Century Exploration New Orleans S-4 Registration of securities issued in business combination transactions

As filed with the Securities and Exchange Commission on October 6, 2011

Registration No. 333-            

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-4

REGISTRATION STATEMENT

under

the Securities Act of 1933

RAAM GLOBAL ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware	1311	20-0412973
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1537 Bull Lea Rd., Suite 200

Lexington, Kentucky 40511

(859) 253-1300

(Address, including zip code, and telephone number,

including area code, of registrant’s principal executive offices)

Howard A. Settle

President and Chief Executive Officer

1537 Bull Lea Rd., Suite 200

Lexington, Kentucky 40511

(859) 253-1300

(Name, address, including zip code, and telephone number,

including area code, of agent for service)

Copies to:

Douglas E. McWilliams

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2300

Houston, Texas 77002-6760

(713) 758-2222

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

Exchange Act Rule 13e-4(i) (Cross-Border Issue Tender Offer)  ¨

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer)  ¨

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to Be Registered	Amount to be Registered	Amount of Registration Fee (1)
12.50% Senior Notes due 2015	$50,000,000	$5,730.00
Guarantees of 12.50% Senior Notes due 2015 (2)		None (3)

(1) Calculated pursuant to Rule 457(f)(2) under the Securities Act of 1933.

(2) Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Century Exploration Resources, LLC, Sita Energy, LLC and Windstar Energy, LLC, our subsidiaries, have guaranteed the notes being registered.

(3) Pursuant to Rule 457(n) of the Securities Act of 1933, no registration fee is required for the Guarantees.

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

TABLE OF ADDITIONAL REGISTRANT GUARANTORS

Exact Name of Registrant Guarantors	State or Other Jurisdiction of Incorporation or Formation		Primary Standard Industrial Classification Code Number		IRS Employer Identification Number
Century Exploration New Orleans, LLC(1)		Delaware		1311		61-1104948
Century Exploration Houston, LLC(2)		Delaware		1311		61-1439624
Century Exploration Resources, LLC(3)		Delaware		1311		20-8957252
Sita Energy, LLC(3)		Delaware		1311		26-1957149
Windstar Energy, LLC(3)		Delaware		1311		26-1957211

(1) The address for Century Exploration New Orleans, LLC is Three Lakeway Center, Suite 2800, 3838 North Causeway Blvd., Metairie, Louisiana 70002.

(2) The address for Century Exploration Houston, LLC is 10210 Grogan’s Mill Road, Suite 300, The Woodlands, Texas 77380.

(3) The address for Century Exploration Resources, LLC, Sita Energy, LLC and Windstar Energy, LLC is 1537 Bull Lea Rd., Suite 200, Lexington, Kentucky 40511, and the telephone number for the Registrant Guarantors is (859) 253-1300.

PROSPECTUS

RAAM Global Energy Company

Offer to Exchange

Up To $50,000,000 of

12.50% Senior Notes due 2015

That Have Not Been Registered Under

The Securities Act of 1933

For

Up To $50,000,000 of

12.50% Senior Notes due 2015

That Have Been Registered Under

The Securities Act of 1933

Terms of the New 12.50% Senior Notes due 2015 Offered in the Exchange Offer:

• The terms of the new notes are materially identical to the terms of the old notes that were issued on July 15, 2011, except that the new notes will be registered under the Securities Act of 1933 and will not contain restrictions on transfer, registration rights or provisions for additional interest.

Terms of the Exchange Offer:

• We are offering to exchange up to $50,000,000 of our old notes for new notes with materially identical terms that have been registered under the Securities Act of 1933 and are freely tradable.

• We will exchange all old notes that you validly tender and do not validly withdraw before the exchange offer expires for an equal principal amount of new notes.

• The exchange offer expires at 5:00 p.m., New York City time, on                     , 2011, unless extended.

• Tenders of old notes may be withdrawn at any time prior to the expiration of the exchange offer.

• The exchange of new notes for old notes will not be a taxable event for U.S. federal income tax purposes.

You should carefully consider therisk factors beginning on page 13 of this prospectus before participating in the exchange offer.

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

The date of this prospectus is                     , 2011

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 and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume that the information contained in this prospectus is accurate as of any date other than its respective date.

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

TABLE OF CONTENTS

	Page
Cautionary Statements Regarding Forward Looking Statements		ii
Prospectus Summary		1
Risk Factors		13
Exchange Offer		38
Ratios of Earnings to Fixed Charges		44
Use of Proceeds		45
Supplemental Oil and Gas Disclosures		46
Selected Financial and Other Data		48
Management’s Discussion and Analysis of Financial Condition and Results of Operations		49
Business		69
Description of Notes		92
Book-Entry; Delivery and Form		142
Certain United States Federal Income Tax Considerations		145
Plan of Distribution		146
Legal Matters		147
Experts		147
Independent Petroleum Engineers		147
Available Information		147
Glossary of Oil and Natural Gas Terms		148
Index to Financial Statements		F-1
Annex A: Letter of Transmittal		A-1

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CAUTIONARY STATEMENTS REGARDING FORWARD LOOKING STATEMENTS

This prospectus contains forward looking statements. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words.

Forward looking statements may include statements that relate to, among other things, our:

• forward looking oil and natural gas reserve estimates;

• future financial and operating performance and results;

• business strategy and budgets;

• market prices;

• drilling of wells and the anticipated results thereof;

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

• competition and government regulations;

• prospect development;

• property acquisitions and sales; and

• plans, forecasts, objectives, expectations and intentions.

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

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

• low and/or declining prices for oil and natural gas and oil and natural gas price volatility;

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

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

• cash flow and liquidity;

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

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

• geological concentration of our reserves;

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

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

• potential mechanical failure or under-performance of significant wells or pipeline mishaps;

• delays in anticipated start-up dates;

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

• ability to find and retain skilled personnel;

• strength and financial resources of competitors;

• federal and state regulatory developments and approvals;

• environmental risks;

• changes in interest rates;

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

• worldwide political and economic conditions.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

All subsequent written and oral forward looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

iii

PROSPECTUS SUMMARY

This summary highlights certain information concerning our business. Because this is a summary, it may not contain all of the information that may be important to you and to your investment decision. The following summary is qualified in its entirety by the more detailed information and financial statements and notes thereto included elsewhere in this prospectus. You should read this prospectus carefully and should consider, among other things, the matters set forth in “Risk Factors.” In this prospectus, unless indicated otherwise, references to “RAAM,” the “Company,” “our company,” “we,” “our” and “us” refer to RAAM Global Energy Company and its subsidiaries. The estimates of the proved reserves of the Company as of December 31, 2010 included in this prospectus are based on a reserve report prepared by each of Netherland, Sewell & Associates, Inc., independent petroleum engineers, a summary of which is attached as Exhibit 99.1 to our Registration Statement on Form S-4 filed with the Securities and Exchange Commission on March 17, 2011, and H.J. Gruy and Associates, Inc., independent petroleum engineers, a summary of which is attached as Exhibit 99.2 to our Registration Statement on Form S-4 filed with the Securities and Exchange Commission on March 17, 2011 (collectively, the “Reserve Reports”). For the definitions of certain terms used in the oil and natural gas industry, see “Glossary of Oil and Natural Gas Terms.”

In this prospectus we refer to the notes to be issued in the exchange offer as the “new notes” and the notes issued on July 15, 2011 as the “old notes.” We refer to the new notes and the old notes collectively as the “notes.”

Our Company

We are a privately held oil and natural gas exploration and production company engaged in the exploration, development, production and acquisition of oil and gas properties. Our operations are located in the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas, Oklahoma, California and New Mexico. We focus on the development of both conventional oil and gas plays and unconventional resource plays. Historically, we have successfully developed conventional oil and gas plays in the offshore Gulf of Mexico and onshore Texas and Louisiana. More recently, we have redirected our focus to the acquisition and development of acreage in the shallow oil, tight gas sand and oil shale plays throughout the United States. Since 2007, we have targeted unconventional plays, including tight gas and oil in shale in Oklahoma, California, and New Mexico and have obtained land positions in these plays.

Our assets create a portfolio of production, resources and opportunities that are balanced between long-lived, dependable production and exploration and development opportunities. Current development projects are focused on three main areas: shallow waters offshore, onshore conventional assets in Texas, Louisiana and Oklahoma, and unconventional assets in Oklahoma. We have selectively acquired and accumulated a portfolio of oil and gas leases in both oil and gas prone unconventional areas domestically. We plan to continue to augment our Gulf Coast production, increase our proved reserves and the reserve life of our portfolio through the development of these unconventional assets.

At December 31, 2010, we had estimated total proved oil and natural gas reserves of 18.8 MMBoe (61% oil). For 2010, our net daily production averaged 10,305 Boepd, which generated revenue of $198 million.

Core Properties

Our core properties include assets offshore in the Gulf of Mexico in Louisiana state waters and United States federal waters, onshore in Texas and Louisiana and conventional and unconventional assets in Oklahoma.

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Offshore

Gulf of Mexico — Louisiana State Waters. We commenced operations in the Breton Sound 53 Field in 1989 and currently operate 13 producing wells from 2 manned production platforms which we own. Average net daily production for the year ended December 31, 2010 was 3,642 Boepd. Our leasehold position encompassed 8,602 net acres with proved reserves of 5,903 MBoe at December 31, 2010. We have had a 75% drilling success rate in the Breton Sound 53 Field since 2000. Historical drilling success has been in the Uvig and Tex W zones above 10,500 feet. Recent development of the field has focused on newly discovered deep plays of the Big Hum and Cris I zones from 10,500 to 17,000 feet.

Gulf of Mexico — Federal Waters. We commenced operations in the shallow water West Cameron 368 Field and Ship Shoal 154 Field in the United States federal waters in 1987 and 1990, respectively, and we currently own and operate 15 wells and 12 production platforms. Average net daily production for the year ended December 31, 2010 from the United States federal waters was 3,346 Boepd. Our leasehold position encompassed 82,837 net acres with proved reserves of 9,231 MBoe as of December 31, 2010.

Onshore

Gulf Coast. We currently have 15 producing wells (15 operated) onshore along the Gulf Coast. Average net daily production for the year ended December 31, 2010 was 3,225 Boepd. Our leasehold position encompassed 9,865 net acres with proved reserves of 2,532 MBoe at December 31, 2010. In Texas, we have focused on the Eocene Yegua/Cook Mountain trend which produce natural gas with high condensate yields. Average net daily production for the year ended December 31, 2010 was 1,320 Boepd from 7 producing wells. During the first half of 2011, we either drilled or completed two additional wells in the Eocene Yegua/Cook Mountain trend, which were online and producing at June 30, 2011. In Louisiana, we have continued to focus on the Lower Miocene Atchafalaya Basin. Average net daily production for the year ended December 31, 2010 was 773 Boepd from 4 producing wells. In addition, we realized 1,132 Boepd of production for the year ended December 31, 2010 from 4 wells in other areas of Louisiana, Mississippi and Texas.

Resource Plays

Oklahoma. Our leasehold position in the shallow oil Mississippi Chat formation of Oklahoma encompassed approximately 38,810 net acres with proved reserves of 1,112 MBoe at December 31, 2010 and average net daily production for the year ended December 31, 2010 of 92 Boepd from 24 producing wells. We own a 50% working interest in an Osage tribe concession in Osage County, Oklahoma. The concession contains 74,580 acres, with approximately half of the concession acreage covered by a modern 3-D seismic survey. Since acquiring the concession in 2007 (including 5 currently producing wells), we have drilled 21 vertical wells, of which 19 vertical wells have been completed with commercial oil production. Two of our vertical wells have been successfully completed in the Mississippi Lime formation, which establishes the presence of commercial oil in this formation. We believe our drilling program to date has proven that significant oil resources exist within our concession acreage. We believe that such completed wells have helped to determine the level of prospectivity of our existing acreage and have reinforced our belief that with access to additional capital our existing acreage positions may provide opportunities for substantial revenue and proved reserve growth with both vertical and horizontal wells.

Recent Developments

On August 24, 2011, the Company purchased all of the issued and outstanding equity of Charter III, Inc. (Charter III) from the shareholders of Charter III for aggregate consideration of approximately $21.0 million. The aggregate consideration was based upon a Charter III reserve report and fair market valuation report from a third party. The Company also obtained a fairness opinion from another third party.

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Beginning in August 2011, we drilled four vertical wells on our Oklahoma acreage in Osage county. These wells are in various stages of completion and review. Two salt water disposal wells were drilled, and facilities are being put in place to bring these wells into production in the fourth quarter of 2011.

In September 2011, we drilled our Perry prospect to total depth. This well was a continuation of our exploration program in the Eocene Yegua/Cook Mountain trend in Texas. We encountered pay in two zones, and the well is deemed to be a commercial well which is expected to be completed in October 2011. Production facilities are expected to be completed in the fourth quarter of 2011.

Also in September 2011, we drilled our Centaurus prospect to total depth. This well was drilled in our Breton Sound 52 Field in the state waters of Louisiana. We encountered pay in the Big Hum section, and the well is deemed to be to be commercial. Completion operations have begun on our Virgo North well which was drilled earlier in 2011 and encountered pay in the Uvig section. As soon as the Virgo North well is completed, completion operations will begin on the Centaurus well. Production from both wells is anticipated before year end 2011.

On September 30, 2011, Century Exploration New Orleans, Inc., Century Exploration Houston, Inc. and Century Exploration Resources, Inc. were converted to Century Exploration New Orleans, LLC, Century Exploration Houston, LLC and Century Exploration Resources, LLC, respectively. These companies are being operated as manager managed limited liability companies.

General Corporate Information

RAAM is a Delaware corporation with principal offices at 1537 Bull Lea Rd., Suite 200, Lexington, Kentucky 40511. We can be reached at (859) 253-1300 and our website address is www.raamglobal.com. We make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

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The Exchange Offer

On July 15, 2011, we completed a private offering of the old notes. We entered into a registration rights agreement with the initial purchasers in the private offering in which we agreed to deliver to you this prospectus and related registration statement and to use our reasonable best efforts to cause the registration statement to become effective by April 10, 2012.

Exchange Offer We are offering to exchange new notes for old notes.

Expiration Date The exchange offer will expire at 5:00 p.m., New York City time, on                     , 2011, unless we decide to extend it.

Condition to the Exchange Offer The registration rights agreement does not require us to accept old notes for exchange if the exchange offer, or the making of any exchange by a holder of the old notes, would violate any applicable law or interpretation of the staff of the SEC. The exchange offer is not conditioned on a minimum aggregate principal amount of old notes being tendered.

Procedures for Tendering Old Notes To participate in the exchange offer, you must follow the procedures established by The Depository Trust Company or “DTC,” for tendering notes held in book-entry form. These procedures, referred to as the Automated Tender Offer Program or “ATOP,” require that (i) the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an “agent’s message” that is transmitted through DTC’s automated tender offer program, and (ii) DTC confirms that:

• DTC has received your instructions to exchange your notes, and

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

For more information on tendering your old notes, please refer to the section in this prospectus entitled “Exchange Offer — Terms of the Exchange Offer,” “— Procedures for Tendering,” and “Description of Notes — Book Entry; Delivery and Form.”

Guaranteed Delivery Procedures None.

Withdrawal of Tenders You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer — Withdrawal of Tenders.”

Acceptance of Old Notes and Delivery of New Notes If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the exchange offer on or before 5:00 p.m. New York City time on the expiration date. We will return any old note that we do not accept for

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exchange to you without expense promptly after the expiration date and acceptance of the old notes for exchange. Please refer to the section in this prospectus entitled “Exchange Offer — Terms of the Exchange Offer.”

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

Use of Proceeds The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under our registration rights agreement.

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

U.S. Federal Income Tax Consequences The exchange of new notes for old notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read “Certain United States Federal Income Tax Consequences.”

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

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

Exchange Agent

c/o The Bank of New York Mellon Corporation

Corporate Trust Operations - Reorganization Unit

101 Barclay Street, Floor 7 East

New York, NY 10286

Attn:                     

Telephone: 212-815-             

Facsimile: 212-298-1915

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Terms of the New Notes

The new notes will be materially identical to the old notes except that the new notes are registered under the Securities Act of 1933 and will not have restrictions on transfer, registration rights or provisions for additional interest. The new notes will evidence the same debt as the old notes, and the same indenture will govern the new notes and the old notes.

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

Issuer RAAM Global Energy Company

Securities Offered $50.0 million aggregate principal amount of the 12.50% Senior Notes due 2015.

Maturity Date October 1, 2015.

Interest We will pay interest in cash on the principal amount of the new notes at an annual rate of 12.50%. We will pay interest on the new notes semi-annually, in arrears, on each April 1 and October 1. Interest on each new note will accrue from the last interest payment date on which interest was paid on the old note tendered in exchange thereof, October 1, 2011.

Guarantees The new notes will be fully and unconditionally guaranteed, jointly and severally on a senior secured basis by each of our existing and future domestic subsidiaries that guarantee indebtedness under our Amended Revolving Credit Facility. The guarantees will rank senior in right of payment to all existing and future senior subordinated indebtedness of these subsidiaries and equal in right of payment with all existing and future senior secured indebtedness of these subsidiaries.

Collateral The new notes and the guarantees will be secured by a security interest in substantially all of our, and all of our existing and future domestic subsidiaries’ (other than our existing and future unrestricted subsidiaries’), assets to the extent they constitute collateral under our Amended Revolving Credit Facility, subject to certain exceptions. The lien securing the new notes will be subordinated and junior to liens securing our senior credit facility pursuant to the terms of an intercreditor agreement. See “Description of Notes — Collateral” and “Description of Notes — Intercreditor Agreement.”

Ranking The new notes will be our senior secured obligations. The new notes and the guarantees will rank senior in right of payment to all of our and the guarantors’ future subordinated indebtedness and equal in right of payment with all of our and the guarantors’ existing and future senior indebtedness, including indebtedness under such senior credit facility. However, the new notes and the guarantees will be

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effectively subordinated to indebtedness under such senior credit facility and additional permitted first lien indebtedness to the extent of the value of the collateral securing such senior credit facility and such additional permitted first lien indebtedness.

Optional Redemption Until October 1, 2014, we may redeem up to 35% of the aggregate principal amount of the notes at a price equal to 112.50% of the principal amount, plus accrued and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings. On or after October 1, 2014 until March 31, 2015, we may redeem some or all of the new notes at an initial redemption price equal to par value plus one-half the coupon plus accrued and unpaid interest to the date of redemption. On or after April 1, 2015, we may redeem some or all of the new notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption. We may also redeem some or all of the new notes at any time prior to October 1, 2014 at the “make-whole” prices described in this prospectus and at any time on or after April 1, 2015 at par.

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

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

Certain Indenture Covenants We will issue the new notes under an indenture, dated September 24, 2010, with The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent. The indenture, among other things, limits our ability and the ability of our restricted subsidiaries to:

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

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

• issue capital stock of our subsidiaries;

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

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

• create or incur liens;

• change our line of business;

• enter into certain transactions with affiliates; and

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

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

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

Risk Factors Investing in the new notes involves risks. See “Risk Factors” beginning on page 13 for a discussion of certain factors you should consider in evaluating whether or not to tender your old notes.

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Ratios of Earnings to Fixed Charges

The following table sets forth our ratios of consolidated earnings to fixed charges for the periods presented:

Six Months Ended June 30,

Year Ended December 31,

Pro forma 2011

2011

Pro forma 2010

2010

2009

2008

2007

2006

Ratio of earnings to fixed charges

2.7x

(1)

3.5x

2.7x

(2)

6.2x

11.8x

25.0x

10.5x

7.8x

(1) Adjusted to give effect to a pro forma increase in interest expense resulting from the issuance of the notes on July 15, 2011 as if the issuance of the notes had occurred on January 1, 2011.

(2) Adjusted to give effect to a pro forma increase in interest expense resulting from the issuance of the initially issued notes on September 24, 2010 and the utilization of a portion of the net proceeds from the sale of the notes to repay indebtedness that was outstanding under our revolving credit facility during the year ended December 31, 2010 as if the issuance of the notes had occurred on January 1, 2010.

For purposes of computing the ratio of earnings to fixed charges, “earnings” consists of pretax income from continuing operations plus fixed charges (excluding capitalized interest) and amortization of capitalized interest. “Fixed charges” represents interest incurred (whether expensed or capitalized), amortization of debt expense and that portion of rental expense on operating leases deemed to be the equivalent of interest.

We did not have any preferred stock outstanding and there were no preferred stock dividends paid or accrued during the periods presented above.

Risk Factors

You should carefully consider the information set forth in the section entitled “Risk Factors” beginning on page 13 and all other information in this prospectus.

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Organizational Structure

The following diagram is intended to illustrate our general corporate structure and the basic relationship of our subsidiary guarantors to us.

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SUMMARY HISTORICAL FINANCIAL DATA

The following table presents summary historical financial information for the periods and as of the dates indicated. The summary statement of operations data for the three years ended December 31, 2010, 2009 and 2008 and the balance sheet data as of December 31, 2010, 2009 and 2008 are derived from our audited consolidated financial statements. The summary statement of operations data for the six months ended June 30, 2011 and 2010 and the balance sheet data as of June 30, 2011 are derived from our unaudited condensed consolidated financial statements included in this prospectus. For further information that will help you better understand the summary data, you should read this financial data in conjunction with the “Selected Financial and Other Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections of this prospectus and the financial statements and related notes and other financial information included elsewhere in this prospectus. Our historical results of operations are not necessarily indicative of results to be expected for any future periods.

	Six Months Ended June 30,					Year Ended December 31,
	2011			2010		2010			2009		2008
	(dollars in thousands)
	(unaudited)
Statement of Operations Data:
Gas sales	$	49,424		$	68,587	$	117,176		$	154,519	$	127,747
Oil sales		46,906			42,998		80,632			84,262		78,990
Insurance proceeds		—			—		—			20,207		2,660
Total revenue		96,330			111,585		197,808			258,988		209,397
Operating expenses:
Production and delivery costs		16,352			14,811		31,569			25,831		19,188
Workover costs		1,218			2,067		10,470			8,439		11,444
Depreciation, depletion and amortization		31,066			39,542		71,954			150,423		90,445
General and administrative expenses		9,115			6,391		16,731			20,573		10,418
Derivative (income) expense		(539	)		309		(555	)		136		(1,007	)
Total operating expenses		57,212			63,120		130,169			205,402		130,488
Income from operations	$	39,118		$	48,465	$	67,639		$	53,586	$	78,909
Balance Sheet Data:
Cash and cash equivalents	$	71,221		$	50,302	$	81,032		$	28,888	$	10,052
Oil and gas properties, net		477,006			423,264		436,950			432,913		398,756
Total assets		628,231			557,853		597,286			555,848		634,527
Total debt, including current portion		157,958			110,941		152,653			114,122		128,960
Shareholders’ equity		274,976			285,248		279,907			258,499		266,674

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SUMMARY RESERVE AND OPERATING DATA

The following tables set forth our estimates of our proved reserves and future net cash flows as of December 31, 2010 using SEC pricing based on the average price as of the first day of each of the twelve months ended December 31, 2010. Our reserve estimates as of December 31, 2010 are calculated by adding reserve estimates from reserve reports prepared by each of Netherland, Sewell & Associates, Inc., independent petroleum engineers, and H.J. Gruy and Associates, Inc., independent petroleum engineers. SEC pricing assumptions were as follows: $4.376 per MMBtu for natural gas and $75.96 per Bbl for oil. See “Supplemental Oil and Gas Disclosures.”

	SEC Pricing
	Reserve Category
	PDP			PDNP			PUD			Total
Net proved reserves:
Oil (MBbls)		1,798			2,053			7,587			11,438
Natural gas (MMcf)		24,748			11,169			8,124			44,041
Future net revenues (dollars in thousands):
Oil	$	137,938		$	157,474		$	532,422		$	827,834
Natural gas		117,799			53,290			36,229			207,318
Total revenues		255,737			210,764			568,651			1,035,152
Production costs		(93,022	)		(53,024	)		(100,044	)		(246,090	)
Development and abandonment costs		(22,250	)		(8,326	)		(100,226	)		(130,802	)
Future net cash flows before taxes	$	140,465		$	149,414		$	368,381		$	658,260

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RISK FACTORS

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

Risks Related to the Business

BP’s Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the U.S. Gulf of Mexico, some of which may be unforeseeable.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in ultra deep water in the U.S. Gulf of Mexico. As a result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals by government and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. Beginning in May 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) of the United States Department of the Interior issued a series of Notices to Lessees and Operators (“NTLs”) imposing a variety of new safety measures and permitting requirements, and implementing a moratorium on deep water drilling activities in the U.S. Gulf of Mexico that effectively shut down deep water drilling activities until the moratorium was lifted in October 2010.

In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BOEMRE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the U.S. Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the U.S. Gulf of Mexico more difficult, more time consuming and more costly. For example, during the previous session of Congress, a variety of amendments to the Oil Pollution Act of 1990 (“OPA”) have been proposed in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the Outer Continental Shelf (the “OCS”), which includes the U.S. Gulf of Mexico where we have substantial offshore operations. OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. Legislation was proposed in the previous session of Congress to amend OPA to increase the minimum level of financial responsibility to $300 million or more, and there exists the possibility that similar legislation could be introduced and adopted during the current session of Congress. If OPA is amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located on the OCS or enter into partnerships with other companies that can meet the increased financial responsibility requirement,

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and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased.

Regulatory requirements and permitting procedures recently imposed by BOEMRE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

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

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

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

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

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

As a result of the issuance of these new regulatory requirements, BOEMRE has been taking much longer than in the past to review and approve permits for new wells. These new requirements also increase the cost of preparing each permit application and will increase the cost of each new well, particularly for wells drilled in deeper water on the OCS.

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

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations are many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving and may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

In addition, BOEMRE issued an NTL, effective October 15, 2010, that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease in the U.S. Gulf of Mexico.

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Historically, many oil and natural gas producers in the Gulf of Mexico have delayed the plugging, abandoning or removal of such idle iron until they met the final decommissioning regulatory requirement, which has been established as being within one year after the lease expires or terminates, a time period that sometimes is years after use of the idle iron has been discontinued. The recently issued NTL sets forth new standards that trigger decommissioning timing requirements; any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years time. Plugging or abandonment of wells may be delayed by two years if all of such well’s hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs.

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

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

• domestic and foreign supplies of oil and natural gas;

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

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

• level of consumer product demand;

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

• domestic and foreign governmental regulations;

• level of global oil and natural gas inventories;

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

• weather conditions;

• technological advances affecting oil and natural gas consumption;

• overall United States and global economic conditions; and

• price and availability of alternative fuels.

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

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

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

Our business may suffer if we lose key personnel.

We depend to a large extent on the services of certain key management personnel, including Howard A. Settle, our President, Chief Executive Officer, and Chairman of the Board of Directors, Jonathan B. Rudney, Co-Founder and a member of our Board of Directors, Jeff T. Craycraft, our Treasurer and Chief Financial Officer, Elizabeth A. Barr, our Vice President of Administration, Michael J. Willis, our Chief Operating Officer, and a member of our Board of Directors, and Sheila E. Beck, our Controller. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel.

