LIBOR + 863 bps	10.50%	06/22/11	05/11/16	$100,000


6.	FAIR VALUES OF FINANCIAL INSTRUMENTS

The table below presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2011 and December 31, 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

commonly quoted intervals. Level 3 inputs are unobservable inputs for the asset or liability and include situations where there is little, if any, market activity for the asset or liability. In instances in which the inputs used to measure fair value may fall into different levels of the fair value hierarchy, the level in the fair value hierarchy within which the fair value measurement in its entirety has been determined is based on the lowest level input significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Disclosures concerning financial assets and liabilities measured at fair value are as follows:


	Assets and Liabilities Measured at
	Fair Value on a Recurring Basis
	Quoted Once		Significant
	in Active		Other			Significant
	Markets for		Observable			Unobservable
	Identical Assets		Inputs			Inputs		Total
	(Level 1)		(Level 2)			(Level 3)		Balance

June 30, 2011:
Commodity derivatives — gas	$	—	$	9,286		$	—	$	9,286
Commodity derivatives — oil		—		(10,894	)		—		(10,894	)
Commodity derivatives — liquids		—		(51	)		—		(51	)
Interest rate collars		—		(1,698	)		—		(1,698	)
December 31, 2010:
Commodity derivatives — gas		—	$	21,480			—	$	21,480
Commodity derivatives — oil		—		(8,843	)		—		(8,843	)
Interest rate collars		—		(3,510	)		—		(3,510	)

Derivative Financial Instruments — The majority of the inputs used to value the Company’s derivatives fall within Level 2 of the fair value hierarchy; however, the credit valuation adjustments associated with these derivatives utilize Level 3 inputs, such as estimates of current credit spreads to evaluate the likelihood of nonperformance. As of June 30, 2011 and December 31, 2010, the impact of the credit valuation adjustments on the overall valuation of the Company derivative positions is not significant to the overall valuation. As a result, derivative valuations in their entirety are classified in Level 2 of the fair value hierarchy.

Debt Instruments — The 2011 First Lien Credit Agreement accrues interest on a variable-rate basis. The Notes accrue interest on a fixed rate basis. The Company estimates the carrying values in Note 7 to represent an approximation to its fair value based on the terms of similar debt that would be available to the Company.

Cash, Trade Receivables, and Payables — The fair value approximates carrying value given the short-term nature of these investments.

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


7.	DEBT

The Company’s debt as of June 30, 2011 and December 31, 2010, was comprised of the following amounts (in thousands):


	June 30,		December 31,
	2011		2010

Revolver — current	$	—	$	184,580
Revolver — long-term		96,000		—
Second lien — current		—		60,000
Second lien — long term		—		92,390
Senior Secured Second Lien Notes — long-term		243,186		—
Series A preferred stock — long term		—		223,630

Total debt	$	339,186	$	560,600

Scheduled maturities or mandatory redemption dates by fiscal year are as follows (amounts in thousands):


Years Ending December 31	Amount

2011	$	—
2012		—
2013		—
2014		96,000
2015		—
2016		243,186

	$	339,186

As described in more detail below, in May 2011, we completed an offering of an aggregate of $250.0 million of our 10.500% Senior Secured Second Lien Notes due 2016. We used the proceeds of this offering, together with borrowings under our amended and restated first lien credit agreement, to refinance substantially all of our existing indebtedness (the “2011 Refinancing”).

First Lien Credit — Prior to the 2011 Refinancing, our first lien credit agreement (the “Prior First Lien Agreement”) among Milagro Exploration, LLC and Milagro Producing, LLC, each an indirect wholly-owned subsidiary of the Company (collectively, the “Borrowers”), Milagro Oil & Gas, Inc., each of the lenders from time to time party thereto and Wells Fargo Bank, N.A. as administrative agent for the lenders, provided for a borrowing base of $179 million. The borrowing base was based on the estimated value of the Borrowers’ oil and natural gas properties, was redetermined on a semi-annual basis (with the Company and the lenders each having the right to one annual interim unscheduled redetermination) and adjusted based on the Company’s oil and natural gas properties, reserves, other indebtedness and other relevant factors.

Amounts outstanding under the Prior First Lien Agreement bore interest at specified margins over LIBOR of between 3.00% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 2.00% and 2.75% for ABR loans. Such margins fluctuated based on the utilization of the facility. Borrowings under the Prior First Lien Agreement were secured by all of the Company’s oil and gas properties. The lenders’ commitments to extend credit was scheduled to expire, and amounts drawn under the Prior First Lien Agreement would have matured, in November 2011.

As part of the 2011 Refinancing, the Company entered into a $300 million Amended and Restated First Lien Credit Agreement (“2011 First Lien Agreement”) that matures in November 2014. The initial borrowing base for this facility was established at $170 million with semi-annual re-determinations to begin in November 2011.

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MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Amounts outstanding under the 2011 First Lien Agreement bear interest at specified margins over the LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. As of June 30, 2011, the interest rate was 3.52%. Borrowings under the 2011 First Lien Agreement are secured by all of the Company’s oil and gas properties. The lenders’ commitments to extend credit will expire, and amounts drawn under the 2011 First Lien Agreement will mature, in November 2014.

The 2011 First Lien Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused availability of the borrowing base under the 2011 First Lien Agreement to current liabilities) of not less than 1.0 to 1.0, minimum Interest Coverage Ratio, as defined, of not less than 2.25 to 1.0 and maximum Leverage Ratio, as defined, of debt balances as compared to EBITDA of not greater than 4.5 to 1.0. The Interest Coverage ratio increases from 2.25 to 1.0 during 2011 and 2.5 to 1.0 thereafter. The Leverage Ratio, as defined, reduces from 4.5 to 1.0 during 2011 to 4.25 to 1 during 2012 and 4.0 to 1 thereafter. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt and liens, changes of control and asset sales. As at June 30, 2011, the Company is in compliance with the financial covenants governing the 2011 First Lien Credit Agreement.

Second Lien — As part of the 2010 recapitalization, the Borrowers entered into a Term Loan Agreement (the “Prior Second Lien Term Loan Agreement”) between the Borrowers, each of the lenders from time to time party thereto and Guggenheim Corporate Funding, LLC, as administrative agent. The Term Loan Agreement provides for three types of loans which are the Term Loans (new loans advanced in full on the closing date), the Delayed Draw Loans (term loans available to be drawn in the future based on certain terms and conditions), and the Converted Loans (existing loans converted from our prior second lien credit agreement). As part of the 2010 recapitalization, the Borrowers and the certain of the prior second lien debt holders entered into a Second LienPayable-in-Kind Facility Agreement (the “Prior Second Lien PIK Facility”), in which the prior second lien debt holders which did not convert their loans under the Prior Second Lien Term Loan Agreement agreed to continue their existing loans consisting of principal and accrued interest totaling approximately $62.6 million.

Concurrently with the closing of the 2011 Refinancing, the Company repaid in full the approximately $152.6 million in aggregate principal amount outstanding under the Prior Second Lien Credit Agreement and the Prior Second Lien PIK Facility, together, in each case, with the accrued interest thereon to the date of such repayment.

Series A Preferred Stock — As part of the 2010 recapitalization, the Company entered into agreements to exchange a portion of prior second lien indebtedness for $205.5 million of Series A Preferred Stock (the “Series A”), consisting of 2,700,000 shares issued at $76.12 per share redeemable in 2016. The preferred shareholders receive a 12% dividend each year paid in cash, or in-kind, which is determined solely at the option of the Company. There were no cash dividends paid during 2010 and the Company has not paid dividends in 2011. There was an increase of approximately $10.4 million of Series A from December 31, 2010 to May 11, 2011, which was primarily related to the accrual of the in-kind dividend that was recorded as interest expense. Upon completion of the 2011 Refinancing, including the amendment of the terms of the Series A as described in Note 9, we reclassified the Series A as mezzanine equity for financial reporting purposes because there is no longer a mandatory redemption provision.

Capitalization of Debt Costs — The Company capitalizes certain direct costs associated with the issuance of long-term debt, which is then amortized over the lives of the respective debt using the straight-line method, which approximates the interest method.