Lower oil and natural gas prices may cause us to record ceiling test write-downs.

We use the full-cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write down.” This charge does not impact cash flow from operating activities, but does reduce our stockholders’ equity. For example, during 2009, the Company had a write down of approximately $44.7 million to capitalized oil and gas properties primarily as a result of lower natural gas and crude oil pricing assumptions, lower than anticipated success rate on drilling and higher than expected capital expenditures incurred. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write downs may occur if we experience substantial downward adjustments to our estimated proved reserves.

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

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have and may continue to enter into hedging arrangements for a significant portion of our oil and natural gas production. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Our ability to use hedging transactions to protect us from future oil and natural gas price declines will be dependent upon oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to commodity price changes. For example, during 2009, the Company had a write down of approximately $44.7 million to capitalized oil and gas properties primarily as a result of lower natural gas and crude oil pricing assumptions, lower than anticipated success rate on drilling and higher than expected capital expenditures incurred.

Our policy has been to hedge a significant portion of our near–term estimated oil and natural gas production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are

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not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the prior few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Oil and Gas Hedging” of the prospectus, dated April 8, 2011, which forms a part of our Registration Statement on Form S-4, filed on March 17, 2011 for additional information on our oil and gas hedges.

Our hedging transactions expose us to counterparty credit risk.

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

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

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Dodd-Frank Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certainbona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect the Company’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore

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be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on the Company, its financial condition, and its results of operations.

Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or underlying assumptions of our properties will materially affect the quantities and present value of those reserves.

Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized herein. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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

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

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

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

• our proved reserves;

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

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

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

• the ability of our banks to lend.

If our revenues or the borrowing base under our Amended Revolving Credit Facility decrease as a result of lower crude oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by operations or cash available under our Amended Revolving Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our crude oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

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

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

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

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

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

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

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

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

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

• fires;

• explosions;

• blow-outs and surface cratering;

• uncontrollable flows of gas, oil and formation water;

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

• pipe, cement, subsea well or pipeline failures;

• casing collapses;

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

• abnormally pressured formations; and

• environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

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

• injury or loss of life;

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

• pollution and other environmental damage;

• clean-up responsibilities;

• regulatory investigations and penalties;

• suspension of our operations; and

• repairs to resume operations.

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

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

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

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. In offshore operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms that we own or operate or that are owned and operated by others and, where facilities are owned and operated by others, the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut-in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues.

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

We currently operate 100% of our conventional wells, however, as we carry out our planned drilling program, we will not serve as operator of all planned wells. We conduct and will conduct many of our operations through joint ventures in which we share control with other parties. We are not the well operator for several of our joint ventures. There is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with those of the project or us. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

• the timing and amount of capital expenditures;

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

• the operator’s expertise and financial resources;

• approval of other participants in drilling wells;

• selection of technology; and

• the rate of production of the reserves.

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

We do not maintain insurance for all of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Therefore, we will not be fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. As a result of a number of recent catastrophic events like the terrorist attacks on September 11, 2001 and Hurricanes Katrina, Rita, Gustav

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

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

Crude oil and natural gas exploration and production operations in the United States and the Gulf of Mexico are subject to extensive federal, regional, state and local laws and regulations. Companies operating onshore and in the Gulf of Mexico are subject to laws and regulations (i) addressing, among other items, land use and lease permit restrictions, bonding and other financial assurance related to drilling and production activities, spacing of wells, unitization and pooling of properties, plugging and abandonment of wells and associated infrastructure after production has ceased, operational reporting and taxation, and environmental and health and safety matters, and (ii) that impose liability for, and require investigation and remediation of, releases of hazardous or other regulated substances, including at third-party owned off-site disposal facilities, and could expose us to significant expenses and damages, including natural resource damages, and fines, penalties and expenses for any violation or non-compliance with any of the applicable laws or regulations.

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

Our oil and gas exploration, development and production operations are also subject to stringent laws and regulations governing the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

• require the acquisition of a permit before drilling or other regulated activity commences;

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

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

• impose substantial liabilities for pollution resulting from operations; and

• require decommissioning or plugging abandoned platforms and wells.

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These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

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

• BOEMRE regulations that impose environmental and safety-related requirements relating to offshore oil and natural gas operations in U.S. waters and impose liability for violations of these requirements;

• the Clean Air Act (“CAA”) and comparable state laws and regulations that impose obligations related to air emissions;

• the Federal Water Pollution Control Act (the “Clean Water Act”) and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

• the Resource Conservation and Recovery Act (“RCRA”), and comparable state laws that impose requirements for the handling and disposal of waste from our facilities;

• the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal;

• the Federal Safe Drinking Water Act (“SWDA”) and comparable state laws that regulate underground injection operations; and

• the Environmental Protection Agency (“EPA”) community right to know regulations under the Title III of CERCLA and similar state statutes that require we organize and/or disclose information about hazardous materials used or produced in our operations.

Failure to comply with these laws and regulations or the terms or conditions of required environmental permits may result in the assessment of administrative, civil and/or criminal penalties; the imposition of investigatory, remedial or corrective action obligations; and the issuance of injunctions or orders limiting or prohibiting some or all of our operations.

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

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbon and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical operations and waste disposal practices. Under certain environmental laws and regulations that impose strict, joint and several liability, we may be required to remediate contamination on our 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 and regulations at the time those actions were taken. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of our operations. In addition, future spills or releases of regulated substances or accidents or the discovery of currently unknown contamination could expose us to

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material losses, expenditures and environmental or health and safety liabilities, including liabilities resulting from lawsuits brought by private litigants or neighboring property owners or operators for personal injury or property damage related to our operations or the land on which our operations are conducted. We may not be able to recover some or any of these costs from insurance. See “Business — Environmental Matters and Regulation” of the prospectus.

We may experience difficulty in achieving and managing future growth.

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

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

• our ability to acquire additional 3-D seismic data;

• our ability to identify and acquire new exploratory prospects;

• our ability to develop existing prospects;

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

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

• the results of our drilling program;

• hydrocarbon prices; and

• our access to capital.

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

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

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA has adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution activities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

Certain of our oil and natural gas operations may be subject to such greenhouse gas reporting. While we believe that we will be able to substantially comply with such reporting requirements without any material adverse effect to our financial condition, since such reporting requirements with respect to greenhouse gas emissions are new in the oil and gas industry, there can be no assurance that such requirements will not develop into more stringent and costly obligations that may have a significant impact on our operating costs.

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In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

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

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could make it more difficult or costly for us to perform fracturing of producing formations and could have an adverse effect on our ability to produce oil and gas from new wells.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions or other similar state agencies. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents on regulating requirements for companies that plan to conduct hydraulic fracturing using diesel. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing a number of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy and the U.S. Government Accountability Office are studying different aspects of how hydraulic fracturing might adversely affect the environment, and the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. A committee of the United States House of Representatives also has conducted an investigation of hydraulic fracturing practices. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or under newly established legislation. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states, including Texas, have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Texas passed a law that requires, subject to certain trade secret protections, disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. Louisiana is considering adoption of a regulation that would impose similar disclosure requirements. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our

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reserves. In addition, disclosure requirements could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water.

Recently proposed rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

Approximately 48% of our total estimated proved reserves at December 31, 2010 were classified as proved undeveloped and may ultimately prove to be less than estimated.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. At December 31, 2010, approximately 48% of our total estimated proved reserves were undeveloped. The future development of these undeveloped reserves into proved developed reserves is highly dependent upon our ability to fund estimated total capital development costs as shown in our reserve report of approximately $100.2 million, of which $1.5 million, $36.3 million and $3.0 million are expected to be incurred in 2011, 2012 and 2013, respectively. We cannot be sure that these estimated costs are accurate. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations. For a more detailed discussion of our current liquidity, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” of the prospectus.

In addition, one of our offshore federal leases, designated as the Flatts’ Guitar prospect, is located in the deep waters of the Gulf of Mexico. This lease accounts for 87% of our proved undeveloped reserves at December 31, 2010 and remains to be drilled or developed. We are unsure what long-term effect, if any, the BOEMRE’s new regulatory requirements and permitting procedures will have on this lease or our other offshore operations. We are also unsure what effect, if any, amendments to OPA will have on this lease and our other offshore operations. However, it is possible that due to changes in regulation we will be unable to develop our proved undeveloped reserves.

Our estimates of proved reserves have been prepared under new SEC rules, which went into effect for fiscal years ending on or after December 31, 2009, and may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.

This prospectus includes estimates of our proved reserves as of December 31, 2010, which have been prepared and presented under new SEC rules. These new rules are effective for fiscal years ending on or after December 31, 2009, and require companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. The previous rules required that reserve estimates be calculated using year-end pricing. Under the new rules the pricing that was

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used for estimates of our reserves as of December 31, 2010 was based on an unweighted average 12-month West Texas Intermediate posted price of $75.96 per Bbl for oil and a Henry Hub spot price of $4.376 per MMBtu for natural gas. As a result of these changes, direct comparisons to our prior period reserves amounts may be more difficult.

Another impact of the new SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our future proved undeveloped reserves if we do not drill and develop those reserves within the required five-year timeframe.

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

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. For the years prior to 2009, we based the estimated discounted future net revenues from our proved reserves on prices and costs in effect on the day of the estimate. In accordance with new SEC requirements, we currently base the estimated discounted future net revenues from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

• actual prices we receive for crude oil and natural gas;

• actual cost of development and production expenditures;

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

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

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

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

We plan to pursue acquisitions as part of our growth strategy and there are risks in connection with acquisitions.

Our growth has been attributable in part to acquisitions of producing properties and companies. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.

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The successful acquisition of producing properties requires an assessment of numerous factors beyond our control, including, without limitation:

• recoverable reserves;

• exploration potential;

• future oil and natural gas prices;

• operating costs; and

• potential environmental and other liabilities.

In connection with such an assessment, we perform a review of the subject properties. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made. Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are focused in the federal and state waters of the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas, California, and New Mexico, we may pursue acquisitions or properties located in other geographic areas.

We are dependent upon a small number of customers for a large portion of our net revenues, and a decline in sales to our major customers could harm our results of operations.

During 2010, 2009 and 2008, our four largest customers accounted for approximately 86%, 95% and 94%, respectively, of our natural gas and oil revenues, and our largest customer accounted for approximately 45%, 45% and 39%, respectively, of our oil and natural gas revenues. Our customer concentration could increase or decrease depending on future customer requirements, which will depend in large part on business conditions in the market in which our customers participate. The loss of one or more major customers or a decline in sales to one of our major customers could significantly harm our results of operations. If we are not able to expand our customer base, we will continue to depend upon a small number of customers for the majority our sales. There can be no assurance that our current customers will not reduce the amount of quantity of our oil and natural gas they purchase.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama’s proposed Fiscal Year 2012 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination or postponement of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to: (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could have an adverse effect on our financial condition and results of operations.

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Risks Related to the Notes

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

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

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

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

The old notes have not been registered under the Securities Act, and may not be resold by purchasers thereof unless the old notes are subsequently registered or an exemption from the registration requirements of the Securities Act is available. However, we cannot assure you that, even following registration or exchange of the old notes for new notes, that an active trading market for the old notes or the new notes will exist, and we will have no obligation to create such a market. At the time of the private placement of the old notes, the initial purchasers advised us that they intended to make a market in the old notes and, if issued, the new notes. The initial purchasers are not obligated, however, to make a market in the old notes or the new notes and any market-making may be discontinued at any time at their sole discretion. No assurance can be given as to the liquidity of or trading market for the old notes or the new notes.

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

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

As of June 30, 2011, we had no indebtedness outstanding under our Amended Revolving Credit Facility. However, any future substantial indebtedness we may incur could have important consequences to you. For example, it could:

• make it more difficult for us to satisfy our obligations with respect to the notes;

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

• make it more difficult for us to satisfy our financial obligations, including with respect to the notes;

• restrict us from making strategic acquisitions or cause us to make non-strategic divestitures;

• require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes;

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

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• place us at a competitive disadvantage compared to our competitors that have less debt; and

• limit our ability to borrow additional funds.

In addition, the terms of the indenture governing the notes and our Amended Revolving Credit Facility contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of our debts.

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

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

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets and our ability to make payments on the notes is therefore dependent upon the performance of our subsidiaries.

We are a holding company and conduct all of our operations through our subsidiaries. All of our operating income is generated by our operating subsidiaries. We must rely on dividends and other advances and transfers of funds from our subsidiaries, and earnings from our investments in cash and marketable securities, to provide the funds necessary to meet our debt service obligations, including payment of principal and interest on the notes. Although we are the sole stockholder, directly or indirectly, of each of our operating subsidiaries and, therefore, able to control their respective declarations of dividends, applicable laws may prevent our operating subsidiaries from being able to pay such dividends. In addition, such payments may be restricted by claims against our subsidiaries by their creditors, such as suppliers, vendors, lessors, and employees, and by any applicable bankruptcy, reorganization, or similar laws applicable to our operating subsidiaries. The availability of funds, and therefore the ability of our operating subsidiaries to pay dividends or make other payments or advances to us, will depend upon their operating results.

Our Chairman, President and Chief Executive Officer and a member of our Board collectively own approximately 52.6% of our outstanding common stock, giving them influence and control in corporate transactions and other matters, which may conflict with noteholders’ interests.

As of June 30, 2011, Howard A. Settle, our Chairman, President and Chief Executive Officer, beneficially owned 23,782.16 shares of our outstanding common stock representing approximately 39.6% of our outstanding common shares and Jonathan B. Rudney, a member of our Board, owned 7,800.35 shares of our outstanding common stock representing approximately 13.0% of our outstanding common shares. As a result, Messrs. Settle and Rudney have the ability to control the election of our directors, determine our corporate and management policies, determine our financing arrangements, control the payment of dividends, and determine the outcome of certain corporate transactions or other matters submitted to our shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. As controlling shareholders, Messrs. Settle and Rudney could make decisions that conflict with noteholders’ interests.

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

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

• refinancing or restructuring our debt;

• selling assets; or

• seeking to raise additional capital.

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

The covenants in the indenture governing the notes and our Amended Revolving Credit Facility could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under the notes.

The covenants contained in the indenture governing the notes and our Amended Revolving Credit Facility could have important consequences for our operations, including:

• making it more difficult for us to satisfy our obligations under the notes or other indebtedness and increasing the risk that we may default on our debt obligations;

• requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

• limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;

• limiting management’s discretion in operating our business;

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

• limiting our ability to hedge our production;

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

• placing us at a competitive disadvantage against less leveraged competitors; and

• making us vulnerable to increases in interest rates, because debt under our Amended Revolving Credit Facility may vary with prevailing interest rates.

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

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

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

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

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

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

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

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

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

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

The rights of the holders of the notes with respect to the collateral securing the notes will be limited pursuant to the terms of the security documents relating to the notes, the intercreditor agreement and the indenture governing the notes. Under the terms of those agreements, the holders of the notes will have a second priority lien, subject to certain permitted liens and encumbrances described in the security documents relating to the notes, on all of the collateral that secures the obligations under our Amended Revolving Credit Facility and other permitted first lien indebtedness. The second priority liens securing the notes may also secure additional notes on an equal and ratable basis. Accordingly, any proceeds received upon a realization of the collateral securing the notes will be applied first to amounts due under our Amended Revolving Credit Facility and other permitted first lien indebtedness before any amounts will be available to pay the holders of the notes. Under the terms of the indenture governing the notes, we are permitted to incur first lien indebtedness in amounts in excess of the current commitments under our Amended Revolving Credit Facility, all of which can be secured by the collateral on a first-priority lien basis and which will be entitled to payment out of the proceeds of any sale of such collateral before the holders of the notes are entitled to any recovery from such collateral.

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

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

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

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

Under the terms of the intercreditor agreement, that was entered into between the collateral agent for the notes and the agent under our Amended Revolving Credit Facility, at any time that obligations that have the benefit of the first-priority liens on the collateral securing the notes are outstanding, any action that may be taken by the collateral agent with respect to the collateral securing the notes, including the ability to cause the commencement of enforcement proceedings against the collateral and to control the conduct of such proceedings, will be significantly restricted. Under the terms of the intercreditor agreement, the collateral agent for the notes may exercise rights and remedies with respect to the collateral only after the passage of 180 days after notification from the collateral agent for the notes to the agent under the Amended Revolving Credit Facility that

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either (i) the obligations with respect to the notes have become due in full as a result of acceleration or otherwise (and such acceleration has not been rescinded) or (ii) any payment or insolvency event of default has occurred and is then continuing under the indenture or the other documents executed in connection therewith. After the passage of such period, the collateral agent for the notes will only be only permitted to exercise remedies to the extent that the First Lien Collateral Agent or any other first lien creditor is not diligently pursuing an enforcement action with respect to all or a material portion of the collateral or diligently attempting to vacate any stay or prohibition against such exercise.

The intercreditor agreement provides that, at any time that obligations that have the benefit of the first-priority liens on the collateral are outstanding, the collateral agent for the notes may not assert any right of marshalling that may be available under applicable law with respect to the collateral. Without this waiver of the right of marshalling, holders of indebtedness secured by first-priority liens in the collateral would likely be required to liquidate collateral on which the notes did not have a lien, if any, prior to liquidating the collateral securing the notes, thereby maximizing the proceeds of the collateral that would be available to repay obligations under the notes. As a result of this waiver, the proceeds of sales of the collateral securing the notes could be applied to repay any indebtedness secured by first priority liens in such collateral before applying proceeds of other collateral securing indebtedness, and the holders of notes may recover less than they would have if such proceeds were applied in the order most favorable to the holders of the notes.

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

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

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

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

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

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

We may be permitted to incur additional notes under the indenture secured by liens on the collateral. The value of your rights to the collateral would be reduced by any increase in the indebtedness secured by the collateral. The value of the collateral and the amount to be received upon a sale of such collateral will depend upon many factors including, among others, the condition of the collateral and the oil and gas development and

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exploration industry, the ability to sell the collateral in an orderly sale, the condition of the international, national and local economies, the availability of buyers and similar factors. No appraisal has been obtained in respect of the collateral in connection with this offering and you should not rely upon the book value of the collateral as a measure of realizable value for such assets. By their nature, portions of the collateral may be illiquid and may have no readily ascertainable market value. In addition, a significant portion of the collateral includes assets that may only be usable, and thus retain value, as part of our existing operating businesses.

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

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

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

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

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

Other consequences of a finding of under-collateralization would be, among other things, a lack of entitlement on the part of the holders of the notes to receive post-petition interest and a lack of entitlement on the part of the unsecured portion of the notes to receive other “adequate protection” under federal bankruptcy laws.

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In addition, if any payments of post-petition interest had been made at the time of such a finding of undercollateralization, those payments could be recharacterized by the bankruptcy court as a reduction of the principal amount of the secured claim with respect to the notes.

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

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

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

The collateral securing the notes and the guarantees includes substantially all of our and the guarantors’ tangible and intangible assets that secure our indebtedness under our senior credit facility, whether now owned or acquired or arising in the future. If additional subsidiaries are formed or acquired that are required to guarantee the notes pursuant to the terms of the indenture, additional financing statements or their foreign equivalents would be required to be filed to perfect the security interest in the assets of such subsidiaries. Depending on the type of the assets constituting after-acquired collateral, additional action may be required to be taken by the collateral agent for the notes, or the collateral agent for our senior credit facility, to perfect the security interest in such assets, such as the delivery of physical collateral, the execution of account control agreements or the execution and recordation of mortgages or deeds of trust. Applicable law requires that certain property and rights acquired after the grant of a general security interest can only be perfected at the time such property and rights are acquired and identified. There can be no assurance that the trustee or the collateral agent will monitor, or that we will inform the trustee or the collateral agent of, the future acquisition of property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after acquired collateral. The collateral agent for the notes and the collateral agent for our senior credit facility have no obligation to monitor the acquisition of additional property or rights that constitute collateral or the perfection of any security interests therein. Such failure may result in the loss of the security interest therein or the priority of the security interest in favor of the notes and the guarantees against third parties.

Security over certain collateral will not be in place upon the date of issuance of the notes offered hereby or will not be perfected on such date.

We expect the execution or amendment and recordation of certain mortgages or deeds of trust relating to our oil and gas properties, which are necessary to increase the amount of indebtedness under the notes from $150 million to $200.0 million as a result of this offering, will not be perfected on or prior to the date of issuance of the additional $50.0 million in notes offered hereby. To the extent any security interest, including the security interest in our oil and gas properties, cannot be perfected by filing, delivery or execution and recordation on the date of issuance of the notes, we will be required to have all security interests that are required by the security documents to be in place perfected as soon as practicable following July 15, 2011, but in any event no later than a 90 days after such date, or such later date as the administrative agent under our Amended Revolving Credit Facility agrees the corresponding security interests and liens in favor of the obligations under such credit facility are in place. Security interests in the collateral securing the notes and the guarantees that require additional steps for perfection will not be perfected or may not have priority with respect to the security interests in the collateral securing the notes and the subsidiary guarantees. To the extent a security interest in certain collateral is perfected following the date of issuance of the notes, it might be voidable by a trustee in bankruptcy.

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The collateral is subject to casualty risks.

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

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

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

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

An adverse rating of the notes may cause their trading price to fall.

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

We may not be able to repurchase the notes upon a change of control.

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

• sales of assets; or

• sales of unregistered equity, if possible at acceptable terms.

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

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

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EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

At the closing of the offering of the old notes, we entered into a registration rights agreement with the initial purchasers pursuant to which we agreed, for the benefit of the holders of the old notes, at our cost, to do the following:

• file a registration statement with the SEC with respect to the exchange offer for the new notes by January 11, 2012, and

• use our reasonable best efforts to cause the registration statement to become effective by April 10, 2012 and to complete the exchange offer after the registration becomes effective.

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

For each old note surrendered to us pursuant to the exchange offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the last interest payment date on which interest was paid on the surrendered old note, October 1, 2011, and from the most recent interest payment date for each interest payment date on the new notes thereafter. The registration rights agreement also provides an agreement to include in the prospectus for the exchange offer certain information necessary to allow a broker-dealer who holds old notes that were acquired for its own account as a result of market-making activities or other ordinary course trading activities (other than old notes acquired directly from us or one of our affiliates) to exchange such old notes pursuant to the exchange offer and to satisfy the prospectus delivery requirements in connection with resales of new notes received by such broker-dealer in the exchange offer. We agreed to use commercially reasonable efforts to maintain the effectiveness of the exchange offer registration statement for these purposes for a period of 180 days after the completion of the exchange offer, which period may be extended under certain circumstances.

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

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

• will not be able to rely on the interpretation of the staff of the SEC,

• will not be able to tender its new notes in the exchange offer, and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the old notes unless such sale or transfer is made pursuant to an exemption from such requirements.

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

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Pursuant to a registration rights agreement, we further agreed to file with the SEC a shelf registration statement to register for public resale old notes held by any holders of old notes under certain circumstances. For a description of our registration rights agreement, please see “Description of Notes — Registration Rights; Additional Interest.”

Terms of the Exchange Offer

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

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

As of the date of this prospectus, $50,000,000 in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

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

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

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

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

Expiration Date

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

Extensions, Delays in Acceptance, Termination or Amendment

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

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

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

• to delay accepting for exchange any old notes,

• to extend the exchange offer, or

• to terminate the exchange offer,

by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

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

Conditions to the Exchange Offer

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

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

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

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

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

Procedures for Tendering

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

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There is no procedure for guaranteed late delivery of the notes.

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

All of the old notes that are eligible for tender were issued in book-entry form and are represented by global certificates held for the account of DTC. We have confirmed with DTC that these old notes may be tendered using the Automated Tender Offer Program (“ATOP”) instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

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

Determinations Under the Exchange Offer

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

When We Will Issue New Notes

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

• a book-entry confirmation of such old notes into the exchange agent’s account at DTC; and

• a properly transmitted agent’s message.

Return of Old Notes Not Accepted or Exchanged

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

Your Representations to Us

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

• any new notes that you receive will be acquired in the ordinary course of your business;

• you have no arrangement or understanding with any person or entity to participate in the distribution of the new notes;

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• you are not our “affiliate,” as defined in Rule 405 of the Securities Act or, if you are an affiliate, you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable; and

• if you are a broker-dealer that will receive new notes for your own account in exchange for old notes, you acquired those notes as a result of market-making activities or other trading activities and you will deliver a prospectus (or to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

Withdrawal of Tenders

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

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

Any old notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under “— Procedures for Tendering” above at any time prior to 5:00 p.m., New York City time, on the expiration date.

Fees and Expenses

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

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

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

• all registration and filing fees and expenses;

• all fees and expenses of compliance with federal securities and state “blue sky” or securities laws;

• accounting and legal fees, disbursements and printing, messenger and delivery services, and telephone costs; and

• related fees and expenses.

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.

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Consequences of Failure to Exchange

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

Accounting Treatment

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

Other

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

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

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RATIOS OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratios of consolidated earnings to fixed charges for the periods presented:

Six Months Ended June 30,

Year Ended December 31,

Pro forma 2011

2011

Pro forma 2010

2010

2009

2008

2007

2006

Ratio of earnings to fixed charges

2.7x

(1)

3.5x

2.7x

(2)

6.2x

11.8x

25.0x

10.5x

7.8x

(1) Adjusted to give effect to a pro forma increase in interest expense resulting from the issuance of the notes on July 15, 2011 as if the issuance of the notes had occurred on January 1, 2011.

(2) Adjusted to give effect to a pro forma increase in interest expense resulting from the issuance of the initially issued notes on September 24, 2010 and the utilization of a portion of the net proceeds from the sale of the notes to repay indebtedness that was outstanding under our revolving credit facility during the year ended December 31, 2010 as if the issuance of the notes had occurred on January 1, 2010.

For purposes of computing the ratio of earnings to fixed charges, “earnings” consists of pretax income from continuing operations plus fixed charges (excluding capitalized interest) and amortization of capitalized interest. “Fixed charges” represents interest incurred (whether expensed or capitalized), amortization of debt expense and that portion of rental expense on operating leases deemed to be the equivalent of interest.

We did not have any preferred stock outstanding and there were no preferred stock dividends paid or accrued during the periods presented above.

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USE OF PROCEEDS

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

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SUPPLEMENTAL OIL AND GAS DISCLOSURES

December 31, 2010

The following table sets forth certain unaudited information concerning our proved oil and natural gas reserves as of December 31, 2010. There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. See “Risk Factors — Risks Related to Our Business.” Reserve estimates depend on many assumptions that may turn out to be inaccurate.

Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantity and present values of our reserves. All of the reserves are located in the United States.