Senior Secured Second Lien Notes — As part of the 2011 Refinancing, the Company issued Senior Secured Second Lien Notes due May 11, 2016 with a face value of $250 million, at a discount of $7.0 million (the “Notes”). The Notes carry a face interest rate of 10.5%; interest is payable semi-annually each May 15 and November 15. The Notes are secured by a second priority lien on all of the collateral securing the 2011 First Lien Agreement, and

F-41

MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

effectively rank junior to any existing and future first lien secured indebtedness of the Company, which includes the 2011 First Lien Agreement. The balance is presented net of unamortized discount of $6.8 million at June 30, 2011.

The Notes contain an optional redemption provision allowing the Company to retire up to 35% of the principal outstanding with the proceeds of an equity offering, at 110.5% of par. Additional optional redemption provisions allow for the retirement of all or a portion of the outstanding senior secured second lien notes at 110.5%, 102.625% and 100.0% beginning on each of May 15, 2014, May 15, 2015 and November 15, 2015, respectively. If a change of control occurs, each noteholder may require the Company to repurchase all or a portion of its notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus any accrued and unpaid interest and special interest, if any, to, but not including, the date of repurchase. The indenture governing the Notes contains covenants that, among other things, limit the Company’s ability to incur or guarantee additional indebtedness or issue certain preferred stock; declare or pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; transfer or sell assets; make investments; create certain liens; consolidate, merge or transfer all or substantially all of its assets; engage in transactions with affiliates; and create unrestricted subsidiaries.

In connection with the offering of the Notes, the Company entered into a registration rights agreement with the initial purchasers. Under the terms of the registration rights agreement, the Company will file a registration statement within 180 days of the closing date to become effective no later than 300 days after the closing date, to allow for the registration of “exchange notes” with terms substantially identical to the Notes. The exchange notes are to be exchanged for the Notes within 30 days after the registration statement becomes effective. If the Company fails to file any of the registration statements required by the registration rights agreement on or before the date specified for such filing, then the Company will pay special interest to each holder of entitled securities until all registration defaults have been cured. With respect to the first90-day period immediately following the occurrence of the first registration default, special interest will be paid at the rate of 0.25% per annum. Such rate will increase by an additional 0.25% per annum with respect to each subsequent90-day period until all registration defaults have been cured, up to a maximum rate of special interest for all registration defaults of 1.0% per annum.


8.	GUARANTOR AND NON-GUARANTOR

The Company is not required to disclose condensed consolidating financial information as the parent company has no independent assets or operations and owns 100% of each of the Borrowers, Milagro Resources LLC and Milagro Mid-Continent LLC. The subsidiary guarantees are full and unconditional guarantees of the Company’s outstanding debt on a joint and several basis. There are no non-guarantor subsidiaries. These subsidiaries are included in the consolidated financial statements.

9. MEZZANINE EQUITY

In connection with the 2011 Refinancing, the Company amended the terms of the Series A. Prior to the amendment, the Series A was treated as debt for accounting purposes, as there was a mandatory redemption date. The amendment made the Series A a perpetual instrument and removed the mandatory redemption. The amendment also requires two-thirds (2/3) of the holders to request redemption, 180 days after the maturity of certain qualified debt, with the redemption date being not more than 90 days after receiving the redemption request. Therefore, as a result of the amendment, the Series A was reclassified from long-term debt to mezzanine equity.

The holders of the Series A shall be entitled to receive dividends on a cumulative basis. Dividends shall accrue, whether declared or not, semi-annually at a 12% rate. Accrued dividends shall be paid in kind when, and if declared by the Company’s board of directors and shall be made by issuing an amount of additional shares of Series A based on the original issue price. As of June 30, 2011 the dividends in arrears were $3.8 million.

The fair value of the Series A approximates the carrying value at the time of the 2011 Refinancing.

F-42

MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


10.	COMMON STOCK

The Company is authorized to issue up to 1,000,000 shares of Common Stock, par value $0.01 per share. As of June 30, 2011, 280,400 shares of Common Stock were issued and outstanding and held by Parent. Holders of Common Stock are entitled to, in the event of liquidation, to share ratably in the distribution of assets remaining after payment of liabilities. Holders of Common Stock have no cumulative rights. The holders of a plurality of the outstanding shares of the Common Stock have the ability to elect all of the directors. Holders of Common Stock have no preemptive or other rights to subscribe for shares. Holders of Common Stock are entitled to such dividends as may be declared by the Board out of funds legally available therefore. The Company has never paid cash dividends on the Common Stock and does not anticipate paying any cash dividends in the foreseeable future.


11.	INCOME TAXES

We recorded no income tax benefit for the six months ended June 30, 2011. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2010 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred assets as of June 30, 2011.


12.	COMMITMENTS AND CONTINGENCIES

Commitments — The Company leases corporate office space in Houston, Texas. Rental expense was approximately $0.9 million and $1.2 million for the six months ended June 30, 2011 and 2010, respectively.

In 2009, the Company entered into a contract with an investment bank for advisory services to be provided in 2010 for guaranteed fees of $1.0 million, this contract has been extended to 2011. The Company paid $300,000 in fees out of the $1.0 million to the investment bank in connection with the 2011 Refinancing.

The following table summarizes the Company’s contractual obligations and commitments at June 30, 2011, by fiscal year (amounts in thousands):


	2011		2012		2013		2014		2015		Thereafter		Total

Office lease	$	882	$	1,798	$	1,884	$	1,913	$	1,913	$	3,188	$	11,578
Other		700		—		—		—		—		—		700

Contingencies:

There are currently various suits and claims pending against the Company that have arisen in the ordinary course of the Company’s business, including contract disputes, property damage claims and title disputes. Management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material effect on the Company’s consolidated financial position, results of operations or cash flow. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.


13.	EMPLOYEE BENEFIT PLANS

The Company operates a discretionary bonus plan and a 401(k) savings plan via a third-party service provider. Upon hire, an individual is immediately eligible to participate in the 401(k) plan. The Company, under its sole discretion, may contribute an employer-matching contribution equal to a percentage not to exceed 6% of each

F-43

MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

eligible participant’s contributions. For the six months ended June 30, 2011 and 2010, the Company contributed $362,281 and $158,346, respectively.


14.	RELATED PARTY TRANSACTIONS

As of June 30, 2011 and December 31, 2010, the Company had a receivable of $2.2 million for monitoring fees paid on behalf of Parent, to certain of Parent’s members (ACON Milagro Investors, LLC, Milagro Investors, LLC and West Coast Milagro Partners, LLC) in 2008 and 2007, which are recognized as an advance to affiliates in the accompanying balance sheet.


15.	SEGMENT INFORMATION

The Company measures financial performance as a single enterprise, allocating capital resources on a project by project basis across its entire asset base to maximize profitability. The Company utilizes a company-wide management team that administers all enterprise operations encompassing the exploration, development and production of natural gas and oil. Since the Company follows the full cost of method of accounting and all its oil and gas properties and operations are located in the United States, the Company has determined that it has one reporting unit. In as much as the Company, is one enterprise, it does not maintain comprehensive financial statement information by area but does track basic operational data by area.

F-44

MILAGRO OIL & GAS, INC.

SUPPLEMENTAL DISCLOSURES ABOUT OIL & GAS PRODUCING ACTIVITIES (unaudited)


1.	Modernization of Oil and Natural Gas Reporting Requirements

The reserve estimates as of December 31, 2010 and 2009 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance issued by the Financial Accounting Standards Board effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s “Modernization of Oil and Gas Reporting” rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.

The above-mentioned rules include updated definitions of proved oil and gas reserves, proved undeveloped oil and gas reserves, oil and gas producing activities, and other terms used in estimating proved oil and gas reserves. Proved oil and gas reserves as of December 31, 2010 and 2009 were calculated based on the prices for oil and gas during the twelve month period before the reporting date, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, rather than the year-end spot prices, which had been used in years prior to 2009. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved 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. The authoritative guidance broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of oil and gas producing activities to include the extraction of non-traditional resources, including bitumen extracted from oil sands as well as oil and gas extracted from shales. Data prior to December 31, 2009 presented throughout this footnote is not required to be, nor has it been, updated based on the new guidance.