Proved Reserves

	Oil Reserves (MBbls)
Balance, December 31, 2009		11,750
Production		(1,066	)
Purchases of reserves in-place		—
Extensions, discoveries and improved recovery		473
Transfers/sales of reserves in-place		—
Revisions of previous estimates		281
Balance, December 31, 2010		11,438

	Natural Gas Reserves (MMcf)
Balance, December 31, 2009		50,724
Production		(16,172	)
Purchases of reserves in-place		—
Extensions, discoveries and improved recovery		6,159
Transfers/sales of reserves in-place		—
Revisions of previous estimates		3,330
Balance, December 31, 2010		44,041

	Total Oil Equivalent (MBoe)
Balance, December 31, 2009		20,204
Production		(3,761	)
Purchases of reserves in-place		—
Extensions, discoveries and improved recovery		1,500
Transfers/sales of reserves in-place		—
Revisions of previous estimates		836
Balance, December 31, 2010		18,779

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Standardized Measure of Discounted Future Pre-Tax Net Cash Flow

The standardized measure of discounted future net cash flow from estimated proved reserves is provided as a common base for comparing oil and natural gas reserves of enterprises in the industry and may not represent the fair market value of the oil and natural gas reserves or the present value of future cash flow of equivalent reserves due to various uncertainties inherent in making these estimates. Those factors include changes in oil and natural gas prices from prices used in the estimates, unanticipated changes in future production and development costs and other uncertainties in estimating quantities and present values of oil and natural gas reserves.

The following table presents the standardized measure of discounted future pre-tax net cash flow from the ownership interest in proved oil and natural gas reserves as of December 31, 2010. The standardized measure of future pre-tax net cash flow as of December 31, 2010 is calculated based on average prices as of the first day of each of the twelve months ended December 31, 2010 at $75.96 per Bbl for oil and $4.376 per MMBtu for natural gas. The resulting estimated future pre-tax cash flow is reduced by estimated future costs to produce the estimated proved reserves based on actual operating cost levels at December 31, 2010. The future pre-tax cash flow is reduced to present value by applying a 10% discount rate.

The standardized measure of estimated discounted future pre-tax cash flow is not intended to represent the replacement cost or fair market value of the oil and natural gas properties.

	At December 31, 2010
	(dollars in thousands)
Future pre-tax cash flow	$	1,035,152
Future production costs		(246,090	)
Future development costs		(130,802	)
Future pre-tax net cash flow	$	658,260
Future income taxes		(196,810	)
Effect of discounting future annual net cash flow at 10%		(190,401	)
Discounted future net cash flow	$	271,049

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SELECTED FINANCIAL AND OTHER DATA

The following table presents our summary consolidated historical financial data for the periods and as of the dates indicated. The statement of operations data and the statement of cash flow data for the years ended December 31, 2010, 2009, 2008, 2007 and 2006 and the balance sheet data as of December 31, 2010, 2009, 2008, 2007 and 2006 are derived from our audited consolidated financial statements. Please see Note 5 to our audited consolidated financial statements for a discussion of a change in accounting principle related to reserve estimation. The statement of operations data and statement of cash flow data for the six months ended June 30, 2011 and 2010 and the balance sheet data as of June 30, 2011 and 2010 are derived from our unaudited condensed consolidated financial statements included in this prospectus. For further information that will help you better understand the summary data, you should read this financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes and other financial information included elsewhere in this prospectus. These historical results are not necessarily indicative of results to be expected for any future periods.

	Six Months Ended June 30,						Year Ended December 31,
	2011			2010			2010			2009			2008			2007			2006
	(unaudited)
	(dollars in thousands)
Statement of Operations Data:
Revenues
Gas sales	$	49,424		$	68,587		$	117,176		$	154,519		$	127,747		$	110,887		$	69,226
Oil sales		46,906			42,998			80,632			84,262			78,990			62,669			35,732
Insurance proceeds		—			—			—			20,207			2,660			—			11,800
Total revenues		96,330			111,585			197,808			258,988			209,397			173,556			116,758
Operating expenses:
Production and delivery costs		16,352			14,811			31,569			25,831			19,188			15,510			14,531
Workover costs		1,218			2,067			10,470			8,439			11,444			12,552			3,980
Depreciation, depletion and amortization		31,066			39,542			71,954			150,423			90,445			58,306			43,504
General and administrative expenses		8,345			6,391			16,633			18,119			10,418			10,432			23,863
Bad debt expense		770			—			98			2,454			—			20,162			—
Derivative (income) expense		(539	)		309			(555	)		136			(1,007	)		(581	)		29
Total operating expenses		57,212			63,120			130,169			205,402			130,488			116,381			85,907
Income from operations		39,118			48,465			67,639			53,586			78,909			57,175			30,851
Other income (expenses):
Interest income		114			93			276			363			762			1,115			844
Interest expense		(6,462	)		(1,731	)		(9,057	)		(4,349	)		(2,488	)		(1,261	)		(1,254	)
Gain on sale of oil and gas properties		—			—			—			—			48,208			—			—
Unrealized gain (loss) on interest rate swap		—			—			—			—			—			—			85
Unrealized gain (loss) on hedging		—			—			—			—			—			—			538
Income (loss) on equity investment		—			—			(5,156	)		492			(7,561	)		(2,576	)		(424	)
Loss on sale of equipment inventory		(20	)		—			(1,463	)		(1,257	)		—			—			—
Other income (expense)		201			536			434			861			469			197			28
Total other income (expenses)		(6,167	)		(1,102	)		(14,966	)		(3,890	)		39,390			(2,525	)		(183	)
Income before taxes		32,951			47,363			52,673			49,696			118,299			54,650			30,668
Income tax provision		12,010			17,214			13,440			23,995			44,585			19,515			10,733
Net income including non-controlling interest		20,941			30,149			39,233			25,701			73,714			35,135			19,935
Net income attributable to non-controlling interest		1,476			946			1,682			715			1,442			—			—
Net income attributable to RAAM Global	$	19,465		$	29,203		$	37,551		$	24,986		$	72,272		$	35,135		$	19,935
Statement of Cash Flows Data:
Capital expenditures	$	86,845		$	28,972		$	86,936		$	137,794		$	193,350		$	121,720		$	94,006
Cash flow provided by (used in):
Operating activities		71,694			57,105			114,209			185,505			122,401			140,176			57,004
Investing activities		(83,811	)		(29,814	)		(87,838	)		(142,334	)		(191,522	)		(126,271	)		(90,143	)
Financing activities		2,306			(5,877	)		25,773			(22,335	)		45,302			169			30,441
Balance Sheet Data (at period end):
Cash and cash equivalents	$	71,221		$	50,302		$	81,032		$	28,888		$	10,052		$	33,889		$	19,797
Oil and gas properties, net		477,006			423,264			436,950			432,913			398,756			299,974			235,150
Total assets		628,231			557,853			597,286			555,848			634,527			410,476			337,778
Total debt, including current portion		157,958			110,941			152,653			114,122			128,960			78,283			73,374
Total shareholders’ equity		274,976			285,248			279,907			258,499			266,674			145,698			120,393

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview

We are a privately held oil and natural gas exploration and production company engaged in the exploration, development, production and acquisition of oil and gas properties. Our operations are located in the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas, Oklahoma, California and New Mexico. We focus on the development of both conventional and unconventional resource plays. Historically, we have successfully developed conventional oil and gas plays in the offshore Gulf of Mexico and onshore Texas and Louisiana. More recently, we have redirected our focus to the acquisition and development of acreage in the shallow oil, tight gas sand and oil shale plays throughout the United States. Since 2007, we have targeted unconventional shallow oil, tight gas sand and oil shale plays in Oklahoma, California, and New Mexico and have obtained large land positions in these plays.

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

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

The primary factors affecting our production levels are capital availability, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline primarily through drilling our existing undeveloped reserves. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely

49

obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

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

How We Evaluate Our Operations

We use a variety of financial and operational measures to assess our performance. Among these measures are (1) volumes of crude oil and natural gas produced, (2) crude oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) EBITDA. The following table contains financial and operational data for the three and six months ended June 30, 2011 and 2010 and for each of the three years ended December 31, 2010, 2009 and 2008.

	Three Months Ended June 30,				Six Months Ended June 30,				Year Ended December 31,
	2011		2010		2011		2010		2010		2009		2008
Average daily production:
Oil (Bbl per day)		2,860		3,069		2,691		3,227		2,920		2,898		2,262
Natural gas (Mcf per day)		45,815		47,828		44,413		48,073		44,308		50,112		40,550
Oil equivalents (Boe per day)		10,496		11,041		10,093		11,239		10,305		11,250		9,020
Average prices:(1)
Oil ($/Bbl)	$	98.92	$	75.37	$	96.29	$	73.63	$	75.66	$	79.66	$	95.67
Natural gas ($/Mcf)	$	6.02	$	7.77	$	6.15	$	7.88	$	7.25	$	8.45	$	8.63
Oil equivalents ($/Boe)	$	53.25	$	54.62	$	52.73	$	54.85	$	52.59	$	58.15	$	62.79
Production expense ($/Boe)	$	9.31	$	6.89	$	8.95	$	7.28	$	8.39	$	6.29	$	5.83
General and administrative expense ($/Boe)	$	4.15	$	3.24	$	4.57	$	3.14	$	4.42	$	4.41	$	3.16
Net income (in thousands)	$	9,472	$	18,026	$	19,465	$	29,203	$	37,551	$	24,986	$	72,272
EBITDA(2) (in thousands)	$	35,779	$	43,372	$	69,003	$	87,690	$	132,002	$	203,753	$	209,790

(1) Average prices presented give effect to our hedging. Please see “— Oil and Gas Hedging” for a discussion of our hedging activities.

(2) EBITDA as used herein represents net income before interest expense, income taxes, depreciation, depletion and amortization. We present EBITDA because some investors believe it is an important supplemental measure of our performance, frequently used in evaluating companies in our industry. EBITDA is not a measurement of our financial performance under accounting principles generally accepted in the United States (“GAAP”) and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. EBITDA has significant limitations, including that it does not reflect our cash requirements for capital expenditures, contractual commitments, working capital or debt service. In addition, other companies may calculate EBITDA differently than we do, limiting their usefulness as comparative measures.

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The following table sets forth a reconciliation of net income as determined in accordance with GAAP to EBITDA for the periods indicated.

	Three Months Ended June 30,				Six Months Ended June 30,				Year Ended December 31,
	2011		2010		2011		2010		2010		2009		2008
	(dollars in thousands)
Net income	$	9,472	$	18,026	$	19,465	$	29,203	$	37,551	$	24,986	$	72,272
Interest expense		3,026		963		6,462		1,731		9,057		4,349		2,488
Depreciation, depletion and amortization		13,927		13,842		31,066		39,542		71,954		150,423		90,445
Income taxes		9,354		10,541		12,010		17,214		13,440		23,995		44,585
EBITDA	$	35,779	$	43,372	$	69,003	$	87,690	$	132,002	$	203,753	$	209,790

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

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

Depreciation, depletion and amortization. All capitalized costs of oil and gas properties are amortized through depreciation, depletion and amortization (“DD&A”) using the future gross revenue method whereby the annual provision is computed by dividing revenue earned during the period by future gross revenues at the beginning of the period, and applying the resulting rate to the cost of oil and gas properties, including estimated future development and abandonment costs. Investments in unproved properties and major development projects are not amortized until proved reserves are attributed to the projects or until impairment occurs. If the results of an assessment indicate that the properties are impaired, that portion of such costs is added to the capitalized costs to be amortized. Capitalized oil and gas property costs are subject to a “ceiling test,” which limits such costs to the aggregate of the estimated present value, discounted at 10%, of future net cash flows from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects. If a write down occurs, it is recorded within this category of the income statement for the period.

General and administrative expenses. General and administrative expenses include payroll and benefits for our corporate staff, costs of maintaining our headquarters, certain data processing charges, property taxes, audit and other professional fees and legal compliance.

Derivative (income) expense. Any hedge ineffectiveness (which represents the amount by which the change in fair value of the derivative exceeds the change in cash flows of the forecasted transaction) is recorded in current-period earnings in the income statement as derivative (losses) gains. Hedge ineffectiveness of actual monthly settlements is also recorded as derivative (losses) gains in the income statement. Hedge effectiveness of actual monthly settlements is recorded as a component of natural gas and oil sales. In general, where prices of underlying commodities rise during a period we recognize commodity derivative loss and where prices of underlying commodities decrease during a period we recognize commodity derivative gain.

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

Income tax provision. We follow FASB accounting guidance related to income taxes. The asset and liability method prescribed by FASB guidance requires recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the tax bases and financial reporting bases of assets and liabilities. Our income tax provision consists of both (a) current federal and state income tax expenses and (b) deferred federal and state income tax expenses.

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Results of Operations

The following table sets forth the unaudited results of operations for the three and six months ended June 30, 2011 and 2010 and the audited results of operations for the years ended December 31, 2010, 2009 and 2008.

	Three Months Ended June 30,						Six Months Ended June 30,						Year Ended December 31,
	2011			2010			2011			2010			2010			2009			2008
	(unaudited)
	(dollars in thousands)
Revenues
Gas sales	$	25,110		$	33,828		$	49,424		$	68,587		$	117,176		$	154,519		$	127,747
Oil sales		25,747			21,052			46,906			42,998			80,632			84,262			78,990
Insurance proceeds		—			—			—			—			—			20,207			2,660
Total revenues		50,857			54,880			96,330			111,585			197,808			258,988			209,397
Operating expenses:
Production and delivery costs		8,890			6,923			16,352			14,811			31,569			25,831			19,188
Workover costs		786			777			1,218			2,067			10,470			8,439			11,444
Depreciation, depletion and amortization		13,927			13,842			31,066			39,542			71,954			150,423			90,445
General and administrative expenses		3,966			3,253			8,345			6,391			16,633			18,119			10,418
Bad debt expense		770			—			770			—			98			2,454			—
Derivative (income) expense		(292	)		515			(539	)		309			(555	)		136			(1,007	)
Total operating expense		28,047			25,310			57,212			63,120			130,169			205,402			130,488
Income from operations		22,810			29,570			39,118			48,465			67,639			53,586			78,909
Other income (expenses):
Interest income		77			63			114			93			276			363			762
Interest expense		(3,026	)		(963	)		(6,462	)		(1,731	)		(9,057	)		(4,349	)		(2,488	)
Gain on sale of oil and gas properties		—			—			—			—			—			—			48,208
Loss on sale of equipment inventory		(20	)		—			(20	)		—			(1,463	)		(1,257	)		—
Income (loss) from equity investment		—			—			—			—			(5,156	)		492			(7,561	)
Other, net		7			470			201			536			434			861			469
Total other income (expenses)		(2,962	)		(430	)		(6,167	)		(1,102	)		(14,966	)		(3,890	)		39,390
Income before taxes		19,848			29,140			32,951			47,363			52,673			49,696			118,299
Income tax provision		9,354			10,541			12,010			17,214			13,440			23,995			44,585
Net income including non-controlling interest		10,494			18,599			20,941			30,149			39,233			25,701			73,714
Net income attributable to non-controlling interest		1,022			573			1,476			946			1,682			715			1,442
Net income attributable to RAAM Global	$	9,472		$	18,026		$	19,465		$	29,203		$	37,551		$	24,986		$	72,272

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

Revenues

Oil and natural gas production. Oil and natural gas production for the three months ended June 30, 2011 was flat as compared to the three months ended June 30, 2010 at 1.0 MMBoe for both periods. During the three months ended June 30, 2011, new discoveries in the Yegua area onshore Texas were offset by normal declines in production in the more mature fields of West Cameron in the federal waters.

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Total revenues. Total revenues for the three months ended June 30, 2011 decreased to $50.9 million from $54.9 million for the three months ended June 30, 2010. The decrease in revenue was mainly attributable to lower hedged gas production coupled with lower hedged gas prices. The decrease in gas hedged revenues was partially offset by the increase in oil prices. The average sales price for the three months ended June 30, 2011 was $53.25 per Boe as compared to $54.62 per Boe for the three months ended June 30, 2010.

Operating costs and expenses

Production and delivery costs. Production and delivery costs increased to $8.9 million, or $9.31 per Boe, for the three months ended June 30, 2011, up from $6.9 million, or $6.89 per Boe, for the comparable period in 2010. The increase in production and delivery costs was primarily attributable to more repair and maintenance costs and enhanced regulatory and compliance efforts required on our platforms.

Workover costs. Our workover costs for the three months ended June 30, 2011 increased slightly to $786,000, or $0.82 per Boe, from $777,000 in the comparable period of 2010, or $0.77 per Boe. The slight increase in workover costs from the comparable period in 2010 was primarily a result of changes in projects needed to manage our wells and maintain efficient production levels.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for the three months ended June 30, 2011 remained flat at $13.9 million as compared to $13.8 million in the three months ended June 30, 2010.

General and administrative expenses. General and administrative expense increased to $4.0 million during the three months ended June 30, 2011, from $3.3 million in the comparable period in 2010. The increase in general and administrative expense resulted principally from higher salaries and office rent due to the establishment of a Denver office location, increased consultant compensation for the use of more specialized consultants on technical projects and additional accounting and legal fees incurred for regulatory compliance matters pursuant to the registration of $150.0 million our Senior Notes.

Bad debt expense.Bad debt expense increased to $0.8 million during the three months ended June 30, 2011, from zero in the comparable period in 2010. This increase is due to an analysis indicating that amounts owed to the Company by one customer are anticipated to be uncollectible.

Interest expense. Net interest expense increased to $2.9 million for the three months ended June 30, 2011, from $0.9 million for the three months ended June 30, 2010 due to higher balances and interest rates associated with the outstanding debt during the 2011 period. Debt balances averaged $150.0 million during the three months ended June 30, 2011 and $110.0 million during the three months ended June 30, 2010. Interest rates averaged 12.50% during the three months ended June 30, 2011 and 3.55% during the three months ended June 30, 2010. The increase in interest rates is due to the Company issuing 12.5% senior secured notes in September 2010 and using a portion of the proceeds from that offering to repay all of the outstanding indebtedness under the revolving credit facility.

Income tax provision. For the three months ended June 30, 2011, the Company recorded income tax expense of $9.4 million as compared to income tax expense of $10.5 million for the three months ended June 30, 2010. Income tax expense recognized was based on an effective tax rate calculation of 47.13% at June 30, 2011 and 36.18% at June 30, 2010. The tax rate for the three months ended June 30, 2011 increased as a result of changes to the expected annual financial results, which affected both the federal and state annualized tax rates.

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

Revenues

Oil and natural gas production. Oil and natural gas production for the six months ended June 30, 2011 decreased to 1.8 MMBoe from 2.0 MMBoe for the six months ended June 30, 2010. The decrease in production during the period was mainly due to pipeline shut-ins at the Breton Sound 53 field during the first quarter of 2011. Other decreases were due to normal production declines which were offset by the production from new discoveries during the second quarter of 2011.

Total revenues. Total revenues for the six months ended June 30, 2011 decreased to $96.3 million from $111.6 million for the six months ended June 30, 2010. The decrease in revenue was mainly attributable to lower production and lower gas prices which was partially reduced by the increase in second quarter oil prices. The average sales price for the six months ended June 30, 2011 was $52.73 per Boe as compared to $54.85 per Boe for the six months ended June 30, 2010.

Operating costs and expenses

Production and delivery costs. Production and delivery costs increased to $16.4 million, or $8.95 per Boe, for the six months ended June 30, 2011, up from $14.8 million, or $7.28 per Boe, for the comparable period in 2010. The increase in production and delivery costs was primarily attributable to more repair and maintenance costs and enhanced regulatory and compliance efforts required on our platforms.

Workover costs. Our workover costs for the six months ended June 30, 2011 decreased to $1.2 million, or $0.67 per Boe, from $2.1 million in the comparable period of 2010, or $1.02 per Boe. The decrease in workover costs from the comparable period in 2010 was primarily a result of changes in projects needed to manage our wells and maintain efficient production levels.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for the six months ended June 30, 2011 decreased to $31.1 million from $39.5 million in the comparable period in 2010. The decrease in depreciation, depletion, and amortization was caused primarily by a lower amount of amortizable oil and gas properties to deplete at June 30, 2011 and a lower of amount of revenues for the period.

General and administrative expenses. General and administrative expense increased to $8.3 million during the six months ended June 30, 2011, from $6.4 million in the comparable period in 2010. The increase in general and administrative expense resulted principally from higher salaries and office rent due to the establishment of a Denver office location, increased consultant compensation for the use of more specialized consultants on technical projects and additional accounting and legal fees incurred for regulatory compliance matters pursuant to the registration of $150.0 million our Senior Notes.

Bad debt expense.Bad debt expense increased to $0.8 million during the six months ended June 30, 2011, from zero in the comparable period in 2010. This increase is due to an analysis indicating that amounts owed to the Company by one customer are anticipated to be uncollectible.

Interest expense. Net interest expense increased to $6.3 million for the six months ended June 30, 2011, from $1.6 million for the six months ended June 30, 2010 due to higher balances and interest rates associated with the outstanding debt during the 2011 period. Debt balances averaged $150.0 million during the six months ended June 30, 2011 and $110.0 million during the six months ended June 30, 2010. Interest rates averaged 12.50% during the six months ended June 30, 2011 and 3.43% during the six months ended June 30, 2010. The increase in interest rates is due to the Company issuing 12.5% senior secured notes in September 2010 and using a portion of the proceeds from that offering to repay all of the outstanding indebtedness under the revolving credit facility.

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Income tax provision. For the six months ended June 30, 2011, the Company recorded income tax expense of $12.0 million as compared to income tax expense of $17.2 million for the six months ended June 30, 2010. Income tax expense recognized was based on an effective tax rate calculation of 36.45% at June 30, 2011 and 36.35% at June 30, 2010. Our effective tax rate differs from the statutory federal income tax rate primarily because of state and local income taxes, domestic production activities deductions, and percentage of depletion in excess of basis.

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

Revenues

Oil and natural gas production. Oil and natural gas production for the year ended December 31, 2010 decreased to 3.8 MMBoe from 4.1 MMBoe for the year ended December 31, 2009. The decrease in production during 2010 was due to general decline in the offshore wells with limited development activities in 2010. We had a capital expenditure program of $86.9 million in 2010 that was used primarily on lease acquisitions and drilling of our most viable prospects onshore in Texas.

Total revenues. Total revenues for the year ended December 31, 2010 decreased to $197.8 million from $259.0 million for the year ended December 31, 2009. The decrease in revenue was mainly attributable to a reduction in revenues from gas hedges and a reduction in gas production.

The decline in average prices realized from the sale of oil and natural gas reflected the sharp economic decline that began during the second half of 2008 and continued through 2009 and 2010. In addition, natural gas prices remained weak through 2009 due to high natural gas storage levels. Even though oil prices did rise during 2010, average sales prices per Boe for the year ended December 31, 2010 of $52.59 per Boe remained well below the average sales prices per Boe for the year ended December 31, 2009 of $58.15 per Boe.

Operating Costs and Expenses

Production and delivery costs. Our production and delivery costs for 2010 increased to $31.6 million, or $8.39 per Boe, from $25.8 million in 2009, or $6.29 per Boe. Actual production and delivery costs for both periods were comparable; however, physical damage insurance proceeds were recovered during the 2009 period and those proceeds offset production and delivery costs since the original repair costs were recorded in this category.

Workover costs. Our workover costs for 2010 increased to $10.5 million, or $2.78 per Boe, from $8.4 million in 2009, or $2.06 per Boe. The increase in workover costs from the comparable period in 2009 was primarily a result of changes in projects needed to manage our wells and maintain efficient production levels. Also during the 2009 period, the Company’s efforts were focused on repairing damages caused by hurricanes as opposed to completing workover projects that were in process.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for 2010 decreased to $72.0 million from $150.4 million in 2009. The decrease in depreciation, depletion and amortization was caused primarily by a lower amount of amortizable oil and gas properties to deplete at December 31, 2010.

General and administrative expenses. General and administrative expenses decreased to $16.6 million, from $18.1 million in 2009. The decrease in general and administrative expense resulted principally from specialized consultant costs on highly technical wells drilled during the 2009 period which did not recur in the 2010 period.

Interest expense. Net interest expense increased to $8.8 million, from $4.0 million in 2009 due to a higher interest rate on the Company’s Senior Notes which were issued during September 2010. The Company has recorded $5.0 of interest payable on the Senior Notes at December 31, 2010. Debt balances averaged $118.4 million during 2010 and $120.7 million during 2009. Interest rates averaged 5.90% during 2010 and 3.52% during 2009.

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Gain on sale of oil and gas properties. Gain on sale of oil and gas properties remained unchanged at $0 for the years ended December 31, 2010 and December 31, 2009.

Income (loss) from equity investment. Income (loss) from equity investment decreased to a $5.2 million loss for the year ended December 31, 2010 from a $492,000 gain for the year ended December 31, 2009. The Company recorded an “other than temporary impairment” on its equity method investment in Attune Australia, LLC during fourth quarter 2010. Champion Exploration, LLC, the partnership in which we had an equity interest (prior to June 30, 2009) had $965,000 of income for the first six months of 2009. We withdrew our 51% interest from Champion Exploration, LLC effective June 30, 2009.

Other income. For 2010, other income was $434,000 as compared to $861,000 in the same period of 2009. The decrease was mainly due to the dissolution of the minority interest in Crestar Energy, LLC in 2009, a non-recurring event.

Income tax provision. For 2010, we recorded an income tax expense of $13.4 million as compared to income tax expense of $24.0 million for 2009. Income tax expense recognized is based on effective tax rates of 25.5% for 2010 and 48.7% for 2009. Our effective tax rate differs from the statutory federal income tax rate primarily because of state and local income taxes and percentage depletion. The Company’s state and local income tax rate in 2010 decreased from 2009 as a result of having higher apportionment of its taxable income to states with lower statutory income tax rates.

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

Revenues

Oil and natural gas production. Oil and natural gas production for the year ended December 31, 2009 increased to 4.1 MMBoe from 3.3 MMBoe for the year ended December 31, 2008. The increase in production during 2009 was due to two new wells commencing production. We had a capital expenditure program of $136.1 million in 2009 that was used primarily on lease acquisitions and drilling of our most viable prospects onshore in Louisiana and Texas and in federal and state waters in the Gulf of Mexico.

Total revenues. Total revenues for the year ended December 31, 2009 increased to $259.0 million from $209.4 million for the year ended December 31, 2008. The increase in revenue was attributable to increased production along with higher hedged prices resulting in approximately $35.7 million and the recovery of business interruption insurance proceeds from Hurricane Gustav and Ike claims of $20.0 million.

The decline in average prices realized from the sale of oil and natural gas reflected the sharp economic decline that began during the second half of 2008 and continued through 2009. In addition, natural gas prices remained weak through 2009 due to high natural gas storage levels. Even though oil prices did rise during 2009, average sales prices per Boe for the year ended December 31, 2009 of $58.15 per Boe remained well below the average sales prices per Boe for the year ended December 31, 2008 of $62.79 per Boe.

Operating Costs and Expenses

Production and delivery costs. Our production and delivery costs for 2009 increased to $25.8 million, or $6.29 per Boe, from $19.2 million in 2008, or $5.83 per Boe. The increase in production and delivery costs from the comparable period in 2008 was primarily a result of higher repair and plugging and abandonment costs that we incurred due to damage from Hurricanes Gustav and Ike.