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

Costs incurred in the acquisition and development of oil and gas assets are presented below for the years ended December 31:


	2010		2009			2008
	(In millions)

Property acquisition costs:
Proved(1)	$	66.9	$	—		$	(16.9	)
Unproved		3.3		2.5			23.4
Exploration		16.1		17.4			94.8
Development costs(2)		27.0		(3.0	)		101.0

Total costs incurred	$	113.3	$	16.9		$	202.3


(1)		The negative acquisition costs primarily relate to the forgiveness of a portion of the debt for early payment with Petrohawk that was entered into at the time of the 2007 acquisition for funding resulting in a purchase price adjustment in 2008.

(2)		Includes asset retirement liabilities incurred and revisions of previous estimates of $10.1 million, $(9.9) million and $1.7 million for 2010, 2009 and 2008, respectively.

F-45


3.	Capitalized Oil and Gas Costs

Aggregate capitalized costs related to oil and gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below as of December 31:


	2010		2009		2008
	(In thousands)

Capitalized costs:
Proved properties	$	1,181,948	$	1,037,129	$	1,014,113
Unproved properties		13,156		43,887		82,024

Less: accumulated depreciation, depletion, amortization and impairment		743,637		691,564		584,899

Net capitalized costs	$	451,467	$	389,452	$	511,238

Unproved properties, which are not subject to amortization, are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the amortization calculation.


4.	Proved Oil and Gas Reserves

The Company’s proved oil and gas reserves as of December 31, 2010, 2009 and 2008 were prepared by W.D Von Gonten & Co. (W.D. Von Gonten), independent third party petroleum consultants. W.D. Von Gonten prepared 100% of proved reserves for the years ended December 31, 2010, 2009, and 2008 respectively. In accordance with the new SEC regulations, reserves at December 31, 2010 and 2009 were estimated using the unweighted arithmetic averagefirst-day-of-the-month price for the preceding 12 — month period. The reserve estimate for 2008 was prepared in compliance with the applicable prior SEC rules based on year-end prices. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.

An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, for the years ended December 31, is as follows:

Milagro Oil & Gas, Inc
Supplemental Oil and Gas Disclosures


	Year Ended December 31, 2010
	Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			MBoe

Proved developed and undeveloped reserves:
Beginning of year		121,922			9,403			1,218			30,942
Revisions of previous estimates		4,627			197			293			1,261
Extensions, discoveries and other additions		868			31			40			216
Divestitures of reserves		(5	)		(4	)		—			(5	)
Purchases of minerals in place		20,967			1,170			2,893			7,557
Production		(13,657	)		(871	)		(139	)		(3,287	)

End of year		134,722			9,926			4,305			36,684

Proved developed reserves:
Beginning of year		93,748			7,041			787			23,453
End of year		90,401			7,300			2,057			24,424
Proved undeveloped reserves:
Beginning of year		28,174			2,362			431			7,489
End of year		44,321			2,626			2,248			12,260

F-46


	Year Ended December 31, 2009
	Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			MBoe

Proved developed and undeveloped reserves:
Beginning of year		147,587			9,365			1,300			35,262
Revisions of previous estimates		(10,298	)		1,499			43			(174	)
Extensions, discoveries and other additions		4,926			494			50			1,365
Divestitures of reserves		(1,781	)		(1,017	)		—			(1,313	)
Purchases of minerals in place		—			—			—			—
Production		(18,512	)		(938	)		(175	)		(4,198	)

End of year		121,922			9,403			1,218			30,942

Proved developed reserves:
Beginning of year		113,449			7,213			967			27,088
End of year		93,748			7,041			787			23,453
Proved undeveloped reserves:
Beginning of year		34,138			2,151			333			8,174
End of year		28,174			2,362			431			7,489


	Year Ended December 31, 2008
	Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			MBoe

Proved developed and undeveloped reserves:
Beginning of year		184,298			10,380			500			41,597
Revisions of previous estimates		(24,585	)		(553	)		641			(4,010	)
Extensions, discoveries and other additions		16,570			921			339			4,021
Divestitures of reserves		(3,915	)		(27	)		—			(680	)
Purchases of minerals in place		125			4			5			30
Production		(24,906	)		(1,360	)		(185	)		(5,696	)

End of year		147,587			9,365			1,300			35,262

Proved developed reserves:
Beginning of year		128,349			8,045			395			29,832
End of year		113,449			7,213			967			27,088
Proved undeveloped reserves:
Beginning of year		55,949			2,335			105			11,765
End of year		34,138			2,151			333			8,174

The tables above include changes in estimated quantities of oil and natural gas reserves shown in Mcf equivalents (“Mcfe”) at a rate of one Bbl per six Mcf and shown in Bbl equivalents (“Boe”) at a rate of six Mcf per one Bbls.