Workover costs. Our workover costs for 2009 decreased to $8.4 million, or $2.06 per Boe, from $11.4 million in 2008, or $3.48 per Boe. The decrease in workover costs from the comparable period in 2008 was primarily a result of changes in projects needed to manage our wells and maintain efficient production levels.

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Depreciation, depletion and amortization. Depreciation, depletion and amortization for 2009 increased to $150.4 million from $90.4 million in 2008. The increase in depreciation, depletion and amortization was the result of lower average 12-month prices used to value the year end reserves, which led to substantial depletion and a $44.7 million writedown of our full cost pool for the 2009 year.

General and administrative expenses. General and administrative expenses increased to $18.1 million, from $10.4 million in 2008. The increase in general and administrative expense resulted principally from an executive bonus and the use of more specialized consultants for the highly technical wells we drilled during the period.

Interest expense. Net interest expense increased to $4.0 million, from $1.7 million in 2008 due to changes in outstanding debt balances and the current LIBOR interest rates. Debt balances averaged $120.7 million during 2009 and $87.1 million during 2008. Interest rates averaged 3.52% during 2009 and 4.90% during 2008.

Gain on sale of oil and gas properties. Gain on sale of oil and gas properties decreased to $0 for the year ended December 31, 2009, from $48.2 million for the year ended December 31, 2008. During March 2008, we sold our lease acreage position in Arkansas for a significant gain. There were no similar property sales during 2009.

Income (loss) from equity investment. Income (loss) from equity investment increased to $492,000 gain for the year ended December 31, 2009, from a $7.6 million loss for the year ended December 31, 2008. Champion Exploration LLC, the partnership in which we had an equity interest (prior to June 30, 2009) incurred a $15.2 million loss during 2008 primarily resulting from drilling dry holes in the United Kingdom. Champion Exploration LLC had $965,000 of income for the first six months of 2009. We withdrew our 51% interest from Champion Exploration LLC effective June 30, 2009.

Other income. For 2009, other income was $861,000 as compared to $469,000 in the same period of 2008 mainly due to the dissolution of the minority interest in Crestar Energy, LLC.

Income tax provision. For 2009, we recorded an income tax expense of $24.0 million as compared to income tax expense of $44.6 million for 2008. Income tax expense recognized is based on effective tax rates of 48.7% for 2009 and 37.9% for 2008. Our effective tax rate differs from the statutory federal income tax rate primarily because of state and local income taxes and percentage depletion. The 2009 effective tax rate was higher than the 2008 rate due to a deferred tax rate increase and higher state and local income taxes. The unfavorable effect of the deferred rate change in 2009 primarily relates to the impact on our deferred tax liabilities of the change in our federal rate from 34% to 35%.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from shareholders, borrowings under our Amended Revolving Credit Facility, debt financings and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

We have a total capital expenditure budget of $275 million for 2011, which is a 216% increase over the $87 million invested during 2010. The Company spent approximately $87 million on capital expenditures during the first six months of 2011. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to

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generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Capital Expenditure Budget

Our total 2011 capital expenditure budget is approximately $275 million, of which approximately $87 million was expended in the first six months of 2011 including $14 million of prepaid drilling and exploration in Oklahoma, which is recorded in other assets. The remaining capital budget of $188 million consists of:

• $48 million for geological and geophysical costs, including $30 million leasing in two new prospect areas in Colorado and Texas;

• $21 million for reserve acquisitions;

• $25 million for Louisiana state water drilling and development prospects;

• $14 million for onshore drilling and development prospects in Mississippi and Louisiana;

• $28 million for onshore drilling and development prospects in Texas;

• $12 million for onshore drilling and development prospects in Oklahoma and California;

• $28 million for recompletions and platform and infrastructure upgrades for all project areas; and

• $12 million for plugging and abandonment costs primarily for offshore properties.

While we have budgeted $188 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. To date, our 2011 capital budget has been funded from debt financing and our cash flows from operations. We believe our present cash balance and expected future cash flows from operations should be more than sufficient to fund the remainder of our 2011 capital expenditure budget.

Amended Revolving Credit Facility

As of September 24, 2010, we had $100.0 million outstanding under our existing credit facility, which was repaid with the proceeds of our offering of $150.0 million 12.50% Senior Notes due 2015. On September 23, 2010, we also entered into our Amended and Restated Revolving Credit Facility. As of June 30, 2011 we had no indebtedness outstanding under our Amended Revolving Credit Facility and a borrowing base of approximately $62.5 million. As of December 31, 2010, we had no indebtedness outstanding under our Amended Revolving Credit Facility and a borrowing base of approximately $62.5 million.

12.50% Senior Secured Notes due 2015

On September 24, 2010, we completed an offering of $150.0 million senior secured notes at a coupon rate of 12.50% (the “2015 Senior Secured Notes”) with a maturity date of October 1, 2015. The interest on the notes is payable in cash semi-annually in arrears on April 1 and October 1 of each year, which commenced on April 1, 2011, to holders of record at the close of business on the preceding March 15 or September 15. Interest on the notes is computed on the basis of a 360-day year of twelve 30-day months. The notes were sold at 99.086% of their face amount and were recorded at their discounted amount, with the discount being amortized over the life of the notes. The Company used a portion of the net proceeds from the offering to repay all outstanding indebtedness under the revolving credit facility and intends to use the remainder of the proceeds for funding a portion of the planned capital expenditures for development and drilling during 2011. As of June 30, 2011, $150.0 million notional amount of the 2015 Senior Secured Notes was outstanding. The carrying amount of the 2015 Senior Secured Notes was $148.8 million as of June 30, 2011.

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The 2015 Senior Secured Notes are guaranteed on a senior secured basis by each of our existing and future domestic subsidiaries that guarantee indebtedness under our Amended Revolving Credit Facility. The 2015 Senior Secured Notes and the guarantees are secured by a security interest in substantially all of our and our existing future domestic subsidiaries’ (other than certain future unrestricted subsidiaries’) assets to the extent they constitute collateral under our Amended Revolving Credit Facility, subject to certain exceptions. Pursuant to an Intercreditor Agreement, the lien securing the notes is subordinated and junior to liens securing our Amended Revolving Credit Facility.

On July 15, 2011, the Company successfully completed the issuance and sale of $50.0 million aggregate principal amount of additional 12.50 % Senior Notes due 2015, which we refer to herein as the “old notes.” The old notes are Additional Notes issued pursuant to the indenture dated as of September 24, 2010, pursuant to which the Company initially issued $150.0 million aggregate principal amount of its 12.50% Notes, as supplemented by the First Supplemental Indenture dated as of July 15, 2011. The Additional Notes have identical terms, other than the issue date and issue price, and constitute part of the same series as the initially issued notes, although they bear a different CUSIP number than the initially issued notes until they are no longer restricted securities under the Securities Act. The Additional Notes are jointly and severally, and unconditionally, guaranteed on a senior secured basis by all of the Company’s current and future domestic subsidiaries that guarantee indebtedness under our Amended Revolving Credit Facility.

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

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

The table below discloses the net cash provided by (used in) operating activities, investing activities and financing activities for the six months ended June 30, 2011 and 2010 and the years ended December 31, 2010, 2009 and 2008:

	Six Months Ended June 30,						Year Ended December 31,
	2011			2010			2010			2009			2008
	(unaudited)
	(dollars in thousands)
Net cash provided by operating activities	$	71,694		$	57,105		$	114,209		$	185,505		$	122,401
Net cash used in investing activities		(83,811	)		(29,814	)		(87,838	)		(142,334	)		(191,522	)
Net cash provided by (used in) financing activities		2,306			(5,877	)		25,773			(22,335	)		45,302
Net (decrease) increase in cash and equivalents	$	(9,811	)	$	21,414		$	52,144		$	20,836		$	(23,819	)

Cash Flows Provided by Operating Activities

Operating activities provided cash totaling $71.7 million during the six months ended June 30, 2011 as compared to cash provided by operations of $57.1 million during the six months ended June 30, 2010. The increase in operating cash flows during the six months ended June 30, 2011 was principally attributable to lower accounts payable balances during the period and decreased revenues payable to our partners at June 30, 2011.

Cash provided from operating activities was $114.2 million during 2010 as compared to cash provided by operating activities of $185.5 million during 2009. The decrease in operating cash flows during 2010 was principally attributable to the timing of payments on accounts payable and better operating results in 2009 than in 2010.

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Cash flows from operating activities were $185.5 million during 2009 as compared to cash provided by operations of $122.4 million during 2008. The increase in operating cash flows during 2009 was principally attributable to the timing of payments on accounts payable and improved operating results over 2008 operating results before consideration of the ceiling test writedown on our oil and gas properties.

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

Cash Flows Used in Investing Activities

Investing activities used cash totaling $83.8 million during the six months ended June 30, 2011 as compared to cash used in investing of $29.8 million during the comparable period in 2010. Cash used in investing activities during the six months ended June 30, 2011 increased as compared to the same period of 2010 primarily because of increased drilling in Louisiana state waters, the implementation of an active drilling program for its prospects onshore Texas and the $14 million prepayment for Oklahoma drilling expenses.

Investing activities used cash totaling $87.8 million during 2010 as compared to cash used in investing of $142.3 million during 2009. Cash used in investing activities decreased in 2010 as compared to 2009 primarily because of the inability to drill wells in the Gulf of Mexico pursuant to the moratorium on drilling activities issued by the BOEMRE.

Investing activities used cash totaling $142.3 million during 2009 as compared to cash used in investing of $191.5 million during 2008. Cash used in investing activities decreased in 2009 as compared to 2008 primarily because of interruptions to our offshore development plans caused by Hurricanes Gustav and Ike in 2008.

Our capital expenditures for drilling, development and acquisition costs for the six months ended June 30, 2011 and 2010 and the years ended December 31, 2010, 2009 and 2008 are summarized in the following table:

	Six Months Ended June 30,				Year Ended December 31,
	2011		2010		2010		2009		2008
	(dollars in thousands)
Project Area
Federal	$	3,662	$	7,828	$	10,305	$	37,169	$	70,903
Shallow State Waters		27,945		5,173		14,561		51,632		78,579
Onshore Texas, Louisiana and Mississippi		32,650		9,280		39,719		38,209		39,957
Oklahoma, California and Mid-Continent		22,588		6,691		22,351		10,784		3,911
Total	$	86,845	$	28,972	$	86,936	$	137,794	$	193,350

Cash Flows Provided by (Used in) Financing Activities

Financing activities provided cash totaling $2.3 million during the six months ended June 30, 2011 as compared to cash used by financing activities of $5.9 million during the comparable period in 2010. Cash flows provided by financing activities during the first six months of 2011 consisted primarily of $8.0 million in proceeds from insurance premium financing offset by payments of $5.8 million on borrowings and shareholder dividends. Cash flows used in financing activities during the first six months of 2010 were mainly comprised of $15.1 million in payments on the Company’s revolving credit facility, insurance premium note payable and shareholder dividends offset by $8.9 million in proceeds from insurance premium financing.

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Financing activities provided cash flows of $25.8 million during 2010 as compared to cash used in financing activities of $22.3 million during 2009. Cash flows provided by financing during 2010 related primarily to the issuance of our Senior Notes offset by the repayment of the outstanding balance on our credit facility. Cash flows used by financing during 2009 related primarily to payments on our credit facility.

Financing activities used cash flows of $22.3 million during 2009 as compared to cash provided by financing activities of $45.3 million during 2008. Cash flows used by financing during 2009 related primarily to payments on our current credit facility. Cash flows provided during 2008 related primarily to the drawdown of funds from our credit facility.

Oil and Gas Hedging

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

While the use of these hedging arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. All of our hedging transactions are settled based upon reported settlement prices on the NYMEX.

At June 30, 2011, on a BOE basis, commodity derivative instruments were in place covering approximately 39% of our projected oil and natural gas sales through 2011, 21% of our projected oil and natural gas sales for 2012 and approximately 12% of our projected oil and natural gas sales for 2013. Approximately 38% of the Company’s remaining 2011 gas production, approximately 22% of the Company’s 2012 gas production, approximately 18% of the Company’s 2013 gas production, approximately 42% of the Company’s remaining 2011 oil production and approximately 21% of the Company’s 2012 oil production will yield minimum prices under the contracts as discussed in the notes to our unaudited consolidated financial statements included in this prospectus. Future oil and gas sales prices on other production will fluctuate according to market conditions. In addition, the results of the Company’s planned drilling and development efforts, as well as other changes in costs, expenses and oil and gas production rates, cannot be predicted with certainty. These and many other variables will affect the cash flows available to the Company for future capital expenditures and for debt repayments. Management projects it will have funds available (primarily from its Senior Secured Notes, its cash flows generated from operations, available borrowings under the Credit Agreement and infusion of new equity) to conduct its planned exploration and development program, but it will have to adjust the amount and timing of future expenditures as the availability of funds changes.

As of June 30, 2011, the Company had entered into the following oil derivative instruments:

	NYMEX Contract Price
	Total Futures				Total Options
Period	Volume in Bbls/Mo		Weighted Average Fixed Price		Volume in Bbls/Mo		Floor
2011(1)		39,000	$	86.21		—	$	—
2012(2)		14,500	$	88.14		3,660	$	110.00

(1) Average hedged volume is calculated for the remainder of the 2011 year.

(2) The Company currently does not have any volumes hedged for futures in the fourth quarter of 2012. The calculation of average hedged volumes is for the full year of 2012.

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Subsequent to June 30, 2011, we entered into derivative instruments where we sold a call for 1,000 barrels of oil per day for the period August 1, 2011 through December 31, 2011 at $95.00. For the same period and at the same daily rate, we bought a call at $86.21. For the period January 1, 2013 through December 31, 2013 we sold a call for 437 barrels of oil per day for $125. In addition, we entered into the following swap transactions where we sold our oil at the following rates and prices: January 2012 through September 2012 for 800 barrels of oil per day at $82.25, October 2012 through December 2012 for 1,300 barrels of oil per day at $84.00, January 2013 through June 2013 for 700 barrels of oil per day at $84.70, July 2013 through December 2013 for 500 barrels of oil per day at $85.50, January 2014 through June 2014 for 800 barrels of oil per day at $85.40 and July 2014 through September 2014 for 700 barrels of oil per day at $85.90. We also hedged the differential of Light Louisiana Sweet (LLS) to West Texas Intermediate (WTI) for September 2011 through December 2011 for 1,500 barrels of oil per day at $17.25 and January 2012 through March 2012 for 1,000 barrels of oil per day at $16.75.

As of June 30, 2011, the Company had entered into the following natural gas derivative instruments:

	NYMEX Contract Price
	Total Futures				Total Options
Period	Volume in MBtu/Mo		Weighted Average Fixed Price		Volume in MBtu/Mo		Estimated Price(2)
2011(1)		486,500	$	5.33		134,167	$	5.95
2012		155,333	$	5.30		152,500	$	5.10
2013		152,083	$	5.40		—	$	—

(1) Average hedged volume is calculated for the remainder of the 2011 year.

(2) For the period remaining in 2011 and 2012, the Company has entered into protective spreads where the price to be realized by the Company is dependent on the NYMEX contract closing price. The Company has estimated the price it will receive based on the closing NYMEX prices as of June 30, 2011.

Each of these transactions was designated as cash flow hedges. Please see “Notes to Unaudited Condensed Consolidated Financial Statements — Note 5” included elsewhere in this prospectus for additional discussion regarding the accounting applicable to our hedging program.

Subsequent to June 30, 2011, we sold a put for 5,000 MBtu per day for the period January 1, 2013 through December 31, 2013 at $4.00. For the same period and daily rate, we also bought a call for $5.40 and sold a call for $6.00.

Contractual Obligations

We have various contractual obligations in the normal course of our operations and financing activities. The following schedule summarizes our contractual obligations and other contractual commitments as of December 31, 2010:

	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Amended Revolving Credit Facility	$	—	$	—	$	—	$	—	$	—
12.50% Notes Due 2015		150,000		—		—		150,000		—
Promissory note(1)		2,970		110		265		305		2,290
Other indebtedness(2)		1,002		1,002		—		—		—
Operating leases(3)		1,317		283		580		454		—
Total	$	155,289	$	1,395	$	845	$	150,759	$	2,290

(1) Consists of a promissory note with GE Commercial Finance Business Property Corporation in the aggregate principal amount of $3.0 million relating to the construction of our Houston, TX office building.

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(2) Consists of $1.0 million of outstanding indebtedness relating to the financing of the premiums on our annual insurance policy.

(3) Consists of office space leases for our Lexington, KY, New Orleans, LA and Denver, CO offices.

Off-Balance Sheet Arrangements

As of June 30, 2011, we had no off-balance sheet arrangements or guarantees of third party obligations. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. Please see Note 2 to our audited consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for exploration and development costs. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including interest related to significant properties being evaluated and directly related overhead costs, are capitalized. Capitalized overhead costs amounted to $2.5 million and $1.6 million for the six months ended June 30, 2011 and 2010, respectively, and $4.6 million, $5.5 million and $3.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties were $95.6 million and $81.7 million for the six months ended June 30, 2011 and 2010, respectively, and $81.7 million and $113.4 million at December 31, 2010 and December 31, 2009, respectively. The Company believes that the unevaluated properties at June 30, 2011 will be substantially evaluated during 2011, 2012 and 2013, and the costs will begin to be amortized at that time. The Company capitalized interest of $4.0 million and $0.4 million during the six months ended June 30, 2011 and 2010, respectively, and $0.7 million, $0 and $2.2 million during the years ended December 31, 2010, 2009 and 2008, respectively, related to significant properties not subject to amortization.

Capitalized oil and gas property costs are subject to a “ceiling test,” which limits such costs to the aggregate of the estimated present value, discounted at 10%, of future net cash flows from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects. During 2009, the Company had a write-down of $44.7 million to capitalized oil and gas properties primarily as a result of lower natural gas and crude oil price assumptions, lower than anticipated success rate on new drilling and higher than expected capital expenditures incurred. There were no write-downs

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resulting from the “ceiling test” for the years ended December 31, 2010 and 2008. Future evaluation of unevaluated properties, oil and gas sales prices and changes in proved reserve estimates will affect the results of future ceiling tests. Sales of proved and unproved properties are accounted for as adjustments of 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, in which case the gain or loss is recognized in current income.

Proved Oil and Natural Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves. Please see “Notes to Unaudited Condensed Consolidated Financial Statements — Note 2” included elsewhere in this prospectus. Our estimated proved reserves for the years ended December 31, 2010, 2009 and 2008 were prepared by Netherland, Sewell & Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm, and H.J. Gruy and Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm.

Depreciation, Depletion and Amortization

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.

All capitalized costs of oil and gas properties are amortized through depreciation, depletion and amortization (“DD&A”) using the future gross revenue method whereby the annual provision is computed by dividing revenue earned during the period by future gross revenues at the beginning of the period, and applying the resulting rate to the cost of oil and gas properties, including estimated future development and abandonment costs.

Sales of Oil and Gas Properties

Pursuant to the full-cost method of accounting, sales of proved and unproved oil and gas properties are accounted for as adjustments of 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, in which case the gain or loss is recognized in current income. During the fourth quarter of 2010, the Company finalized an agreement to sell approximately 69,000 acres onshore Louisiana to an unrelated third party oil and gas company. The final sales price amounted to $13.7 million and is recorded in accounts receivable and as an accumulated reduction to our net oil and gas properties on the accompanying consolidated balance sheet. The cash payment was collected during January 2011, pursuant to the agreement.

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Asset Retirement Obligations

In accordance with the provisions of FASB guidance related to accounting for asset retirement obligations and FASB guidance on accounting for conditional asset retirement obligations, costs associated with the retirement of fixed assets (e.g., oil and gas production facilities, etc.) that the Company is legally obligated to incur are accrued. The fair value of the obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the life of the applicable asset. The asset retirement cost recorded in oil and gas properties being amortized at June 30, 2011 is $19.7 million and at December 31, 2010 is $18.8 million. Accretion of the discounted asset retirement obligations is recognized as an increase in the carrying amount of the liability and as an expense within depreciation, depletion and amortization on the accompanying statement of operations. A discount rate of 5% was used to calculate the asset retirement obligation until September 24, 2010, at which time the Company began using a discount rate of 12.5%, the rate of the newly issued 2015 Senior Notes, for all new AROs and revisions to any previous AROs. Other critical assumptions used to calculate asset retirement obligations include reserve lives as reported by our independent oil and natural gas reservoir engineering consulting firms, current market rates for plugging and abandonment activities and historical costs the Company has incurred on its plugging and abandonment activities.

Hedging Activities

The Company’s revenues are primarily the result of sales of its oil and natural gas production. Market prices of oil and natural gas may fluctuate and affect operating results. The Company engages in hedging activities that primarily include the use of floors, costless collars and futures transactions in order to minimize the downside risk from adverse price movements but allow for the realization of upside profits, if available. Costs and any benefits derived from the effective hedge portions of these activities are reflected in revenues from oil and gas production.

The Company follows the provisions of FASB guidance related to accounting for derivative instruments and hedging activities. This guidance requires all derivatives to be reported as assets or liabilities at their fair values, and the balance-sheet caption “Commodity Derivatives” is being used in the accompanying balance sheets for this purpose. This guidance also imposes additional documentation requirements in order for derivatives to be accounted for as hedges of future risks. The Company designated all new commodity derivative instruments entered into in 2010 and 2009 as hedges for accounting purposes, so the related unrealized changes in their fair values are reported net of tax in the accompanying balance sheet as a component of other comprehensive income. Any hedge ineffectiveness (which represents the amount by which the change in fair value of the derivative exceeds the change in cash flows of the forecasted transaction) is recorded in current period earnings in the accompanying statement of operations as derivative (income) expense. Hedge ineffectiveness of actual monthly settlements is recorded as a component of oil and gas sales in the accompanying consolidated statement of operations. During 2010 and 2009, the amount of other comprehensive income related to hedge transactions that settled during the year and is recorded in the accompanying consolidated statements of operations was $17.5 million and $44.0 million, respectively, net of tax effects. During the year ended December 31, 2008, the amount of other comprehensive loss related to hedge transactions that settled and is recorded in the accompanying consolidated statements of operations was $1.1 million. The Company anticipates the amount of other comprehensive income related to hedge transactions that will settle during the next twelve months and be recorded in the 2011 consolidated statements of operations will be $4.8 million, net of tax effects.

Recently Issued Accounting Pronouncements

In June 2009, the FASB issued accounting guidance on the consolidation of variable interest entities (“VIEs”). This new guidance revises previous guidance by replacing the quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a VIE with a qualitative approach focused on identifying which enterprise has both the power to direct the activities of the VIE

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that most significantly impacts the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits that could be significant to the entity. In addition, this guidance requires reconsideration of whether an entity is a VIE when any changes in facts or circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of the entity that most significantly impacts the entity’s economic performance. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE and additional disclosures about an enterprise’s involvement in VIEs. This guidance is effective for fiscal years beginning after November 15, 2009. Our adoption of the new guidance during the first quarter of 2010 did not have a material effect on our consolidated financial statements.

In January 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-06,Fair Value Measurements and Disclosures (“ASU 2010-06”) which requires new disclosures and clarifies existing disclosures required under current fair value guidance. Under the new guidance, a reporting entity must (1) disclose separately gross transfers in and gross transfers out of Levels 1 and 2 and (2) include separate presentation of purchases, sales, issuances and settlements rather than net presentation in the Level 3 reconciliation. ASU 2010-06 also amends required levels of disaggregation of asset classes and expands information required as to inputs and valuation techniques for recurring and non-recurring Level 2 and 3 measurements. With the exception of the disclosures in (2) above, the new disclosures became effective for interim an annual reporting periods beginning after December 15, 2009. Items in (2) above become effective one year later. Although it expanded disclosure requirements, the adoption of ASU 2010-06 did not have a material effect on the Company.

In July 2010, the FASB issued ASU No. 2010-20,Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses (“ASU 2010-20”). The amendments of ASU 2010-20 require enhanced disclosures regarding the nature of credit risk in a company’s financing receivables and how that risk is analyzed. Disclosures required by ASU 2010-20 include credit quality indicators, non-accrual and past due information, and modifications of financing receivables. Sales-type and direct financing capital leases are in the scope of the new requirements though trade accounts receivable that arose from the sale of goods or services and have contractual maturities of one year or less are specifically excluded. End of period disclosures were effective for year-end 2010. Disclosures regarding activity became effective in the first quarter of 2011. The amendments of ASU 2010-20 had no impact on the Company’s consolidated financial results as these changes relate only to disclosures.

In June 2011, ASU No. 2011-5 was issued, amending Topic 220 — Comprehensive Income. ASU 2011-5 modifies alternative presentation standards, eliminating the option for disclosure of the elements of other comprehensive income within the statement of stockholder’s equity. Adoption of ASU 2011-5 by the Company will change our existing presentation, but will not impact the components of other comprehensive income. ASU 2011-5 is effective for fiscal periods beginning after December 15, 2011.

The FASB also issued several accounting standards updates during 2010 and 2011, not discussed above, that related to technical corrections of existing guidance or new guidance that is not meaningful to the Company’s current financial statements.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the six months ended June 30, 2010 or 2011 or for the years ended December 31, 2010, 2009 or 2008. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

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Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which may include the use of derivative instruments.

Commodity Price Risk

Our primary market risk exposure is in the pricing applicable to our crude oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our United States natural gas production. Pricing for crude oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production for the six months ended June 30, 2011, our annual revenue would increase or decrease by approximately $16.2 million for each $10.00 per barrel change in crude oil prices and $10.1 million for each $1.00 per MMBtu change in natural gas prices.

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

For a further discussion of our hedging activities including a list of the commodity derivatives held by the Company, please see “Notes to Unaudited Condensed Consolidated Financial Statements — Note 3” and “Notes to Unaudited Condensed Consolidated Financial Statements — Note 5” included in this prospectus.

Credit Risk

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through joint interest receivables ($3.2 million at June 30, 2011) and the sale of our crude oil and natural gas production, which we market to energy marketing companies, refineries and affiliates ($28.7 million in receivables at June 30, 2011). Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. In order to minimize our exposure to credit risk we request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. In this manner, we reduce credit risk. We also have the right to place a lien on our co-owners interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to support crude oil and natural gas sales receivables owed to us.

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Interest Rate Risk

Our exposure to changes in interest rates relates primarily to long-term debt obligations. Historically, we were exposed to changes in interest rates as a result of our revolving credit facility and this exposure will remain under our Amended Revolving Credit Facility. No debt was outstanding under the Amended Revolving Credit Facility at June 30, 2011. The majority of our long-term debt obligations consist of the outstanding senior notes, which have a fixed interest rate; therefore, we are not exposed to interest rate risk through these notes and our overall interest rate risk exposure is low. For additional information regarding our Amended Revolving Credit Facility, see “Management’s Discussion and Analysis Financial Condition and Results of Operations — Amended Revolving Credit Facility.” We do not believe our interest rate exposure warrants entry into interest rate hedges and have, therefore, not hedged our interest rate exposure.

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BUSINESS

General

We are a privately held oil and natural gas exploration and production company engaged in the exploration, development, production and acquisition of oil and gas properties. Our operations are located in the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas, Oklahoma, California and New Mexico. We focus on the development of both conventional oil and gas plays and unconventional resource plays. Historically, we have successfully developed conventional oil and gas plays in the offshore Gulf of Mexico and onshore Texas and Louisiana. More recently, we have redirected our focus to the acquisition and development of acreage in the shallow oil, tight gas sand and oil shale plays throughout the United States. Since 2007, we have targeted unconventional plays, including tight gas and oil in shale in Oklahoma, California, and New Mexico and have obtained land positions in these plays.

Our assets create a portfolio of production, resources and opportunities that are balanced between long-lived, dependable production and exploration and development opportunities. Current development projects are focused on three main areas: shallow waters offshore, onshore conventional assets in Texas, Louisiana and Oklahoma, and unconventional assets in Oklahoma. We have selectively acquired and accumulated a portfolio of oil and gas leases in both oil and gas prone unconventional areas domestically. We plan to continue to augment our Gulf Coast production, increase our proved reserves and the reserve life of our portfolio through the development of these unconventional assets.

We were established in 1986 by Howard A. Settle and Jonathan B. Rudney. In 2003, RAAM was incorporated in Delaware as a holding company for its operating subsidiaries.

At December 31, 2010, we had estimated total proved oil and natural gas reserves of 18.8 MMBoe (61% oil). For 2010, our net daily production averaged 10,305 Boepd, which generated revenue of $198 million.

Core Properties

Our core properties include assets offshore in the Gulf of Mexico in Louisiana state waters and United States federal waters, onshore in Texas and Louisiana, and conventional and unconventional assets in Oklahoma.

Offshore

Gulf of Mexico — Louisiana State Waters. We commenced operations in the Breton Sound 53 Field in 1989 and currently operate 13 producing wells from 2 manned production platforms which we own. Average net daily production for the year ended December 31, 2010 was 3,642 Boepd. Our leasehold position encompassed 8,603 net acres with proved reserves of 5,903 MBoe at December 31, 2010. We have had a 75% drilling success rate in the Breton Sound 53 Field since 2000. Historical drilling success has been in the Uvig and Tex W zones above 10,500 feet. Recent development of the field has focused on newly discovered deep plays of the Big Hum and Cris I zones from 10,500 to 17,000 feet.

Gulf of Mexico — Federal Waters. We commenced operations in the shallow water West Cameron 368 Field and Ship Shoal 154 Field in the United States federal waters in 1987 and 1990, respectively, and we currently own and operate 15 wells and 12 production platforms. Average net daily production for the year ended December 31, 2010 from the United States federal waters was 3,346 Boepd. Our leasehold position encompassed 82,837 net acres with proved reserves of 9,231 MBoe as of December 31, 2010.

Onshore

Gulf Coast. We currently have 15 producing wells (15 operated) onshore along the Gulf Coast. Average net daily production for the year ended December 31, 2010 was 3,225 Boepd. Our leasehold position encompassed

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9,865 net acres with proved reserves of 2,532 MBoe at December 31, 2010. In Texas, we have focused on the Eocene Yegua/Cook Mountain trend, which produce natural gas with high condensate yields. Average net daily production for the year ended December 31, 2010 was 1,320 Boepd from 7 producing wells. In Louisiana we have focused on the Lower Miocene Atchafalaya Basin. Average net daily production for the year ended December 31, 2010 was 773 Boepd from 4 producing wells. In addition, we realized 1,132 Boepd of production for the year ended December 31, 2010 from 4 wells in other areas of Louisiana, Mississippi and Texas.

Resource Plays

Oklahoma. Our leasehold position in the shallow oil Mississippi Chat formation of Oklahoma encompassed approximately 38,810 net acres with proved reserves of 1,112 MBoe at December 31, 2010 and average net daily production for the year ended December 31, 2010 of 92 Boepd from 24 producing wells. We own a 50% working interest in an Osage tribe concession in Osage County, Oklahoma. The concession contains 74,580 acres, with approximately half of the concession acreage covered by a modern 3-D seismic survey. Since acquiring the concession in 2007 (including 5 currently producing wells), we have drilled 21 vertical wells, of which 19 vertical wells have been completed with commercial oil production. During the first half of 2011, we drilled four horizontal wells, which are in various states of completion and review.

Our Operations

Proved Reserves

The following tables set forth our estimated proved crude oil and natural gas reserves and percent of total proved reserves that are proved developed as of December 31, 2010 by reserve category and region. Netherland, Sewell & Associates, Inc., independent petroleum engineers, evaluated properties representing approximately 32% of our proved reserves, and H.J. Gruy and Associates, Inc., independent petroleum engineers, evaluated the remaining properties representing approximately 68% of our proved reserves at December 31, 2010. Copies of Netherland, Sewell & Associates, Inc. and H.J. Gruy and Associate, Inc.’s summary reports are included as exhibits to the registration statement which includes this prospectus. The estimated value of our proved reserves at December 31, 2010 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2010 through December 2010, without giving effect to derivative transactions, and were held constant throughout the life of the properties. These prices were $75.96 per Bbl for crude oil and oil equivalents and $4.376 per MMBtu for natural gas.

	December 31, 2010
	Crude Oil		Natural Gas
	(MBbls)		(MMcf)
Estimated proved developed producing		1,798		24,748
Estimated proved developed non-producing		2,053		11,169
Estimated proved undeveloped		7,587		8,124
Total estimated proved reserves		11,438		44,041

	Proved Developed				Proved Undeveloped
	Crude Oil		Natural Gas		Crude Oil		Natural Gas
	(MBbls)		(MMcf)		(MBbls)		(MMcf)
Offshore
Federal waters		767		4,239		6,649		6,649
Shallow state waters		2,333		19,621		55		1,475
Onshore
Onshore Texas and Louisiana		522		12,057		—		—
Resource Plays
Oklahoma		229		—		883		—
Total		3,851		35,917		7,587		8,124

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We have historically added reserves through our exploration program and development activities. Changes in proved reserves were as follows:

	December 31,
MBoe	2010			2009			2008
Proved reserves beginning of year		20,204			18,270			11,939
Revisions of previous estimates		836			2,563			(181	)
Extensions, discoveries and other additions		1,500			1,927			8,374
Production		(3,761	)		(4,106	)		(3,292	)
Purchase of minerals in place		—			1,550			1,430
Proved reserves end of year		18,779			20,204			18,270

Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Revisions of 181 MBoe during 2008 was mainly due to the write-off of reserves at Barataria Bay due to it being determined to be uneconomic under the current evaluation at December 31, 2008. The revisions of 2,563 MBoe during 2009 include a reserve add of the Barataria Bay reserves due to remedial work which was performed during the year, reserve adds at Breton Sound 53 due to remapping and Jupiter II gas pay, reserve adds at Flatts Guitar, reserve adds to Lake Salvadore and Main Pass 45 due to performance adds and a downward revision at West Cameron 368 due to sand production. Revisions of 836 MBoe during 2010 include reserve adds for some of our wells in shallow state waters due to remedial work performed during the year.

Extensions, discoveries and other additions. These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions at December 31, 2009 include producing wells in West Cameron 368 Field, Breton Sound 53 Field and Oklahoma. Extensions, discoveries and other additions at December 31, 2010 include new wells drilled onshore in Texas and additional reserves in Oklahoma.

We expect that a significant portion of future reserve additions will come from our major development projects including the extension and further development of the Breton Sound 53 Field, the expansion of the Eocene Yegua/Cook Mountain producing trend in east Texas, and the extension and further development of the shallow oil production in Oklahoma. We may also purchase proved properties in strategic acquisitions.

Technology Used to Establish Proved Reserves. Under the SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and Netherland, Sewell & Associates, Inc. and H.J. Gruy and Associates, Inc., our independent petroleum engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient

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production history were estimated using appropriate decline curves, material balance calculation or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using pore volume calculations and performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Qualifications of technical persons and internal controls over reserves estimation process. In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and guidelines established by the SEC, Netherland, Sewell & Associates, Inc. and H.J. Gruy and Associates, Inc., our independent petroleum engineers, estimated 98% of our proved reserve information as of December 31, 2010 included in this prospectus. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished to Netherland, Sewell & Associates, Inc. and H.J. Gruy and Associates, Inc. in their reserves estimation process. Our technical team meets regularly with representatives of Netherland, Sewell & Associates, Inc. and H.J. Gruy and Associates, Inc. to review properties and discuss methods and assumptions used in Netherland, Sewell & Associates, Inc.’s and H.J. Gruy and Associates, Inc.’s preparation of the year-end reserves estimates. All field and reserve technical information, which is updated annually, is assessed for validity when Netherland, Sewell & Associates, Inc. and H.J. Gruy and Associates, Inc. hold technical meetings with our internal staff of petroleum engineers, operations and land personnel to discuss field performance and to validate future development plans. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of the Netherland, Sewell & Associates, Inc. and H.J. Gruy and Associates, Inc. reserve reports are reviewed with representatives of Netherland, Sewell & Associates, Inc. and H.J. Gruy and Associates, Inc., respectively, and our internal technical staff before dissemination of the information. Additionally, our senior management reviews and approves the Netherland, Sewell & Associates, Inc. and H.J. Gruy and Associates, Inc. reserve reports and any internally estimated significant changes to our proved reserves on a quarterly basis.

Our Vice President of Reservoir Engineering is the technical person primarily responsible for overseeing the preparation of our reserves estimates. He has a BS degree in Civil Engineering and an MBA in Finance. He has 29 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering since 1985 and is a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers. He is a registered Professional Engineer in the State of Louisiana. Our Vice President of Reservoir Engineering reports directly to our Senior Vice President of Exploration and our Chief Operating Officer. Reserves estimates are reviewed and approved by senior engineering staff with final approval by our Chief Operating Officer and certain other members of senior management.

Proved undeveloped reserves. Our proved undeveloped reserves at December 31, 2010 were 8.9 MMBoe, consisting of 7.6 MMBbls of crude oil and 8.1 Bcf of natural gas. There were no material changes in proved undeveloped reserves that occurred during the year. Estimated future development costs relating to the development of 2010 year-end proved undeveloped reserves, as shown in our December 31, 2010 reserve report, is $100 million, of which 2011 and 2012 expenditures are estimated to be $1.5 million and $36.3 million, respectively. All proved undeveloped reserves are scheduled to be drilled by 2016. In addition, one of our offshore federal leases, designated as the Flatts’ Guitar prospect, is located in the deep waters of the Gulf of Mexico. This lease accounts for 87.0% of our proved undeveloped reserves at December 31, 2010 and remains to be drilled or developed. The BOEMRE’s moratorium and substantive changes to regulations for drilling will have an effect on this lease. The amendments to OPA will also affect this lease and our other offshore operations.

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On January 25, 2011, we filed suit against the United States Government claiming a breach of contract on the lease governing Ewing Bank Block 920 (the Flatts’ Guitar Prospect). For additional information regarding this suit, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Overview.”

Capital Expenditure Budget

We have a total capital expenditure budget of $275 million for 2011, which is a 216% increase over the $87 million invested during 2010. The Company spent approximately $87 million on capital expenditures during the first six months of 2011. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Our total 2011 capital expenditure budget is approximately $275 million, of which approximately $87 million was expended in the first six months of 2011 including $14 million of prepaid drilling and exploration in Oklahoma, which is recorded in other assets. The remaining capital budget of $188 million consists of:

• $48 million for geological and geophysical costs, including $30 million leasing in two new prospect areas in Colorado and Texas;

• $21 million for reserve acquisitions;

• $25 million for Louisiana state water drilling and development prospects;

• $14 million for onshore drilling and development prospects in Mississippi and Louisiana;

• $28 million for onshore drilling and development prospects in Texas;

• $12 million for onshore drilling and development prospects in Oklahoma and California;

• $28 million for recompletions and platform and infrastructure upgrades for all project areas; and

• $12 million for plugging and abandonment costs primarily for offshore properties.

While we have budgeted $188 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. To date, our 2011 capital budget has been funded from debt financing and our cash flows from operations. We believe our present cash balance and expected future cash flows from operations should be more than sufficient to fund the remainder of our 2011 capital expenditure budget.

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Developed and Undeveloped Acreage

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

	Developed acres				Undeveloped acres				Total
	Gross		Net		Gross		Net		Gross		Net
Offshore
Federal waters(1)		18,359		16,227		67,159		66,610		85,518		82,837
Shallow waters(2)		7,966		5,503		3,099		3,099		11,065		8,602
Onshore
Texas and Louisiana(3)		4,983		2,947		7,237		6,918		12,220		9,865
Resource Plays
Haynesville		0		0		3,568		3,568		3,568		3,568
Tuscaloosa Marine Shale(4)		0		0		99,067		87,902		99,067		87,902
Tucumcari Basin Tight Sands		0		0		28,385		4,889		28,385		4,889
Deep Bossier Tight Sands		640		128		3,860		772		4,500		900
Monterey Shale		0		0		28,567		19,656		28,567		19,656
Oklahoma		27,100		13,550		50,520		25,260		77,620		38,810
Total		59,048		38,355		291,462		218,674		350,510		257,029

(1) Our core areas of production in the United States federal waters in the Gulf of Mexico are the West Cameron 368 Field and the Ship Shoal 154 Field.

(2) Our core area of production in the state waters in the Gulf of Mexico is in the Breton Sound 53 Field.

(3) Our core areas of production in Texas are the Eocene Yegua/Cook Mountain trend and our core areas of production in Louisiana are in the Lower Miocene trend.

(4) In December 2010, we entered into a contractual agreement to sell 69,544 net acres and received payment in January 2011. In May 2011, we sold approximately 16,000 acres.

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2010 that will expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates:

	2011				2012				2013
	Gross		Net		Gross		Net		Gross		Net
Offshore
Federal waters		0		0		0		0		10,000		10,000
Shallow waters		1,385		1,385		1,021		1,021		662		662
Onshore
Texas and Louisiana		2,311		1,836		1,771		1,196		3,156		2,726
Resource Plays
Haynesville		121		60		0		0		0		0
Tuscaloosa Marine Shale		2,921		2,197		859		771		35,918		32,880
Tucumcari Basin Tight Sands		0		0		0		0		7,878		1,554
Deep Bossier Tight Sands		0		0		0		0		0		0
Monterey Shale		0		0		0		0		0		0
Oklahoma		480		240		0		0		320		160
Total		7,218		5,718		3,651		2,988		57,934		47,982

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

	2010				2009				2008
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells
Oil		2.0		1.3		2.0		1.0		6.0		3.0
Natural Gas		3.0		2.4		2.0		1.9		7.0		4.7
Dry		3.0		2.6		3.0		2.5		5.0		3.4
Total Exploratory Wells		8.0		6.3		7.0		5.4		18.0		11.1
Development Wells
Oil		—		—		5.0		2.6		5.0		2.5
Natural Gas		1.0		0.8		—		—		3.0		2.6
Dry		—		—		1.0		0.5		—		—
Total Development Wells		1.0		0.8		6.0		3.1		8.0		5.1
Total Wells		9.0		7.1		13.0		8.5		26.0		16.2

As of December 31, 2010, there were 3 gross (2.12 net) wells in the process of completing or waiting on completion. We have also recompleted 3 wells during 2010, all of which are producing. As of December 31, 2010, we were not operating any drilling rigs on our properties. Our rig activity during 2011 will be dependent on crude oil and natural gas prices and, accordingly, our rig count may increase or decrease from current levels. There can be no assurance, however, that additional rigs will be available to us at an attractive cost.

Summary of Oil and Natural Gas Properties and Projects Offshore

We operated 21 offshore production platforms with 28 producing wells as of December 31, 2010. Production from our offshore assets averaged 6,987 Boepd for the year ended December 31, 2010. Our offshore staff includes 5 geoscientists who generate prospects from our extensive, modern 3-D seismic data base. Our offshore operations cover three core areas of production in the Gulf of Mexico: (1) the West Cameron 368 Field production area in shallow United States federal waters, (2) the Ship Shoal production area in shallow United States federal waters, and (3) the Breton Sound production area in shallow state waters. In each of these core areas, we have platforms, production facilities, and pipelines in place, where production from new wells can be established quickly. We have a significant inventory of drilling prospects in each of these core areas. In the United States federal waters, we currently hold 16,445 net acres by production and we have 66,610 net acres that remain undrilled in primary term contracts. In the state waters of Louisiana, we hold 5,503 net acres by production.

One of our offshore federal leases, designated as the Flatts’ Guitar prospect, is located in the deep waters of the Gulf of Mexico. This lease accounts for 87% of our proved undeveloped reserves at December 31, 2010 and remains to be drilled or developed. The BOEMRE’s moratorium and substantive changes to regulations for drilling will have an effect on this lease. The amendments to OPA will also affect this lease and our other offshore operations. On January 25, 2011, we filed suit against the United States Government claiming a breach of contract on the lease governing Ewing Bank Block 920 (the Flatts’ Guitar Prospect). For additional information regarding this suit, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview.”

West Cameron 368 Field. The West Cameron 368 Field was one of our first discoveries in the Gulf of Mexico. We have drilled 22 successful wells out of 24 wells drilled and have produced over an aggregate gross 120 Bcf and 1.0 MMBbls since our first discovery in 1986. West Cameron 368 Field represented 25% of our average daily production for the year ended December 31, 2010.

Ship Shoal 154 Field. In 1989, we farmed out Ship Shoal 150 Block from Chevron. In 1990, we drilled our first successful well on this prolific salt dome. We have drilled 17 wells based on our 3-D seismic analysis and

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we have completed 11 of these wells as commercial oil producers. We have produced over an aggregate gross 8.8 Bcf and 11.9 MMBbls to date from Ship Shoal. Ship Shoal 154 Field represented 8% of our average daily production for the year ended December 31, 2010.

Breton Sound 53 Field. The Breton Sound 53 Field has been a core area for our offshore operations since it first acquired and completed the Virgo BS 52 SL 12806 Century #1 well in 1989. This well established the first geopressured production in the Breton Sound 53 Field, which has subsequently grown to become the Company’s most prolific offshore field to date. We have 8,602 net acres under lease and operate two manned production platforms in the Breton Sound 53 Field. The Breton Sound 53 Field represented 35% of our average daily production for the year ended December 31, 2010. We began a three well development program in this area during the first quarter of 2011. We have drilled two successful wells, which are currently in the process of being completed.

Onshore

We have planned an eight-well drilling program for 2011 which has resulted in three successful wells and two unsuccessful wells so far this year. Production from our onshore properties in the Gulf Coast averaged 3,225 Boepd for the year ended December 31, 2010. As of June 30, 2011, we have 2,947 net acres held by production and 20,669 net acres that remain undrilled.

Eocene Yegua/Cook Mountain. Two wells drilled in 2010 were brought online and were producing as of June 30, 2011. A third well was considered uneconomic and a fourth well just recently drilled is considered successful. The Eocene Yegua/Cook Mountain trend in southeast Texas has been a core area for us since 2005. We shot the 167 square mile JASPO proprietary 3-D in 2005 and have since merged this data with over 300 square miles of licensed 3-D data. Production from this area averaged 1,320 Boepd for the year ended December 31, 2010. The Eocene Yegua/Cook Mountain trend represented 13% of our average daily production for the year ended December 31, 2010.

Briscoe Bayou. The Briscoe Bayou well was spud in late January 2011, and was determined to be uneconomic.

Other Non-Core. The company also operates 4 wells (2 in Louisiana, 1 in Mississippi and 1 in Texas), which accounted for 11% of our average net daily production for the year ended December 31, 2010.

Resource

We have significant land positions in the following unconventional tight sand and shale plays in the United States, which are in various stages of development: (1) Mississippian Chat and Lime, Pennsylvanian Sands (Oklahoma, oil), (2) Monterey Shale (California, oil) and (3) Tucumcari Basin Tight Sands (New Mexico, gas).

Although we have several resource projects in various stages of development, our focus within the next twelve months will be on developing the Oklahoma assets.

Oklahoma. We currently own a 50% working interest in an Osage tribe concession in Osage county, Oklahoma. The concession contains 74,580 gross acres. 35,000 of the 74,580 acres are covered by modern 3-D survey data in the possession of the joint venture. Through the joint venture, we have drilled 21 vertical wells in our concession, 19 of which have been successful and are currently producing (91% success rate as of December 31, 2010). Average net daily production for the year ended December 31, 2010 from the Oklahoma concession was approximately 92 Boepd with estimated proved reserves of 1,112 MBoe.

In 2011, we acquired approximately 63,000 additional net acres in Oklahoma and Kansas, all of which are prospective in the Mississippian Chat and Lime formations. As a part of these transactions, we entered into a

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turnkey drilling contract for four horizontal wells to be drilled in the Mississippi Lime formation. With these acquisitions, we will have approximately 102,000 net acres under lease which are prospective in the Mississippian Chat and Lime formations in the Cherokee basin. During the first half of 2011, all four horizontal wells were drilled and are in various stages of completion and review.

Monterey Shale. We have established an office in Bakersfield, California and will begin a major exploration program in the San Joaquin Basin. The program will focus on the Monterey oil shale. We have acquired 3-D and 2-D seismic data over the prospective area. We have 20,509 net acres under lease as of June 30, 2011. We believe the Monterey Shale may be one of the most prolific oil resource plays in the United States. As a result of our recent activities, we are in a position to have significant participation in this emerging oil resource play.

Tucumcari Basin Tight Sands. We are a participant in a 4,889 net acre joint venture in the Tucumcari Basin. We own an 18.75% working interest in this project. We will not be incurring any major additional expenditures until production testing and evaluation has been completed.

Tuscaloosa Marine Shale. In December 2010, we entered into a contractual agreement with a major independent exploration and production company to sell approximately 69,000 net acres of our Tuscaloosa Marine Shale acreage located in Louisiana. In January 2011, we received $13.8 million in payment for these leases. Approximately 16,000 acres in the Tuscaloosa Marine Shale trend located in Mississippi were sold during May 2011 for approximately $2.2 million. We currently have 89 net acres remaining of which 72 acres expire in 2012 and the remaining acreage in 2013.

Production, Price and Cost History

Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically during this decade. However, the current economic slowdown reduced this demand during the second half of 2008 and through 2009. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect such volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

The following table sets forth information regarding oil and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2010, 2009 and 2008. For additional information on price calculations, see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Year Ended December 31,
	2010		2009		2008
Net production volumes:
Oil (Bbl)		1,065,784		1,057,819		825,637
Natural gas (Boe)		2,695,394		3,048,502		2,466,793
Oil equivalents (Boe)		3,761,178		4,106,321		3,292,430
Average sales price per unit:(1)
Oil (Bbl)	$	75.66	$	79.66	$	95.67
Natural gas (Boe)	$	7.25	$	8.45	$	8.63
Oil equivalents (Boe)	$	52.59	$	58.15	$	62.79
Costs and expenses per Boe:
Lease operating expenses	$	8.39	$	6.29	$	5.83
Depreciation, depletion and amortization(2)	$	19.13	$	36.63	$	27.47
General and administrative expenses	$	4.42	$	4.41	$	3.16

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(1) Average prices presented give effect to our hedging. Please see “— Oil and Gas Hedging” for a discussion of our hedging activities.

(2) At December 31, 2009, the Company’s ceiling test computation resulted in a write-down of oil and gas properties of $44.7 million, or $10.88 per Boe.

Net production volumes for the year ended December 31, 2010 were 3,761 MBoe, an 8% decrease from net production of 4,106 MBoe for 2009. Our net production volumes decreased 345 MBoe over 2009 net production volumes mainly due to general decline in the offshore wells with limited development activities in 2010. Our average oil sales prices, without the effect of realized derivatives, increased $16.37 per Bbl to $75.26 per Bbl for the year ended December 31, 2010 from $58.89 per Bbl for the year ended December 31, 2009. Giving effect to our derivative transactions in both periods, our oil prices decreased $4.00 per Bbl to $75.66 per Bbl for the year ended December 31, 2010 from $79.66 per Bbl for the year ended December 31, 2009. Our lease operating expenses increased $2.10 per Boe, or 33%, to $8.39 per Boe for the year ended December 31, 2010 from $6.29 per Boe for the year ended December 31, 2009 mainly due to new offshore production.

Net production volumes for the year ended December 31, 2009 were 4,106 MBoe, a 25% increase from net production of 3,292 MBoe for 2008. Our net production volumes increased 814 MBoe over 2008 net production volumes mainly due to the successful drilling and completion of offshore wells in Louisiana and United States federal waters. Our average oil sales prices, without the effect of realized derivatives, decreased $42.55 per Bbl to $58.89 per Bbl for the year ended December 31, 2009 from $101.44 per Bbl for the year ended December 31, 2008. Giving effect to our derivative transactions in both periods, our oil prices decreased $16.02 per Bbl to $79.66 per Bbl for the year ended December 31, 2009 from $95.67 per Bbl for the year ended December 31, 2008. Our lease operating expenses increased $0.46 per Boe, or 8%, to $6.29 per Boe for the year ended December 31, 2009 from $5.83 per Boe for the year ended December 31, 2008 mainly due to new offshore production.

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

	Average Net Daily Production for the Year Ended December 31, 2010						Average Net Daily Production for the Year Ended December 31, 2009
	Bbls		Mcf		Boe		Bbls		Mcf		Boe
Offshore
Federal waters(1)		1,042		13,822		3,346		1,087		19,829		4,392
State waters(2)		1,242		14,402		3,642		1,271		15,792		3,903
Onshore
Texas, Louisiana and Mississippi(3)		544		16,084		3,225		469		14,491		2,884
Resource Plays
Oklahoma		92		—		92		71		—		71
Total		2,920		44,308		10,305		2,898		50,112		11,250

(1) Our core areas of production in the United States federal waters in the Gulf of Mexico are the West Cameron 368 Field and the Ship Shoal 154 Field.

(2) Our core area of production in the state waters in the Gulf of Mexico is in the Breton Sound 53 Field.

(3) Our core areas of production in Texas are the Eocene Yegua/Cook Mountain trend and the Briscoe Bayou prospect and our core areas of production in Louisiana are in the Lower Miocene trend.

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Productive Wells

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

	Oil Wells				Natural Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Offshore
Federal waters(1)		11.0		8.3		4.0		3.6		15.0		11.9
State waters(2)		5.0		3.1		8.0		6.4		13.0		9.5
Onshore
Texas, Louisiana and Mississippi(3)		3.0		1.9		12.0		6.6		15.0		8.5
Resource Plays
Oklahoma		24.0		12.0		—		—		24.0		12.0
Total		43.0		25.3		24.0		16.6		67.0		41.9

(1) Our core areas of production in the United States federal waters in the Gulf of Mexico are the West Cameron 368 Field and the Ship Shoal 154 Field.

(2) Our core area of production in the state waters in the Gulf of Mexico is in the Breton Sound 53 Field.