For the year ended December 31, 2010, the Company added 7.6 MMBoe through acquisitions in its core areas of onshore Texas Gulf Coast and the Midcontinent, with a positive revision of 1.3 MMBoe of previous estimated quantities primarily due to an increase in reference prices. The oil and natural gas reference prices used in computing reserves as of December 31, 2010 were $79.43 per barrel and $4.38 per Mmbtu before price differentials.

For the year ended December 31, 2009, extensions of 1.4 MMBoe during the year ended December 31, 2009, consist primarily from adding of seven proved undeveloped locations. Divestures of 1.3 MMBoe were made throughout 2009. The oil and natural gas reference prices used in computing reserves as of December 31, 2009 were $61.18 per barrel and $3.87 per Mmbtu before price differentials.

F-47

For the year ended December 31, 2008, the Company’s negative revision of previous estimated quantities is composed of a 4.0 MMBoe revision due to the decrease in oil and gas prices at December 31, 2008. Extensions, discoveries, and other additions of 4.0 MMBoe during the year ended December 31, 2008, consist of 2.6 MMBoe primarily from the drilling of discovery wells during the year and 1.4 MMBoe from new proved undeveloped locations added during the year. The oil and natural gas reference prices used in computing reserves as of December 31, 2008 were $44.60 per barrel and $5.71 per Mmbtu before price differentials.


5.	Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2010 and 2009 are based on the unweighted arithmetic averagefirst-day-of-the-month price for the preceding12-month period and reserves as of December 31, 2008 prepared in compliance with the applicable prior SEC rules based on year-end prices. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves, less the tax basis of the Company. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.

F-48

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31:


	2010			2009			2008
	(In thousands)

Future cash inflows	$	1,505,295		$	1,038,573		$	1,227,930
Future production costs		(459,137	)		(343,508	)		(473,848	)
Future development costs		(195,440	)		(137,580	)		(133,257	)
Future income tax expenses		(80,150	)		(3,791	)		—

Future net cash flows		770,568			553,694			620,825
10% discount for estimated timing of cash flows		(321,533	)		(235,496	)		(227,254	)

Standardized measure of discounted future net cash flows	$	449,035		$	318,198		$	393,571

Standardized measure of discounted future net cash flows, beginning of year	$	318,198		$	393,571		$	853,223
Changes in the year resulting from:
Sales, less production costs		(89,020	)		(87,223	)		(293,631	)
Revisions of previous quantity estimates		16,946			(1,757	)		(82,240	)
Extensions, discoveries and other additions		3,930			11,006			53,342
Net change in prices and production costs		96,996			4,767			(212,898	)
Changes in estimated future development costs		(2,507	)		(23,456	)		(7,736	)
Previously estimated development costs incurred during the period		7,227			933			36,581
Purchases of minerals in place		72,121			—			457
Accretion of discount		31,886			39,357			85,322
Divestiture of Reserves		(68	)		(19,300	)		(9,625	)
Net change in income taxes		(43,234	)		(660	)		—
Timing differences and other		36,560			960			(29,224	)

Standardized measure of discounted future net cash flows, end of year	$	449,035		$	318,198		$	393,571

F-49

MILAGRO OIL & GAS, INC.

Exchange Offer for

$250,000,000 10.500% Senior Secured Second Lien Notes due 2016

 

PROSPECTUS

Dealer Prospectus Delivery Obligation

Until February 13, 2012, all dealers that effect transactions in these securities, whether or

not participating in this offering, may be required to deliver a prospectus. This is in addition to

the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to

their unsold allotments or subscriptions.

November 14, 2011

Milagro Oil & Gas Inactive 424B3Prospectus supplement