(3) Our core areas of production in Texas are the Eocene Yegua/Cook Mountain trend and the Briscoe Bayou prospect and our core areas of production in Louisiana are in the Lower Miocene trend.

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

Marketing and Customers

We generally sell our natural gas and oil at the wellhead to marketing companies. All of our offshore and shallow water production and onshore gas production is connected to a pipeline. Generally our onshore oil production is stored in tanks and delivered to market by trucks.

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

We sold natural gas and oil production representing 10% or more of our natural gas and oil revenues for the six months ended June 30, 2011 and 2010 and the years ended December 31, 2010, 2009 and 2008 to the following customers as listed below. In the exploration, development, and production business, production is normally sold to relatively few customers. However, based on the current demand for natural gas and oil, management believes that the loss of any major customers would not have a material adverse effect on operations.

	Six Months Ended June 30,						Year Ended December 31,
	2011			2010			2010			2009			2008
Texon, L.P.		42	%		46	%		45	%		45	%		39	%
Adams Resources Marketing, Ltd.		10	%		24	%		20	%		29	%		23	%
Superior Natural Gas Corporation		16	%		11	%		12	%		9	%		11	%
Upstream Energy Services		7	%		9	%		9	%		12	%		25	%
Eastex Crude Company		12	%		6	%		7	%		4	%		0	%

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Delivery Commitments

In order to get better pricing from our intrastate markets, we have committed gas production for several of our onshore properties to various purchasers. We have one gas commitment for life of lease on a Louisiana onshore property that produced approximately 9% and 8% of our daily production during June 2011 and December 2010, respectively. Four of our wells located onshore in Texas have gas commitments through April 30, 2012, and produced approximately 9% and 9% of our production during June 2011 and December 2010, respectively. The remaining gas production is being sold pursuant to month-to-month marketing arrangements which require either a 30 day or 60 day notice by both parties. All of our oil is being sold pursuant to month-to-month marketing contracts that are terminable by either party with a 30 day notice. None of the commitments have required minimum daily production volumes.

Competition

We encounter intense competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources who have been engaged in the oil and natural gas business for much longer than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Intellectual Property

The majority of RAAM Global’s 3-D seismic data is licensed from the owners of the data under long-term, non-exclusive agreements. These licenses range in term from 25 to 50 years. At times, licensed 3-D data is re-processed on a proprietary basis by RAAM. This reprocessed data is uniquely controlled by RAAM Global, but is still subject to the underlying license agreements, with RAAM Global having no ownership rights. RAAM Global is a majority owner of the JASPO 3-D survey covering certain lands in the upper Texas Gulf Coast. Several successful wells have been drilled on this 3-D survey. RAAM Global does not have any current plans to sell its ownership in this survey, but may grant non-exclusive licenses to third parties in the future.

Offices

We own a 19,673 square foot building in The Woodlands, Texas, of which we occupy 13,115 square feet. We lease 7,000 square feet of office space in Lexington, Kentucky from one of our affiliates that expires on December 31, 2015. We also lease 16,206 square feet of office space in New Orleans, Louisiana, which expires on May 31, 2015. We recently entered into a short-term lease for 3,900 square feet in Covington, Louisiana to provide temporary offices in case of an evacuation for our New Orleans employees. The initial term is for a six month period beginning August 15, 2011 until February 14, 2012 with the option to renew the lease for six additional months until August 14, 2012. We also lease 3,679 square feet of office space in Denver, Colorado, which expires on April 30, 2014.

Employees

As of June 30, 2011, we had 63 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services.

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Title to Properties

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

Seasonality

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

Legal Proceedings

In the ordinary course of business, we are involved in various pending or threatened legal actions. While management is unable to predict the ultimate outcome of these actions, it believes that any ultimate liability arising from these actions will not have a material adverse effect on our consolidated financial position, results of operations or cash flows; however, because of the inherent uncertainty of litigation, we cannot provide assurance that the resolution of any particular claim or proceeding to which we are a party will not have a material adverse effect on our financial position, results of operation or cash flows for the period in which the resolution occurs.

We are currently pursuing options to satisfy a Compliance Order issued by the Louisiana Department of Environmental Quality in 2010 with respect to discharges of produced water from an operated production facility in Louisiana coastal waters; one of the options being considered is conversion of an existing well into an injection well for disposal of produced water, which remedy, if pursued, is anticipated to cost approximately $5.1 million to implement and complete by June 30, 2012.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

There were no changes in or disagreements on any matters of accounting principles or financial statement disclosure between us and our independent auditors during our two most recent fiscal years or any subsequent interim period.

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Environmental Matters and Regulation

Our exploration, development and production operations are subject to various federal, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and remediation requirements for the oil and gas industry could have a significant impact on our operating costs. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or new interpretations of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on our financial condition or results of operations, we cannot provide any assurance that we will be able to remain in compliance in the future with respect to existing or new laws and regulations or the terms and conditions required of required permits or that such future compliance will not have a material adverse effect on our business and operating results.

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

Comprehensive Environmental Response, Compensation, and Liability Act

The Comprehensive Environmental Response, Compensation, and Liability Act (the “CERCLA”), also known as the “Superfund” law, and comparable state statutes impose joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substances and may have disposed of these wastes at disposal sites owned and operated by others.

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We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.

Solid and Hazardous Waste Handling

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

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to RCRA, CERCLA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed 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 or mitigate existing contamination.

Clean Water Act

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

Safe Drinking Water Act

The Safe Drinking Water Act (the “SWDA”) regulates, among other things, underground injection operations. The injection of fluids (other than diesel fuels) and propping agents pursuant to hydraulic fracturing

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operations is not regulated under the SDWA. The hydraulic fracturing process is typically regulated by state oil and gas commissions or other similar state agencies. Legislation has been proposed in Congress, however, to make the injection of oil and gas well completion fluids subject to the SDWA. If enacted, this legislation could impose on our hydraulic fracturing operations additional permit and financial assurance requirements, well construction specifications, monitoring, reporting and recordkeeping obligations, and more stringent plugging and abandonment requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, federal legislation has been proposed that would require the disclosure of the chemicals within the hydraulic fluids. In addition, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents on regulating requirements for companies that plan to conduct hydraulic fracturing using diesel. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing a number of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy and the U.S. Government Accountability Office are studying different aspects of how hydraulic fracturing might adversely affect the environment, and the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. A committee of the United States House of Representatives also has conducted an investigation of hydraulic fracturing practices. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or under newly established legislation. In addition, some states, including Texas, have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Texas passed a law that requires, subject to certain trade secret protections, disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. Louisiana is considering adoption of a regulation that would impose similar disclosure requirements. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. In addition, disclosure requirements could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water.

Oil Pollution Act

The primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”) which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters, including the Outer Continental Shelf (“OCS”) or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several, strict liability, without regard to fault, to each liable party all containment and for oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. As a result of the BP Deepwater Horizon incident, legislation has been proposed in Congress to increase the minimum level of financial responsibility to $300 million or more. If OPA is amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing

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financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located on the OCS or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if there were to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

Air Emissions

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

On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

National Environmental Policy Act

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

Greenhouse Gas Emissions Controls

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on

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these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

Certain of our oil and natural gas operations may be subject to such greenhouse gas reporting requirements and, if so, we will monitor, as necessary, our emissions to make such required reports when due in 2012. While we believe that we will be able to substantially comply with such reporting requirements without any material adverse effect to our financial condition, since such reporting requirements with respect to greenhouse gas emissions are new in the oil and gas industry, there can be no assurance that such requirements will not develop into more stringent and costly obligations that may have a significant impact on our operating costs.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

OSHA and Other Laws and Regulation on Employee Health and Safety

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

Endangered Species Act

The federal Endangered Species Act, as amended, the ESA, restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2010, 2009 and 2008. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2010 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact our business activities, financial condition or results of operations.

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Other Regulation of the Oil and Natural Gas Industry

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

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

Drilling and Production

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

• the location of wells;

• the method of drilling and casing wells;

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

• the plugging and abandoning of wells.

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

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

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

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, the BOEMRE or other appropriate federal or state agencies.

Transportation of Oil

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

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

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

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in the adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers

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and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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

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

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission, or the CFTC. See below the discussion of “Other federal laws and regulations affecting our industry — Energy Policy Act of 2005.” Should we violate applicable anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations are currently required to report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires collection by FERC of transactional information from certain natural gas market participants. Certain physical natural gas buyers and sellers must report information regarding their reported transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. See below the discussion of “Other federal laws and regulations affecting our industry — FERC Market Transparency Rules.”

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

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a

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particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

State Natural Gas Regulation

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

Other Federal Laws and Regulations Affecting Our Industry

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005, or the EPAct 2005. EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an antimanipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. The FERC rule implementing the anti-manipulation provision of EPAct 2005 makes it unlawful for any entity, directly or indirectly, 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, (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

FERC Market Transparency Rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility

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of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.

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

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DESCRIPTION OF NOTES

You can find the definitions of certain terms used in this description under the subheading “— Certain Definitions.” In this description, the term “Company,” “us” or “we” refers only to RAAM Global Energy Company (including its permitted successors and assigns) and not to any of its subsidiaries.

The old notes were, and the new notes will be, issued under an indenture among the Company, the Guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee. The terms of the notes will include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended.

The following description is a summary of the material provisions of the indenture and the registration rights agreement. It does not restate those agreements in their entirety. We urge you to read the indenture and the registration rights agreement because they, and not this description, define your rights as holders of the new notes. Certain defined terms used in this description but not defined below under “— Certain Definitions” have the meanings assigned to them in the indenture.

The registered holder of a new 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 Guarantees

The New Notes

The new notes:

• will be senior secured obligations of the Company;

• will be issued in this exchange offer in an aggregate principal amount of up to $50.0 million, subject to the Company’s ability to issue additional notes under certain circumstances;

• will rank equally in right of payment with all other existing and future senior obligations of the Company, including debt borrowed under any Credit Facilities, and senior in right of payment of all Indebtedness that by its terms is subordinated to the notes;

• will be secured by second priority Liens on the Collateral described herein, subject to certain exceptions and Permitted Liens; and

• will be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by all of the Company’s existing and future Domestic Subsidiaries (other than Unrestricted Subsidiaries, as discussed herein) as set forth herein.

However, pursuant to the terms of the Intercreditor Agreement (as defined herein), the liens on the Collateral securing the new notes will be junior and subordinate to the liens on the Collateral securing the Senior Credit Agreement and additional permitted first lien Indebtedness (including permitted refinancings respectively thereof) and as such the new notes will be effectively subordinated, to the extent of the value of the Collateral, to all First Lien Obligations (as defined herein), including the Senior Credit Agreement and additional permitted first lien Indebtedness (including permitted refinancings respectively thereof), to the extent of the assets securing such First Lien Obligations. See “Risk Factors — Risks Relating to the Notes — The Liens on the collateral securing the notes will be junior and subordinate to the liens on the collateral securing our obligations under our Senior Credit Agreement and any other permitted additional first lien indebtedness. If there is a default, the value of the collateral may not be sufficient to repay both the lenders under our Senior Credit Agreement and holders of other permitted additional first lien indebtedness and the holders of the notes.” and “— Collateral —Intercreditor Agreement.” As of June 30, 2011, there was no borrowing outstanding under our Senior Credit Agreement.

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The Guarantees

The new notes will be fully and unconditionally guaranteed, jointly and severally, by each of the Company’s present Restricted Subsidiaries and its future Restricted Subsidiaries that guarantee Indebtedness of the Company under a Credit Facility.

The Guarantees of the new notes will:

• be a senior secured obligation of such Guarantor;

• rank equally in right of payment with all other existing and future senior obligations of such Guarantor, including debt borrowed under any Credit Facilities (including the Senior Credit Agreement), and senior in right of payment to all Indebtedness that by its terms is subordinated to the Guarantee of such Guarantor; and

• be secured by second priority Liens on the Collateral described herein, subject to certain exceptions and Permitted Liens.

However, pursuant to the terms of the Intercreditor Agreement (as defined herein), the liens on the Collateral securing the Guarantees will be junior and subordinate to the liens on the Collateral securing the Senior Credit Agreement and additional permitted first lien Indebtedness (including permitted refinancings respectively thereof) and as such the new notes will be effectively subordinated, to the extent of the value of the Collateral, to all First Lien Obligations (as defined herein), including the Senior Credit Agreement and additional permitted first lien Indebtedness (including permitted refinancings respectively thereof), to the extent of the assets securing such First Lien Obligations. See “Risk Factors — Risks Relating to the Notes — The Liens on the collateral securing the notes will be junior and subordinate to the liens on the collateral securing our obligations under our Senior Credit Agreement and any other permitted additional first lien indebtedness. If there is a default, the value of the collateral may not be sufficient to repay both the lenders under our Senior Credit Agreement and holders of other permitted additional first lien indebtedness and the holders of the notes.” and “— Collateral — Intercreditor Agreement.” As of June 30, 2011, we had no borrowings outstanding under our Senior Credit Agreement.

As of the date of the indenture, all of our subsidiaries were “Restricted Subsidiaries.” However, under the circumstances described below under the subheading “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries,” we will be permitted to designate certain of our 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

The Company has issued notes with an initial maximum aggregate principal amount of $50.0 million (excluding the aggregate principal amount of $150.0 million in initially issue notes). The Company may issue additional notes from time to time after this offering. Any offering of additional notes is subject to the covenant described below under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock.” Any old notes, the new notes and any additional notes subsequently issued under the indenture, together with any Exchange Notes, will be treated as a single class for all purposes under the indenture, including without limitation, waivers, amendments, redemptions and offers to purchase. The Company will issue notes in denominations of $2,000 and integral multiples of $1,000 in excess thereof. The notes will mature on October 1, 2015.

Interest on the notes will accrue at the rate of 12.50% per annum. Interest will be payable semi-annually in arrears on April 1 and October 1, commencing on April 1, 2011. Interest on overdue principal, interest and Additional Interest, if any, will accrue at a rate that is 1% higher than the applicable rate on the notes. The Company will make each interest payment to the holders of record on the immediately preceding March 15 and September 15.

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Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Additional Interest may accrue on the old notes as liquidated damages in certain circumstances described below under “— Registration Rights; Additional Interest.” Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Methods of Receiving Payments on the Notes

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

Paying Agent and Registrar for the Notes

The trustee will initially act as paying agent and registrar. The Company may change the paying agent or registrar without prior notice to the holders of the notes, and the Company or any of its domestic Subsidiaries may act as paying agent.

Transfer and Exchange

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

Guarantees

Initially, all of the Company’s Subsidiaries that guarantee our Senior Credit Agreement will guarantee the notes. The notes will be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis, by each of the Company’s future Restricted Subsidiaries that guarantee Indebtedness of the Company under any Credit Facility. See “— Certain Covenants — Additional Guarantees.”

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

A Guarantor may not sell or otherwise dispose of all or substantially all of its properties or assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person), another Person, other than the Company 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 properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than the Guarantor) unconditionally assumes all the obligations of that Guarantor under the indenture and the Guarantee, pursuant to a supplemental indenture substantially in the form specified in the indenture, under the notes, the indenture and that Guarantor’s Guarantee on terms set forth therein; or

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

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The Guarantee of a Guarantor will be released:

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

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

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

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

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

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

Collateral

The notes and the Guarantees will be secured by second priority liens on all property and assets that from time to time are subject to a Lien securing the First Lien Obligations, except as described herein (the “Collateral”). As of the date hereof, the Collateral includes substantially all of the assets of the Company and its Guarantors other than Excluded Collateral.

The Collateral will not include the following:

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

(2) any 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 then Rule 3-16 or Rule 3-10 of Regulation S-X under the Securities Act would require the filing of separate financial statements of such Subsidiary with the SEC (or any other governmental agency) in connection with a registration of the notes under the Securities Act;

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

(4) fixed or capital assets owned by the Company 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 equipment;

(5) Collateral that has been released in accordance with the Intercreditor Agreement or the indenture; and

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(6) certain other property or assets owned by the Company or any Guarantor that is not secured by Liens for the benefit of any First Lien Obligations; (such excluded assets collectively referred in the prospectus as the “Excluded Collateral”).

Intercreditor Agreement

We negotiated an Intercreditor Agreement among the First Lien Collateral Agent, on behalf of the First Lien Secured Parties (including the lenders under our Senior Credit Agreement), the trustee as the Collateral Agent, on behalf of the Second Lien Secured Parties (including the holders of the notes), the Company, Century Exploration New Orleans, LLC and Century Exploration Houston, LLC, which, among other things, defines the rights of the trustee, the First Lien Collateral Agent and the First Lien Secured Parties (including the lenders under our Senior Credit Agreement) and the Collateral Agent and the Second Lien Secured Parties (including the holders of the Notes) with respect to the Collateral.

The following description is a summary of the material provisions of the Intercreditor Agreement. It does not restate the Intercreditor Agreement in its entirety. We urge you to read the Intercreditor Agreement because it, and not this description, defines your rights as holders of the new notes.

First Lien Obligations; Notes Effectively Subordinated to First Lien Obligations

The Intercreditor Agreement provides that all Indebtedness under the Senior Credit Agreement permitted pursuant to the covenant described under the caption “Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock,” together with all other First Lien Obligations (as defined herein) will be secured by First Priority Liens (as defined herein) on the Collateral, which Liens will be contractually senior to the Liens thereon that secure the notes and the Guarantees. As a result, the Second Lien Obligations will be effectively subordinated to the First Lien Obligations to the extent of the value of the Collateral. “First Lien Obligations” means, collectively, (i) all principal of and interest and premium (if any) on all loans made pursuant to the First Lien Agreement and any other Indebtedness incurred pursuant to a Credit Facility to the extent that such Indebtedness is secured equally and ratably with the other First Lien Obligations by the Liens on the Collateral, (ii) all reimbursement obligations (if any) and interest thereon with respect to any letter of credit or similar instruments issued pursuant to the First Lien Agreement, (iii) all Hedging Obligations of the Company or any Guarantor, and (iv) all fees, expenses and other amounts payable from time to time pursuant to the First Lien Debt Documents.

“First Lien Agreement” means (i) the Senior Credit Agreement and (ii) any other credit agreement, loan agreement, note agreement, promissory note, indenture or other agreement or instrument evidencing or governing the terms of any indebtedness or other financial accommodation that has been incurred to extend, replace, refinance or refund in whole or in part the indebtedness and other obligations outstanding under the Senior Credit Agreement or any other agreement or instrument referred to in this clause (ii).

Payment of Second Lien Obligations

The Intercreditor Agreement does not prohibit the Collateral Agent, on behalf of the Second Lien Secured Parties, from receiving regularly scheduled payments of principal and interest with respect to the Second Lien Obligations.

Relative Priorities

The Intercreditor Agreement provides that, notwithstanding the date, manner or order of grant, attachment or perfection of any Lien securing Second Lien Obligations, including the notes or the Guarantees (a “Second Priority Lien”) or any Lien on Collateral securing the First Lien Obligations (a “First Priority Lien”), and notwithstanding any provision of the Uniform Commercial Code of any applicable jurisdiction or any other applicable law or the provisions of any Debt Document or any other circumstance whatsoever, each Agent, for itself and on behalf of the Secured Parties on whose behalf it acts in such capacity therefor, will agree that, so

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long as the First Lien Obligations have not been discharged as set forth in the Intercreditor Agreement (such discharge, the “Discharge of First Lien Obligations”), (a) any First Priority Liens then or thereafter held by or for the benefit of any First Lien Secured Party will be senior in right, priority, operation, effect and all other respects to any and all Second Priority Liens and (b) any Second Priority Liens then or thereafter held by or for the benefit of any Second Lien Secured Party will be junior and subordinate in right, priority, perfection, operation, effect and all other respects to any and all First Priority Liens, and the First Priority Liens will be and remain senior in right, priority, perfection, operation, effect and all other respects to any Second Priority Liens for all purposes.

Prohibition on Contesting Liens; Additional Collateral

The Intercreditor Agreement provides that (a) no Second Lien Secured Party will object to or contest, in any proceeding (including any insolvency or liquidation proceeding), the priority, validity, extent, perfection, or enforceability of any First Priority Lien; and (b) so long as the Discharge of First Lien Obligations has not occurred, neither the Company nor any Guarantor shall grant or permit, and no Second Lien Secured Creditor shall acquire or hold, any Lien on any assets of the Company or any Guarantor securing any Second Lien Obligation which assets are not also subject to a First Priority Lien granted pursuant to the First Lien Debt Documents in favor of the First Lien Collateral Agent for the benefit of the First Lien Secured Creditors securing the First Lien Obligations.

Exercise of Rights and Remedies; Standstill

The Intercreditor Agreement provides that the First Lien Collateral Agent and the other holders of First Lien Obligations will, at all times prior to the payment in full in cash of the First Lien Obligations, have the exclusive right to enforce rights and exercise remedies (including any right of setoff) with respect to the Collateral, or to commence or seek to commence any action or proceeding with respect to such rights or remedies, in each case, without any notification to, consultation with or the consent of the Collateral Agent or any other Second Lien Secured Party, and no Second Lien Secured Party will have any such right; provided, however, that (i) the Second Lien Secured Parties will be entitled to take actions that unsecured creditors are entitled to take (which in any event cannot be inconsistent with the limitations imposed on the Second Lien Secured Parties in any such Intercreditor Agreement) and (ii) 180 days following notice from the Collateral Agent to the First Lien Collateral Agent that either (x) the Second Lien Obligations have become due in full as a result of acceleration or otherwise (and such acceleration has not been rescinded) or (y) any payment or insolvency event of default has occurred and is then continuing under the indenture or the other documents executed in connection therewith, and in each case so long as neither the First Lien Collateral Agent nor any other first lien creditor is not diligently pursuing an enforcement action with respect to all or a material portion of the collateral or diligently attempting to vacate any stay or prohibition against such exercise (the “Standstill Period”), the Second Lien Secured Parties may enforce or exercise any rights or remedies permitted by the Intercreditor Agreement with respect to any Collateral.

In addition, the Intercreditor Agreement provides that the Collateral Agent and the Second Lien Secured Parties agree, except as contemplated in the prior sentence, (x) not take any enforcement action with respect to any Collateral or exercise rights with respect to a Lien securing a Second Lien Obligation, (y) will not contest, protest or object to, or take any other action that may impair, any collection or foreclosure proceeding or action with respect to the Collateral brought by the First Lien Collateral Agent or any First Lien Secured Parties or any other exercise by the First Lien Collateral Agent or any First Lien Secured Party, of any rights and remedies under the First Lien Debt Documents or otherwise, and (z) will not object to the forbearance by the First Lien Collateral Agent or the First Lien Secured Parties from bringing or pursuing any collection or foreclosure proceeding or action or any other exercise of any rights or remedies relating to the Collateral.

Purchase Option

The Intercreditor Agreement provides that if an event of default under the First Lien Debt Documents has occurred and is continuing, and as a result of such event of default under the First Lien Debt Documents (i) the First Lien Obligations have been accelerated, (ii) the Second Lien Obligations have been accelerated, (iii) any

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insolvency or liquidation proceeding has been commenced (or is then occurring) with respect to any of us or any borrower under our Senior Credit Agreement or (iv) the administrative agent under our Senior Credit Agreement (A) is pursuing any enforcement action (including any demand for payment or acceleration thereof, the exercise of any rights and remedies with respect to any Collateral securing such obligations or the commencement or prosecution of enforcement of any of the rights and remedies under, as applicable, the First Lien Debt Documents or the Indenture Documents, or applicable law, including without limitation the exercise of any rights of set-off or recoupment, and the exercise of any rights or remedies of a secured creditor under the Uniform Commercial Code of an applicable jurisdiction or under the Bankruptcy Code) with respect to the Collateral or (B) proposes any release, sale or other disposition not otherwise permitted under the Indenture Documents with respect to any material portion of the Collateral, in each case of this subsection (iv) that would have the effect of releasing Liens securing the Second Lien Obligations (each, a “Trigger Event”), then the Second Lien Secured Parties shall have the right and option to purchase the entire aggregate amount (but not less than the entire aggregate amount) of outstanding First Lien Obligations (including unfunded and unterminated commitments) at a price equal to par, plus all accrued and unpaid interest, fees and other amounts (other than contingent indemnification obligations) of First Lien Obligations, together with cash collateral for all outstanding Letters of Credit (as defined in the Senior Credit Agreement) in an amount equal to 105% of the undrawn and available amount of such Letters of Credit outstanding under the Senior Credit Agreement, and a payment for all then outstanding Hedging Obligations at a price equal to the sum of any unpaid amounts then due in respect of such Hedging Obligations plus or minus a net amount reasonably and customarily quoted by the First Lien Secured Parties party to such Hedging Obligation that would be paid to assign or novate each such Hedging Obligation in the ordinary course of its business. Such sale shall be without warranty or representation or recourse other than as provided in standard LSTA documentation for par trades. To exercise the option following any Trigger Event, the Collateral Agent shall deliver a written notice to the First Lien Collateral Agent, which notice must be given within 60 days after the occurrence of any such Trigger Event and shall be deemed an irrevocable exercise of its option to purchase the First Lien Obligations. Upon delivery of such notice, the Second Lien Secured Parties shall be obligated to purchase, and the First Lien Creditors shall be obligated to sell, the entire aggregate amount of outstanding First Lien Obligations (other than contingent indemnification obligations) for the purchase price described above within twenty (20) days after delivery of such notice.

Automatic Release of Second Priority Liens

The Intercreditor Agreement provides that, upon any release, sale or disposition of Collateral, or the release the Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC or a Guarantor from its obligations under its guaranty of the First Lien Obligations which guaranty is secured by a lien on Collateral, permitted or consented to pursuant to the terms of the First Lien Debt Documents that results in the release of the First Priority Liens on any Collateral (including without limitation any sale or other disposition pursuant to any enforcement action) (in each case, a “Release”), the Liens of the Collateral Agent and the Second Lien Secured Parties on such Collateral (but not on any proceeds of such Collateral not required to be paid to the First Lien Secured Parties, except to the extent that the First Priority Liens have also been released on such proceeds of such Collateral (other than in the event that such release occurs in the context of the Discharge of First Lien Obligations)), and the Obligations of the Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC or such Guarantor under any guaranty of the Second Lien Obligations, will be automatically, unconditionally and simultaneously released, and the Collateral Agent and the other Second Lien Secured Parties will promptly execute and deliver such release documents as the First Lien Collateral Agent may reasonably request to effectively confirm such Release and as may be otherwise reasonably required to consummate such Release and any related transactions.

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Waterfall

The Intercreditor Agreement provides that any Collateral or proceeds thereof received by any Secured Party in connection with any sale, collection or other disposition of such Collateral upon the enforcement or exercise of any right or remedy (including any right of setoff) whether or not pursuant to an insolvency proceeding will be applied as follows:

• first, to the First Lien Obligations in accordance with the First Lien Debt Documents; and

• second, after the Discharge of the First Lien Obligations has occurred, in accordance with the Second Lien Debt Documents.

Payment Over

The Intercreditor Agreement provides that so long as the Discharge of First Lien Obligations has not occurred, any Collateral or any proceeds thereof received by the Collateral Agent or any other Second Lien Secured Party in violation of the Intercreditor Agreement with respect to the Collateral, or otherwise, will be segregated and held in trust and forthwith transferred or paid over to the First Lien Collateral Agent for the benefit of the First Lien Secured Parties in the same form as received, together with any necessary endorsements and the Second Lien Secured Parties authorize the First Lien Collateral Agent to make any such endorsements as agent for the Collateral Agent.

Insolvency and Liquidation Proceedings

The Intercreditor Agreement provides that:

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

(i) will not file any pleadings or motions, take any position at any hearing or proceeding of any nature, or otherwise take any action whatsoever, in each case in respect of any Second Lien Obligations or the Collateral, including, without limitation, with respect to the determination of First Lien Obligations, any Liens or claims held by the First Lien Collateral Agent (including the validity and enforceability thereof) or any other First Lien Secured Creditor or the value of any claims of such parties under Section 506(a) of the Bankruptcy Code or otherwise, other than, proofs of claim in an insolvency proceedings subject to the term sand limitations contained in the Intercreditor Agreement;

(ii) will be deemed to have consented to, will raise no objection to, nor support any other Person objecting to, any sale, use or lease of cash or other collateral under the Bankruptcy Code or to any financing which the First Lien Secured Parties or any third party (subject to the consent, or nonobjection, by the First Lien Creditors) desires to provide to the Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC or any Guarantor (a “DIP Financing”);

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

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

(v) to the extent that the Collateral Agent or any Second Lien Secured Creditor has or acquires rights under Section 363 or Section 164 of the Bankruptcy Code with respect to the Second Lien Obligations or any of the Collateral, the Collateral Agent agrees, on behalf of itself and the other

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Second Lien Secured Creditors, not to assert any of such rights without the prior written consent of the First Lien Collateral Agent; provided that if requested by the First Lien Collateral Agent, the Collateral Agent shall timely exercise such rights in the manner requested by the First Lien Collateral Agent, including any rights to payments in respect of such rights;

(b) the Collateral Agent, for itself and on behalf of the other Second Lien Secured Parties, will agree that no Second Lien Secured Party may object to or contest, or support any other Person in objecting to or contesting, (i) any request by the First Lien Collateral Agent or any other First Lien Secured Party for adequate protection in respect of any First Lien Obligations, (ii) any objection, based on a claim of a lack of adequate protection in respect of any First Lien Obligation, by the First Lien Collateral Agent or any other First Lien Secured Party to any motion, relief, action or proceeding, or (iii) the payment of interest, fees, expenses or other amounts to the First Lien Agent or any other First Lien Secured Creditor under section 506(b) or 506(c) of the Bankruptcy Code or otherwise.

(c)(x) the Collateral Agent and the Second Lien Secured Creditors, may seek, support, accept or retain adequate protection (A) only if the First Lien Secured Creditors are granted adequate protection that includes replacement Liens on additional collateral and super priority claims and the First Lien Secured Creditors do not object to the adequate protection being provided to the First Lien Secured Creditors and (B) solely in the form of (a) a replacement Lien on such additional collateral, subordinated to the Liens securing the First Lien Obligations and any DIP Financing on the same basis as the other Second Priority Liens are subordinated to the First Priority Liens under any such Intercreditor Agreement and (b) super priority claims junior in all respects to the super priority claims granted to the First Lien Secured Creditors, and (y) in the event the Collateral Agent, on behalf of itself and the Second Lien Secured Creditors, receives adequate protection, including in the form of additional collateral, then the Collateral Agent, on behalf of itself or any of the Second Lien Secured Creditors, agrees that the First Lien Secured Creditors shall have a senior Lien and claim on such adequate protection as security for the First Lien Obligations and that any Lien on any additional collateral securing the Second Lien Obligations shall be subordinated to such Liens on such collateral securing the First Lien Obligations and any DIP Financing and any other Liens granted to the First Lien Secured Creditors as adequate protection, with such subordination to be on the same terms that the other Liens securing the Second Lien Obligations are subordinated to the Liens securing the First Lien Obligations under the Intercreditor Agreement.

Relief from the Automatic Stay

Prior to the expiration of the Standstill Period, the Collateral Agent, for itself and on behalf of the other Second Lien Secured Parties, agrees that, no Second Lien Secured Party may, without the prior written consent of the First Lien Collateral Agent, seek or request relief from or modification of the automatic stay or any other stay in any insolvency or liquidation proceeding or take any action in derogation thereof, in each case in respect of any part of the Collateral or any Second Priority Lien.

Post-Petition Interest

The Intercreditor Agreement provides that neither the Collateral Agent nor any other Second Lien Secured Party may oppose or seek to challenge any claim by the First Lien Collateral Agent or any other First Lien Secured Party for allowance or payment in any insolvency or liquidation proceeding of First Lien Obligations consisting of post-petition interest, fees or expenses.

Postponement of Subrogation

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

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Judgment Creditors

The Intercreditor Agreement provides that in the event that any Second Lien Secured Party becomes a judgment Lien creditor in respect of Collateral as a result of its enforcement of its rights as an unsecured creditor, such judgment Lien shall be subject to the terms of the Intercreditor Agreement for all purposes (including in relation to the First Priority Liens and the First Lien Obligations) to the same extent as all other Liens securing the Second Lien Obligations subject to the Intercreditor Agreement.

Second Lien Creditors’ Rights as Unsecured Creditor

The Intercreditor Agreement provides that, subject to the terms and provisions of the Intercreditor Agreement, the Collateral Agent and the other Second Lien Secured Parties may, in accordance with the Debt Documents relating to the Second Lien Obligations and applicable law, enforce rights and exercise remedies against the Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC or a Guarantor as unsecured creditors prior to the end of the Standstill Period; provided that no such action is otherwise inconsistent with the terms of the Intercreditor Agreement.

Plans of Reorganization

The Intercreditor Agreement provides that no Second Lien Secured Party shall support or vote in favor of any plan of reorganization (and each shall be deemed to have voted to reject any plan of reorganization) unless such plan (i) pays off, in cash in full, all First Lien Obligations or (ii) is accepted by the class of holders of First Lien Obligations voting thereon and is supported by the First Lien Collateral Agent.

DIP Financings

The Intercreditor Agreement provides that the Collateral Agent, for itself and on behalf of the other Second Lien Secured Parties, and each of the Second Lien Secured Parties by purchasing Notes, agrees with each of the First Lien Secured Parties that neither the Collateral Agent, nor any other Second Lien Secured Party, will, nor will any of them permit any of their respective affiliates to, without the prior written consent of the First Lien Collateral Agent on behalf of the “Majority Lenders” (as defined in the First Lien Agreement), extend directly or indirectly all or any portion of any DIP Financing; provided, however, the foregoing shall not restrict the right of any Second Lien Secured Party to propose all or a portion of a DIP Financing to the Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC or any Guarantors in any Insolvency Proceeding. In the event First Lien Collateral Agent, on behalf of such Majority Lenders (as defined in the First Lien Agreement), shall consent to any such DIP Financing by Second Lien Secured Parties, and any Second Lien Secured Party or an Affiliate of a Second Lien Secured Party shall provide any DIP Financing to the Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC or any Guarantors, such Second Lien Secured Party agrees to cause any post petition Liens, any replacement Liens, any super priority Liens, any adequate protection Liens and any administrative expenses that it obtains in connection therewith to be subordinated to the First Priority Liens upon the terms of the Intercreditor Agreement.

Collateral Agreements; Amendments; Releases

The Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, the Guarantors and the Collateral Agent have entered into one or more Collateral Agreements and other documents granting, in favor of the Collateral Agent for the benefit of the Collateral Agent and the holders of the Second Lien Obligations, Second Priority Liens on the Collateral securing the Second Lien Obligations, subject to certain exceptions and subject to Permitted Liens. The Intercreditor Agreement provides, subject to limitations (if any) set forth therein, that, in the event the First Lien Collateral Agent or the other First Lien Secured Parties and the relevant grantors enter into any amendment, waiver or consent in respect of any of the documents evidencing or giving rise to Liens securing the First Lien Obligations for the purpose of adding to, or deleting from, or waiving or consenting to any departures from any provisions of, any such document or changing in any manner the rights

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of any parties thereunder, then such amendment, waiver or consent shall apply automatically to any comparable provision of the indenture and the comparable Collateral Agreements evidencing or giving rise to Liens securing the Second Lien Obligations without the consent of the trustee, the Collateral Agent, the holders of notes or the other Second Priority Secured Parties and without any action by any of the foregoing, provided, that (other than with respect to amendments, modifications or waivers that secure additional extensions of credit and add additional secured creditors and do not violate the express provisions of the Indenture), (A) any such amendment, waiver or consent that materially and adversely affects the rights of the Second Lien Secured Creditors and does not affect the First Lien Secured Creditors in a like or similar manner shall not apply to the Second Lien Security Documents without the consent of the Collateral Agent and (B) notice of such amendment, waiver or consent shall be given to the Collateral Agent no later than 30 days after its effectiveness, provided that the failure to give such notice shall not affect the effectiveness and validity thereof.

Restrictions on Second Lien Documents and Amendments to Second Lien Documents

The Intercreditor Agreement provides, unless a similar amendment, supplement or modification to the applicable First Lien Debt Document has been, or is concurrently being, made, without the prior written consent of the First Lien Collateral Agent, the indenture may not be amended, supplemented, modified, increased, restated, refinanced or replaced to the extent such amendment, supplement, modification, restatement, refinancing or replacement, or the terms of any new indenture, would (i) contravene the provisions of the Intercreditor Agreement, (ii) increase the interest rate on the notes issued thereunder to a rate higher than thirteen percent (13%) per annum, or impose any fee, original issue discount or similar payment in connection therewith that, together with all such fees, original issue discounts or similar payments imposed from the date hereof, would exceed two percent (2%) of the amount of the notes, other than the initial fees or original issue discount payable in connection with the initial issuance of the notes; (iii) change (to earlier dates) any dates upon which payments of principal or interest are due thereon; (iv) change any representation, warranty, covenant, default or event of default thereunder in a manner materially adverse to the Company or any of its subsidiaries; (v) change the redemption, prepayment or defeasance provisions thereof in a manner which would be materially adverse to the First Lien Secured Parties; (vi) add Collateral (unless such Collateral is also provided to the First Lien Collateral Agent), or (vii) increase the obligations thereunder of the Company or any of its subsidiaries or confer any additional rights on the Second Lien Secured Parties which would be materially adverse to the First Lien Secured Parties.

Certain Bankruptcy and Other Limitations

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

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

So long as no Event of Default shall have occurred and be continuing, and subject to certain terms and conditions in the indenture and the collateral agreements (including, without limitation, the Intercreditor agreement), the Company and each of the Guarantors will be entitled to receive all cash dividends, interest and other payments made upon or with respect to the Collateral pledged by it. Subject to the Intercreditor Agreement,

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all funds distributed under the collateral agreements and received by the Collateral Agent for the ratable benefit of the holders shall be distributed by the Collateral Agent to the trustee for application in accordance with the provisions of the indenture.

No appraisal has been made of the value of the Collateral. There can be no assurance that the proceeds from the sale of the Collateral remaining after the satisfaction of all First Lien Obligations or after the satisfaction of all other First Lien Obligations secured by any Collateral would be sufficient to satisfy the obligations owed to the holders of the notes.

To the extent third parties hold Permitted Liens, such third parties may have rights and remedies with respect to the property subject to such Liens that, if exercised, could adversely affect the value of the Collateral. By its nature, some or all of the Collateral will be illiquid and may have no readily ascertainable market value and any sale of such Collateral separately from the assets of the Company as a whole may not be feasible. Accordingly, there can be no assurance that the Collateral can be sold in a short period of time, if salable. See “Risk Factors—Risks Relating to the Notes — The notes will be secured only to the extent of the value of the assets having been granted as security for the notes, which may not be sufficient to satisfy our obligations under the notes.”

Optional Redemption

On or after October 1, 2014, the Company may redeem all or a part of the notes at any time or from time to time upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest thereon, if any, on the notes to the applicable redemption date, if redeemed during the periods set forth below:

Period	Percentage
October 1, 2014 to March 31, 2015		106.250	%
April 1, 2015 and thereafter		100.000	%

In addition, at any time on or prior to October 1, 2014, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the notes issued under the indenture at a redemption price of 112.50% of the principal amount, plus accrued and unpaid interest and Additional Interest, if any, on the notes to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), with the net cash proceeds of one or more Equity Offerings by the Company, provided that:

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

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

In addition, at any time prior to October 1, 2014, the notes may be redeemed in whole or in part at the option of the Company upon not less than 30 nor more than 60 days’ prior notice at a redemption price equal to 100% of the principal amount thereof plus the Applicable Premium as of, and accrued and unpaid interest and Additional Interest, if any, to the date of redemption (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

“Applicable Premium” means, with respect to a note at any redemption date, the greater of (x) 1.0% of the principal amount of such note and (y) the excess of (A) the present value at such time of (1) redemption price of such note as of October 1, 2014 (without regard to accrued and unpaid interest) plus (2) all required interest payments due on such note through October 1, 2014, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the principal amount of such note.

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“Treasury Rate” means, with respect to the notes as of any redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the period from the redemption date to October 1, 2014; provided, however, that if the period from the redemption date to October 1, 2014 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to October 1, 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 shall be used.

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

Selection and Notice

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

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

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

No notes of $2,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture. Notices of redemption may not be conditional.

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

Mandatory Redemption; Open Market Purchases

Except as set forth below under “— Repurchase at the Option of Holders,” the Company is not required to make mandatory redemption or sinking fund payments with respect to the notes or to repurchase the notes at the option of the holders. The Company may at any time and from time to time purchase notes in the open market or otherwise if such purchase complies with the then applicable agreements of the Company, including the indenture.

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 the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000) of that holder’s notes pursuant to a Change of Control Offer on the terms set forth in the indenture. In the Change of Control Offer, the Company will offer a Change of Control Payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest and Additional Interest, if any, on the notes repurchased, to the date of settlement (the “Change of Control Purchase Date”), subject to the right of holders of record on the relevant record date to

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receive interest due on an interest payment date that is on or prior to the Change of Control Purchase Date. Within 30 days following any Change of Control, the Company will mail a notice to each holder and the trustee describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes as of the Change of Control Purchase Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice.

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

On the Change of Control Purchase Date, the Company will, to the extent lawful:

(i) accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;

(ii) 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

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

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

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

The provisions described above that require the Company to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. 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 the Company repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

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

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

Asset Sales

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

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

(2) the fair market value is determined by the Company’s Board of Directors and evidenced by a resolution of the Board of Directors set forth in an officers’ certificate delivered to the trustee; and

(3) at least 75% of the consideration received by the Company or such Restricted Subsidiary from all Asset Sales since the Issue Date, in the aggregate, is in the form of cash or Additional Assets.

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

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

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

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

(i) to repay or repurchase Indebtedness and other Obligations under a Credit Facility, any other First Lien Obligations and Indebtedness and other Obligations arising under or pursuant to the notes;

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

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

(iv) to make one or more capital expenditures; or

(v) to acquire other long-term assets that are not classified as current assets under GAAP and that are used or useful in the Oil and Gas Business.

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

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Any Net Proceeds from Asset Sales that are not applied or invested as provided in the preceding paragraph will constitute “Excess Proceeds.” On the 361st day after the Asset Sale (or, at the Company’s option, any earlier date), if the aggregate amount of Excess Proceeds then exceeds $15.0 million, the Company will make an Asset Sale Offer to all holders of notes, and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets, to purchase the maximum principal amount of notes and such other pari passu Indebtedness that may be purchased out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of principal amount plus accrued and unpaid interest and Additional Interest, if any, to the date of settlement, subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of settlement, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, the Company may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and other pari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such other pari passu Indebtedness to be purchased on a pro rata basis. Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

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

Certain Covenants

Restricted Payments

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

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

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

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

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

unless, at the time of and after giving effect to such Restricted Payment:

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

(2) the Company would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period,

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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

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

(a) 50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from July 1, 2010 to the end of the Company’s most recently ended fiscal quarter (commencing with the fiscal quarter ending September 30, 2010) for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus

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

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

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

So long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the preceding provisions will not prohibit:

(1) the payment of any dividend within 60 days after the date of declaration of the dividend, if at the date of declaration the dividend payment would have complied with the provisions of the indenture;

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

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

(4) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Company or any Restricted Subsidiary of the Company held by any current or former director or employee of the Company or any of its Restricted Subsidiaries pursuant to any director or employee equity subscription agreement or plan, stock option agreement or similar agreement or plan; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $1.0 million in any twelve-month period beginning on or after the Issue Date;

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(5) the acquisition of Equity Interests by the Company in connection with the exercise of stock options or stock appreciation rights by way of cashless exercise;

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

(7) the payment of cash in lieu of fractional shares of Capital Stock in connection with any transaction otherwise permitted under the indenture;

(8) dividends on the Company’s Capital Stock in an amount not to exceed $1.0 million in any twelve month period beginning on or after the Issue Date; and

(9) other Restricted Payments in an aggregate amount since the Issue Date not to exceed $5.0 million.

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

Incurrence of Indebtedness and Issuance of Preferred Stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt) and neither the Company nor any Guarantor will issue any Disqualified Stock, and the Company will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock; provided, however, that the Company and any Guarantor may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, if the Fixed Charge Coverage Ratio for the Company’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock is issued would have been at least 4.5 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or Disqualified Stock had been issued, as the case may be, at the beginning of such four-quarter period.

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

(1) the incurrence by the Company or any Guarantor of Indebtedness under one or more Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of

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credit being deemed to have a principal amount equal to the maximum potential liability of the Company and its Restricted Subsidiaries thereunder) not to exceed an amount equal to the greater of (a) $75.0 million and (b) 15% of ACNTA as of the date of such incurrence;

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

(3) the incurrence by the Company and the Guarantors of Indebtedness represented by the notes issued and sold in this offering and any Guarantees to be issued on the date of the indenture and the Exchange Notes and the related Guarantees issued pursuant to the Registration Rights Agreement;

(4) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvement of property, plant or equipment used in the business of the Company or such Restricted Subsidiary, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to refund, refinance or replace any Indebtedness incurred pursuant to this clause (4), not to exceed the greater of $10.0 million at any time outstanding;

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

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

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

(b)(i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person that is neither the Company nor a Restricted Subsidiary of the Company will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

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

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

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

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

(11) Indebtedness of a Restricted Subsidiary incurred and outstanding on the date on which such Restricted Subsidiary was acquired by, or merged into, the Company or any Restricted Subsidiary (other than Indebtedness Incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was otherwise acquired by the Company or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that at the time such Restricted Subsidiary is

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acquired by the Company, the Company would have been able in Incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant after giving effect to the incurrence of such Indebtedness pursuant to this clause (11);

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

(13) the incurrence by the Company or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, not to exceed $15.0 million.

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

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

Liens

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

Dividend and Other Payment Restrictions Affecting Subsidiaries

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

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

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

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

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

(1) agreements governing Existing Indebtedness and the Senior Credit Agreement as in effect on the date of the indenture and any amendments, modifications, restatements, renewals, increases, supplements,

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

(2) the indenture, the notes and the Guarantees;

(3) applicable law;

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

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

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

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

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

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

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

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

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

Merger, Consolidation or Sale of Assets

The Company will not, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not the Company is the surviving corporation); or (2) sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the properties or assets of the Company and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person, unless:

(1) either (a) the Company is the surviving corporation; or (b) the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made is a corporation organized or existing under the laws of the United States, any state of the United States or the District of Columbia;

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

(3) immediately after such transaction no Default or Event of Default exists;

(4) except with respect to a transaction solely between the Company and a Guarantor, the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made will, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, 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;” and

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

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

This “Merger, Consolidation or Sale of Assets” covenant will not apply to:

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

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

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

Transactions with Affiliates

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

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

(2) the Company 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 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; and

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

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

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

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

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

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

(5) sales of Equity Interests (other than Disqualified Stock) to Affiliates of the Company;

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

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

Designation of Restricted and Unrestricted Subsidiaries

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

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

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Additional Guarantees

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

Business Activities

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

Reports

Whether or not required by the rules and regulations of the SEC, so long as any notes are outstanding, the Company will furnish to the holders of notes, within the time periods specified in the SEC’s rules and regulations:

(1) all quarterly and annual reports that would be required to be filed with the SEC on Forms 10-Q and 10-K if the Company were required to file such reports excluding (i) information that would not be required to be provided pursuant to (2) below if, but for (2) below, such information would otherwise be required on a current report and (ii) with respect to Form 10-K, information required to be provided pursuant to Part III Item 11 of Form 10-K; and

(2) all current reports that would be required to be filed with the SEC on Items 1.01, 1.02, 1.03, 2.01, 4.01 and 5.01 of Form 8-K if the Company were required to file such reports.

All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on the Company’s consolidated financial statements by the Company’s independent registered public accounting firm.

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

In addition, the Company 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.

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

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Notwithstanding the foregoing, the Company will not be required to provide the following:

(a) Sarbanes-Ox1ey. No certifications or attestations concerning the financial statements or disclosure controls and procedures or internal controls that would otherwise be required pursuant to the Sarbanes¬Oxley Act of 2002 will be required (provided further, however, that nothing contained in the terms herein shall otherwise require the Company to comply with the terms of the Sarbanes-Oxley Act of 2002 at any time when it would not otherwise be subject to such statute);

(b) Financial Statements of Acquired Entities. The financial statements required of acquired businesses will be limited to the financial statements (in whatever form) that the Company receives in connection with the acquisition, and whether or not audited;

(c) Financial Statements of Unconsolidated Entities. No financial statements of unconsolidated entities will be required;

(d) Segment Reporting. The Company will not be required to prepare its financial statements in accordance with SFAS No. 131;

(e) Mezzanine Securities. The Company will not be required to comply with SPAS No. ISO in respect of any period prior to the date of the indenture;

(f) Supplemental Schedules. The schedules identified in Section 5-04 of Regulation S-X will not be required;

(g) Item 403 of Regulation S-K. The Company may limit the information disclosed in such reports in respect of Item 403 of Regulation S-K under the Securities Act to identifying, in each case utilizing a reference date permitted under Item 403, (A) the aggregate voting and economic ownership interests in the Company and, if applicable, the top-level holding company of the Company of each Person (including any “group” as that term is used in Section 1 3(d)(3) under the Exchange Act) who is known to the Company to be the Beneficial Owner of more than 5% of any class of the Company’s Capital Stock, (B) the aggregate voting and economic ownership interests in the top-level holding company of the Company beneficially owned by directors and officers of the Company as a group and (C) the information required to be disclosed under Item 403(c); and

(h) Exhibits. No exhibits pursuant to Item 601 of Regulation S-K under the Securities Act (other than in respect of material agreements governing Indebtedness) will be required.

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

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 or Additional Interest, if any, on the notes;

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

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

(4) failure by the Company or any of its Restricted Subsidiaries, as applicable, to comply for 30 days after receipt of written notice from the trustee or the holders of 25% in principal amount of the notes with the provisions described under the captions “— Certain Covenants — Restricted Payments,” “— Incurrence

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of Indebtedness and Issuance of Preferred Stock,” “— Liens,” “— Dividends and Other Payment Restrictions Affecting Subsidiaries,” “— Transactions with Affiliates,” “— Additional Guarantees” and “— Business Activities;”

(5) failure by the Company for 60 days after notice from the trustee or the holders of 25% of the principal amount of the notes outstanding to comply with any of the other agreements in the indenture (or 120 days with respect to the covenant described above under “Reports”);

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

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

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

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

(7) failure by the Company or any of its Restricted Subsidiaries to pay final judgments aggregating in excess of $15 million, which judgments are not paid, discharged or stayed (including a stay pending appeal) for a period of 60 days after the date of such final judgment (or, if later, the date when payment is due pursuant to such judgment);

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

(9) certain events of bankruptcy, insolvency or reorganization described in the indenture with respect to the Company or any of its Significant Subsidiaries or any group of Subsidiaries of the Company that, taken as a whole, would constitute a Significant Subsidiary; and

(10)(x) any Collateral Agreement at any time for any reason shall cease to be in full force and effect in all material respects except as defined in the Indenture or the Collateral Agreements; (y) any Collateral Agreement ceases to give the Collateral Agent the Liens, rights, powers and privileges purported to be created thereby with respect to any Collateral having a fair market value in excess of $2.5 million, superior to and prior to the rights of all third Persons other than the holders of Permitted Liens and subject to no other Liens except as expressly permitted by the applicable Collateral Agreement or the Indenture; or (z) the Company or any of the Guarantors, directly or indirectly, contest in any manner the effectiveness, validity, binding nature or enforceability of any Collateral Agreement.

In the case of an Event of Default arising from certain events of bankruptcy, insolvency or reorganization, with respect to the Company, 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 principal amount of the then outstanding notes may declare all the notes to be due and payable immediately.

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

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Subject to the provisions of the indenture relating to the duties of the trustee, in case an Event of Default occurs and is continuing, the trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any holders of notes unless such holders have offered to the trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, interest, premium or Additional 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 notice that an Event of Default is continuing;

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

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

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

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

The holders of a majority in principal amount of the notes then outstanding by notice to the trustee may on behalf of the holders of all of the notes waive any past Default or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of principal of, or interest, premium or Additional Interest, if any, on, the notes or in respect of a covenant that cannot be amended without the consent of each holder.

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

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

No Personal Liability of Directors, Officers, Employees and Stockholders

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

Legal Defeasance and Covenant Defeasance

The Company may at its option and, at any time, elect to have all of its obligations discharged with respect to outstanding notes and all obligations of the Guarantors discharged with respect to their Guarantees (“Legal Defeasance”) except for:

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

(2) the Company’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;

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

(4) the Legal Defeasance provisions of the indenture.

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

In order to exercise either Legal Defeasance or Covenant Defeasance:

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

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

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

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

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

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

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

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

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

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

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Amendment, Supplement and Waiver

Except as provided in the next three succeeding paragraphs, the Indenture Documents may be amended or supplemented with the consent of the holders of at least a majority in principal amount of the notes affected thereby then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes), and any existing Default or Event of Default or compliance with any provision of the Indenture Documents may be waived with the consent of the holders of a majority in principal amount of the then outstanding notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

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

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

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

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

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

(5) make any note payable in currency 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, or interest, premium or Additional Interest, if any, on the notes (other than as permitted in clause (7) below);

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

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

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

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

(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 the Company’s or a Guarantor’s obligations to holders of notes in the case of a merger or consolidation or sale of all or substantially all of the Company’s or a Guarantor’s properties or assets;

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

(5) to secure the notes or the Guarantees pursuant to the requirements of the covenant described above under the subheading “— Certain Covenants — Liens” or otherwise;

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

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

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

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

Without the consent of the holders of at least a majority in aggregate principal amount of the notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes), an amendment, supplement or waiver may not release all or substantially all of the Collateral from the Liens created pursuant to the Collateral Agreements, except in accordance with the Indenture and the Collateral Agreements.

Impairment of Security Interest

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

Satisfaction and Discharge

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

(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 the Company, have been delivered to the trustee for cancellation; or

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

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

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

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

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

Concerning the Trustee

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

The holders of a majority in 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 occurs 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 security or indemnity satisfactory to it against any loss, liability or expense.

Governing Law

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

Registration Rights; Additional Interest

The Company, the Guarantors and the purchasers of the notes entered into a registration rights agreement on or prior to the closing of this offering. The following description is a summary of the material provisions of the registration rights agreement. It does not restate that agreement in its entirety. We urge you to read the registration rights agreement, which is filed as an exhibit to the registration statement which includes this prospectus, in its entirety because it, and not this description, defines your registration rights as holders of the new notes. See “— Additional Information.”

The Company, the Guarantors and the initial purchasers entered into the registration rights agreement on the original issuance date of the old notes. Pursuant to the registration rights agreement, the Company and the Guarantors agreed to file with the SEC the Exchange Offer Registration Statement (as defined in the registration rights agreement) on the appropriate form under the Securities Act with respect to the exchange notes. Upon the effectiveness of the Exchange Offer Registration Statement, the Company and the Guarantors will offer to the holders of Transfer Restricted Securities pursuant to the Exchange Offer (as defined in the registration rights agreement) who are able to make certain representations the opportunity to exchange their Transfer Restricted Securities for exchange notes.

Pursuant to the registration rights agreement, the Company and the Guarantors agreed that they will, subject to certain exceptions,

(1) within 180 days after the date of original issue of the notes (the “Issue Date”), file the Exchange Offer Registration Statement with the SEC with respect to a Registered Exchange Offer to exchange the notes for new notes of the Company, which we call “Exchange Notes,” having terms substantially identical in all material respects to the notes (except that the Exchange Notes will not contain terms relating to transfer restrictions);

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(2) use their reasonable best efforts to cause the Exchange Offer Registration Statement to be declared effective under the Securities Act within 270 days after the Issue Date;

(3) as soon as practicable after the effectiveness of the Exchange Offer Registration Statement (the “Effectiveness Date”), offer the Exchange Notes in exchange for the notes; and

(4) keep the Registered Exchange Offer open for not less than 30 days (or longer if required by applicable law) after the date notice of the Registered Exchange Offer is mailed to the holders of the notes.

For each old note tendered to us pursuant to the Registered Exchange Offer, we will issue to the holder of such old note an Exchange Note having a principal amount equal to that of the surrendered old note. Interest on each Exchange Note will accrue from the last interest payment date on which interest was paid on the note surrendered in exchange therefor, or, if no interest has been paid on such note, from the date of its original issue.

Under existing SEC interpretations, the Exchange Notes will be freely transferable by holders other than our affiliates after the Registered Exchange Offer without further registration under the Securities Act if the holder of the Exchange Notes makes the representations to us set forth in the second succeeding paragraph; provided, however, that broker-dealers (“Participating Broker-Dealers”) receiving Exchange Notes in the Exchange Offer will have a prospectus delivery requirement for resales of such Exchange Notes. The SEC has taken the position that Participating Broker-Dealers may fulfill their prospectus delivery requirements with respect to Exchange Notes (other than a resale of an unsold allotment from the original sale of the notes) with the prospectus contained in the Exchange Offer Registration Statement.

The registration rights agreement will require the Company and the Guarantors to allow Participating Broker-Dealers and other Persons, if any, with similar prospectus delivery requirements to use the prospectus contained in the Exchange Offer Registration Statement in connection with the resale of such Exchange Notes for 180 days following the Effectiveness Date (or such shorter period during which Participating Broker-Dealers are required by law to deliver such prospectus).

A holder of old notes (other than certain specified holders) who wishes to exchange such old notes for Exchange Notes in the Registered Exchange Offer will be required to represent that any Exchange Notes to be received by it will be acquired in the ordinary course of its business and that at the time of the commencement of the Registered Exchange Offer it has no arrangement or understanding with any Person to participate in the distribution (within the meaning of the Securities Act) of the Exchange Notes and that it is not an “affiliate” of the Company, as defined in Rule 405 of the Securities Act, or if it is an affiliate, that it will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable.

In the event that:

(1) any change in law or in applicable interpretations thereof by the staff of the SEC does not permit us to effect the Registered Exchange Offer;

(2) for any other reason we do not consummate the Registered Exchange Offer within 310 days of the Issue Date;

(3) a purchaser notifies us following consummation of the Registered Exchange Offer that notes held by it are not eligible to be exchanged for Exchange Notes in the Registered Exchange Offer; or

(4) certain holders are prohibited by law or SEC policy from participating in the Registered Exchange Offer or may not resell the Exchange Notes acquired by them in the Registered Exchange Offer to the public without delivering a prospectus,

then, the Company and the Guarantors will, subject to certain exceptions,

(1) promptly file a shelf registration statement (the “Shelf Registration Statement”) with the SEC covering resales of the notes or the Exchange Notes, but in no event later than the 30th day following notice of items (1) through (4) of the preceding paragraph;

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(2)(A) in the case of clause (1) above, use their reasonable best efforts to cause the Shelf Registration Statement to be declared effective under the Securities Act on or prior to the 270th day after the Issue Date and (B) in the case of clause (2), (3) or (4) above, use their reasonable best efforts to cause the Shelf Registration Statement to be declared effective under the Securities Act on or prior to the 180th day after the date on which the Shelf Registration Statement is required to be filed; and

(3) use their reasonable best efforts to keep the Shelf Registration Statement effective until the earliest of (A) the time when the notes covered by the Shelf Registration Statement can be sold by non-affiliates pursuant to Rule 144 without any limitations under Rule 144, (B) two years from the Issue Date and (C) the date on which all notes registered thereunder are disposed of in accordance therewith.

We will, in the event a Shelf Registration Statement is filed, among other things, provide to each Person for whom such Shelf Registration Statement was filed copies of the prospectus which is part of the Shelf Registration Statement, notify each such Person when the Shelf Registration Statement has become effective and take certain other actions as are required to permit unrestricted resales of the notes or the Exchange Notes, as the case may be. A Person selling such notes or Exchange Notes pursuant to the Shelf Registration Statement generally would be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such holder (including certain indemnification obligations).

We may require each Person requesting to be named as a selling security holder to furnish to us such information regarding the Person and the distribution of the notes or Exchange Notes by the Person as we may from time to time reasonably require for the inclusion of the Person in the Shelf Registration Statement, including requiring the Person to properly complete and execute such selling security holder notice and questionnaires, and any amendments or supplements thereto, as we may reasonably deem necessary or appropriate. We may refuse to name any Person as a selling security holder that fails to provide us with such information.

We will pay, as liquidated damages, Additional Interest on the applicable notes and Exchange Notes, subject to certain exceptions,

(1) if the Company and the Guarantors fail to file an Exchange Offer Registration Statement with the SEC on or prior to the 180th day after the Issue Date,

(2) if the Exchange Offer Registration Statement is not declared effective by the SEC on or prior to the 270th day after the Issue Date or, if the Company and the Guarantors are obligated to file a Shelf Registration Statement pursuant to clause 2(A) above, a Shelf Registration Statement is not declared effective by the SEC on or prior to the 270th day after the Issue Date,

(3) if the Registered Exchange Offer is not consummated on or before the 40th day after the Effectiveness Date,

(4) if they are obligated to file the Shelf Registration Statement pursuant to clause 2(B) above, the Company and the Guarantors fail to file the Shelf Registration Statement with the SEC on or prior to the 90th day (the “Shelf Filing Date”) after the date on which the obligation to file a Shelf Registration Statement arises,

(5) if the Company and the Guarantors are obligated to file a Shelf Registration Statement pursuant to clause 2(B) above, the Shelf Registration Statement is not declared effective on or prior to the 90th day after the Shelf Filing Date, or

(6) after the Exchange Offer Registration Statement or the Shelf Registration Statement, as the case may be, is declared effective, such Registration Statement thereafter ceases to be effective or usable (subject to certain exceptions) (each such event referred to in this clause (6) and the preceding clauses (1) through (5) being called a “Registration Default”).

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If any such Registration Default is not cured within 30 calendar days of the date on which such Registration Default shall have occurred, Additional Interest shall be paid from and including the date on which any such Registration Default shall have occurred to but excluding the earlier to occur of (i) the date on which all Registration Defaults have been cured or (ii) the date on which all of the notes otherwise become freely tradable by holders, other than Affiliates of the Issuer, without further registration under the Securities Act.

The rate of the Additional Interest will be 0.25% per annum for the first 90-day period immediately following the occurrence of a Registration Default, and such rate will increase by an additional 0.25% per annum with respect to each subsequent 90-day period during which Additional Interest is to be paid, up to a maximum Additional Interest rate of 1.00% per annum. We will pay such Additional Interest on regular interest payment dates. Such additional interest will be in addition to any other interest payable from time to time with respect to the notes and the Exchange Notes, but will be the sole remedy for any Registration Default.

We will be entitled to close the Registered Exchange Offer 30 days after it commences, provided that we have accepted all notes theretofore validly tendered in accordance with the terms of the Registered Exchange Offer.

Certain Definitions

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

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

(1) the sum of:

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

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

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

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

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

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

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reserve report attributable to downward determinations of estimates of proved crude oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such year-end reserve report,

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

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

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

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

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

(a) minority interests;

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

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

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

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

If the Company changes its method of accounting for its oil and gas properties from the full cost method to the successful efforts method or a similar method of accounting, ACNTA will continue to be calculated as if the Company were still using the full cost method of accounting.

“Acquired Debt” means, with respect to any specified Person:

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

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

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“Additional Assets” means:

(1) any assets used or useful in the Oil and Gas Business;

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

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

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

“Additional Interest” means all additional interest then owing pursuant to the registration rights agreement.

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

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

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

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

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

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

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

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

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

(5) the sale or other disposition of cash or Cash Equivalents;

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

(7) any trade or exchange by the Company or any Restricted Subsidiary of oil and gas properties or other properties or assets for oil and gas properties or other properties or assets owned or held by another Person, provided that the fair market value of the properties or assets traded or exchanged by the Company

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or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the fair market value of the properties or assets (together with any cash) to be received by the Company or such Restricted Subsidiary, and provided further that any net cash received must be applied in accordance with the provisions described above under the caption “— Repurchase at the Option of Holders — Asset Sales;”

(8) the creation or perfection of a Lien (but not the sale or other disposition of the properties or assets subject to such Lien) in accordance with the limitations set forth in the indenture;

(9) surrender or waiver of contract rights or the settlement, release or surrender of contract, tort or other claims of any kind; and

(10) the granting of royalty interests or other interests in oil and gas properties to employees, consultants (or directors) in accordance with the terms of the After Payout Overriding Royalty Interest Program and the Employee Drilling Bonus Plan or similar compensation agreements approved by the Board of Directors.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

“Board of Directors” means:

(1) with respect to a corporation, the board of directors of the corporation;

(2) with respect to a partnership, the Board of Directors of the general partner of the partnership; and

(3) with respect to any other Person, the board or committee of such Person serving a similar function.

“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the applicable Person to have been duly adopted by the Board of Directors of such Person and to be in full force and effect on the date of such certification, and delivered to the trustee.

“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York are authorized or required by law to close.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty.

“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 or membership interests (whether general or limited); and

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(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 (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than six months from the date of acquisition;

(3) certificates of deposit and eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any lender party to the Senior Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of “B” or better;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

(5) commercial paper having the highest rating obtainable from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and in each case maturing within six months after the date of acquisition; and

(6) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition.

“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 (including Capital Stock) of the Company and its Subsidiaries taken as a whole to any “person” (as that term is used in Section 13(d)(3) of the Exchange Act) other than one or more Permitted Holders;

(2) the adoption of a plan relating to the liquidation or dissolution of the Company;

(3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” or “group” (as that term is used in Section 13(d)(3) of the Exchange Act), other than one or more Permitted Holders, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Company, measured by voting power rather than number of shares, other than, with respect to a merger or consolidation, a transaction in which the Voting Stock of the Company outstanding immediately prior to such transaction is converted into or exchanged for Voting Stock (other than Disqualified Stock) of the surviving or transferee Person (or any parent thereof) constituting a majority of the outstanding shares of such Voting Stock of such surviving or transferee Person (or any parent thereof) immediately after giving effect to such transaction; or

(4) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors.

“Collateral Agent” means the party named as the collateral agent for the Second Lien Secured Parties in the indenture until a successor replaces it in accordance with the provisions of the indenture and thereafter means any such successor.

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“Collateral Agreements” means, collectively, the Intercreditor Agreement, each security agreements or other collateral agreement, and each other document or instrument creating Liens in favor of the Collateral Agent as required by the indenture, in each case, as the same may be in force from time to time.

“Commission” or “SEC” means the Securities and Exchange Commission.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus:

(1) 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

(2) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued and whether or not capitalized (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 interest rate Hedging Obligations, to the extent that any such expense was deducted in computing such Consolidated Net Income; plus

(3) depreciation, depletion and amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), impairment, exploration expense, and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion and amortization, impairment and other non-cash expenses were deducted in computing such Consolidated Net Income; plus

(4) unrealized non-cash losses resulting from foreign currency balance sheet adjustments required by GAAP to the extent such losses were deducted in computing such Consolidated Net Income; minus

(5) non-cash items increasing such Consolidated Net Income for such period, other than items that were accrued in the ordinary course of business; minus (to the extent included in determining Consolidated Net Income).

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:

(1) the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be excluded, except to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

(2) the Net Income of any Restricted Subsidiary that is not a Guarantor 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, partners or members;

(3) the cumulative effect of a change in accounting principles will be excluded;

(4) income resulting from transfers of assets (other than cash) between the Company or any of its Restricted Subsidiaries, on the one hand, and an Unrestricted Subsidiary, on the other hand, will be excluded;

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(5) any write-downs of non-current assets will be excluded; provided that any ceiling limitation writedowns under Commission guidelines shall be treated as capitalized costs, as if such write-downs had not occurred;

(6) any unrealized non-cash gains or losses or charges in respect of hedge or non-hedge derivatives will be excluded;

(7) any non-cash compensation charge arising from any grant of stock, stock options or other equity based awards will be excluded;

(8) any item classified as an extraordinary, unusual or nonrecurring gain, loss or charge will be excluded; and

(9) all deferred financing costs written off and premiums or penalty paid in connection with any early extinguishment of Indebtedness will be excluded.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Company, as applicable, 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 at the time of such nomination or election.

“Credit Facilities” means one or more first-priority secured debt facilities (including, without limitation, the Senior Credit Agreement), commercial paper facilities or capital markets financings, in each case with banks or other institutional lenders or institutional investors providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from (or sell receivables to) such lenders against such receivables), letters of credit or capital markets financings, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced (including by means of sales of debt securities) in whole or in part from time to time.

“Debt Documents” means, collectively, the First Lien Debt Documents and the Indenture Documents, and corresponding documents relating to other Second Lien Obligations.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require the Company to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that the Company may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “— Certain Covenants — Restricted Payments.”

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary of the Company that was formed under the laws of the United States or any state of the United States or the District of Columbia or that guarantees or otherwise provides direct credit support for any Indebtedness of the Company.

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“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means any public or private sale of Capital Stock (other than Disqualified Stock) made for cash on a primary basis by the Company after the date of the indenture.

“Exchange Notes” means the notes (including any additional notes) issued in a Registered Exchange offer pursuant to the indenture.

“Existing Indebtedness” means the aggregate principal amount of Indebtedness of the Company and its Restricted Subsidiaries in existence on the date of the indenture, until such amounts are repaid.

“First Lien Collateral Agent” means the collateral agent for the First Lien Secured Parties named in any First Lien Debt Document and any successor or replacement collateral agent designated as such by the holders of First Lien Obligations.

“First Lien Debt Documents” means, collectively, all agreements, instruments and other documents evidencing, governing or providing any Lien for the benefit of any First Lien Obligations.

“First Lien Secured Parties” means the holders of the First Lien Obligations and the First Lien Collateral Agent.

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any four-quarter reference period, the ratio of the Consolidated Cash Flow 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 or redeems any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the applicable four-quarter reference period 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 to such incurrence, assumption, guarantee, repayment, repurchase or redemption 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 such 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 and including any related financing transactions, subsequent to the commencement of the applicable four-quarter reference period and on or prior to the Calculation Date will be given pro forma effect as if they had occurred on the first day of such period, including any Consolidated Cash Flow (with such pro forma adjustments to be made in good faith by the Company whether or not permitted by Regulation S-X promulgated under the Securities Act or any other regulation or policy of the Commission related thereto);

(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and assets, operations or businesses disposed of prior to the Calculation Date, will be excluded; and

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and assets, operations or businesses disposed of 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;

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(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 (excluding prepayment penalties associated with the repayment of debt from the proceeds of this offering) 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 interest rate Hedging Obligations; plus

(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

(3) any interest expense 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, whether paid or accrued and whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of the Company (other than Disqualified Stock) or to the Company or a Restricted Subsidiary of the Company,

in each case, on a consolidated basis and in accordance with GAAP.

“Foreign Subsidiary” means any Restricted Subsidiary of the Company that is not a Domestic Subsidiary.

“freely tradable” means a Transfer Restricted Security shall be deemed to be “freely tradable” at any time of determination if at such time of determination (i) it may be sold to the public pursuant to Rule 144A under the Securities Act by a person that is not an “affiliate” (as defined in Rule 144 under the Securities Act) of the Company without regard to any of the conditions specified therein (other than the holding period requirement in paragraph (d) of Rule 144 so long as such holding period requirement is satisfied at such time of determination) and (ii) it does not bear any restrictive legends relating to the Securities Act.

“GAAP” means generally accepted accounting principles in the United States, which are updated from time to time.

The term “guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness. When used as a verb, “guarantee” has a correlative meaning.

“Guarantee” means any guarantee by a Guarantor of the Company’s payment Obligations under the indenture and on the notes.

“Guarantors” means each Restricted Subsidiary of the Company that executes the indenture as an initial Guarantor or that becomes a Guarantor in accordance with the provisions of the indenture, and their respective successors and assigns.

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“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person incurred in the normal course of business and not for speculative purposes under:

(1) interest rate swap agreements, interest rate cap agreements and interest rate collar agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in interest rates with respect to Indebtedness incurred and not for purposes of speculation;

(2) foreign exchange contracts and currency protection agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in currency exchanges rates with respect to Indebtedness incurred and not for purposes of speculation;

(3) any commodity futures contract, commodity option or other similar agreement or arrangement designed to protect against fluctuations in the price of oil, natural gas or other commodities used, produced, processed or sold by that Person or any of its Restricted Subsidiaries at the time; and

(4) other agreements or arrangements designed to protect such Person or any of its Restricted Subsidiaries against fluctuations in interest rates, commodity prices or currency exchange rates.

“Indebtedness” means, with respect to any specified Person (excluding accrued expenses and trade payables), without duplication,

(1) all obligations of such Person, whether or not contingent, in respect of:

(a) the principal of and premium, if any, in respect of outstanding (A) Indebtedness of such Person for money borrowed and (B) Indebtedness evidenced by notes, debentures, bonds or other similar instruments for the payment of which such Person is responsible or liable;

(b) all Capital Lease Obligations of such Person and all Attributable Debt in respect of sale and leaseback transactions entered into by such Person;

(c) the deferred purchase price of property, which purchase price is due more than six months after the date of taking delivery of title to such property, including all obligations of such Person for the deferred purchase price of property under any title retention agreement, but excluding accrued expenses and trade accounts payable arising in the ordinary course of business; and

(d) the reimbursement obligation of any obligor for the principal amount of any letter of credit, banker’s acceptance or similar transaction (excluding obligations with respect to letters of credit securing obligations (other than obligations described in clauses (a) through (c) above) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no later than the tenth Business Day following receipt by such Person of a demand for reimbursement following payment on the letter of credit);

(2) all net obligations in respect of Hedging Obligations except to the extent such net obligations are otherwise included in this definition;

(3) all liabilities of others of the kind described in the preceding clause (1) or (2) that such Person has Guaranteed or that are otherwise its legal liability;

(4) with respect to any Production Payment, any warranties or guaranties of production or payment by such Person with respect to such Production Payment but excluding other contractual obligations of such Person with respect to such Production Payment;

(5) Indebtedness (as otherwise defined in this definition) of another Person secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person, the amount of such obligations being deemed to be the lesser of

(a) the full amount of such obligations so secured, and

(b) the fair market value of such asset as determined in good faith by such specified Person;

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(6) Disqualified Stock of such Person or a Restricted Subsidiary in an amount equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

(7) the aggregate preference in respect of amounts payable on the issued and outstanding shares of preferred stock of any of the Company’s Restricted Subsidiaries that are not Guarantors in the event of any voluntary or involuntary liquidation, dissolution or winding up (excluding any such preference attributable to such shares of preferred stock that are owned by such Person or any of its Restricted Subsidiaries; provided, that if such Person is the Company, such exclusion shall be for such preference attributable to such shares of preferred stock that are owned by the Company or any of its Restricted Subsidiaries); and

(8) any and all deferrals, renewals, extensions, refinancings and refundings (whether direct or indirect) of, or amendments, modifications or supplements to, any liability of the kind described in any of the preceding clauses (1), (2), (3), (4), (5), (6), (7) or this clause (8), whether or not between or among the same parties. if and to the extent any of the preceding items (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and, to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person. Subject to clause (4) of the preceding sentence, Production Payments shall not be deemed to be Indebtedness.

“Indenture Documents” means, collectively, the indenture, the notes, the Guarantees and the Collateral Agreements.

“Intercreditor Agreement” means the intercreditor agreement that is entered into at the closing of the offering of the notes, among the trustee, the Collateral Agent, the First Lien Collateral Agent, the Company and the Guarantors, and the other signatories thereto, as the same may be amended, supplemented, restated or modified from time to time.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of the Company, the Company will be deemed to have made an Investment on the date of any such sale or disposition in an amount equal to the fair market value of the Equity Interests of such Restricted Subsidiary not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “— Certain Covenants — Restricted Payments.” The acquisition by the Company or any Subsidiary of the Company of a Person that holds an Investment in a third Person will not be deemed to be an Investment by the Company or such Subsidiary in such third Person unless such Investment in such third Person was contemplated by the Company or such Subsidiary and not incidental to the acquisition of such Person.

“Issue Date” means the date on which notes are first issued 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 other than a precautionary financing statement not intended as a security agreement.

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“Net Income” means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however:

(1) any gain or loss, together with any related provision for taxes, realized in connection with: (a) any Asset Sale; or (b) the disposition of any securities by such Person or any of its Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Subsidiaries; and

(2) any extraordinary gain or loss, together with any related provision for taxes on such extraordinary gain or loss.

“Net Proceeds” means the aggregate cash proceeds received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of, without duplication:

(1) the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale,

(2) 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,

(3) amounts required to be applied to the repayment of Indebtedness secured by a Lien on the properties or assets that were the subject of such Asset Sale, and

(4) any reserve for adjustment in respect of the sale price of such properties or assets established in accordance with GAAP.

“Net Working Capital” means:

(1) all current assets of the Company and its Restricted Subsidiaries, minus

(2) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness;

in each case, on a consolidated basis and determined in accordance with GAAP. “Non-Recourse Debt” means Indebtedness:

(1) as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) is the lender;

(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness (other than the notes) of the Company or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity; and

(3) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of the Company or any of its Restricted Subsidiaries.

“Obligations” means any principal, premium, if any, interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization, whether or not a claim for post-filing interest is allowed in such proceeding), penalties, fees, charges, expenses, indemnifications, reimbursement obligations, damages, guarantees, and other liabilities or amounts payable under the documentation governing any Indebtedness or in respect thereto.

“Oil and Gas Business” means:

(1) the acquisition, exploration, development, operation and disposition of interests in oil, natural gas and other hydrocarbon properties;

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(2) the gathering, marketing, treating, processing (but not refining), storage, selling and transporting of any production from those interests, including any hedging activities related thereto; and

(3) any activity necessary, appropriate, incidental or reasonably related to the activities described above.

“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business, including through agreements, transactions, interests or arrangements that permit one to share risk or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including without limitation:

(1) direct or indirect ownership of crude oil, natural gas, other related hydrocarbon and mineral properties or any interest therein or gathering, transportation, processing, storage or related systems; and

(2) the entry into operating agreements, joint ventures, processing agreements, working interests, royalty interests, mineral leases, farm-in agreements, farm-out agreements, development agreements, production sharing agreements, area of mutual interest agreements, contracts for the sale, transportation or exchange of crude oil and natural gas and related hydrocarbons and minerals, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, partnership agreements (whether general or limited), or other similar or customary agreements, transactions, properties, interests or arrangements and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding, however, Investments in corporations and publicly-traded limited partnerships.

“Permitted Holders” means Howard A. Settle, Jonathan Rudney or their respective family members, heirs or their successors, beneficiaries or any trust, foundation or other entity controlled by or established for the benefit of any of the foregoing, or any of their respective Affiliates.

“Permitted Investments” means:

(1) any Investment in the Company or in a Restricted Subsidiary of the Company;

(2) any Investment in Cash Equivalents;

(3) any Investment by the Company or any Restricted Subsidiary of the Company in a Person, if as a result of such Investment:

(a) such Person becomes a Restricted Subsidiary of the Company; or

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its properties or assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company;

(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “— Repurchase at the Option of Holders — Asset Sales;”

(5) any Investment in any Person solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Company;

(6) any Investments received in compromise of obligations of trade creditors or customers that were incurred in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer;

(7) Hedging Obligations permitted to be incurred under the “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant;

(8) Permitted Business Investments;

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(9) any repurchases of notes permitted pursuant to the terms of the indenture, including open market purchases of the notes; and

(10) other Investments in any Person having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (10) that are at the time outstanding, not to exceed $10.0 million.

“Permitted Liens” means:

(1) Liens on any property or assets securing Indebtedness and other obligations under Credit Facilities permitted under the indenture;

(2) Liens in favor of the Company or the Guarantors;

(3) Liens on any property or assets of a Person existing at the time such Person is merged with or into or consolidated with the Company or any Restricted Subsidiary of the Company, provided that such Liens were in existence prior to the contemplation of such merger or consolidation and do not extend to any property or assets other than those of the Person merged into or consolidated with the Company or the Restricted Subsidiary;

(4) Liens on any property or assets existing at the time of acquisition thereof by the Company or any Restricted Subsidiary of the Company, provided that such Liens were not incurred in connection with the contemplation of such acquisition;

(5) Liens to secure the performance of statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business;

(6) Liens existing on the Issue Date;

(7) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(8) Liens securing Permitted Refinancing Indebtedness incurred to refinance Indebtedness that was previously so secured, provided that any such Lien is limited to all or part of the same property or assets (plus improvements, replacements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property that is the security for a Permitted Lien hereunder;

(9) Liens securing Hedging Obligations of the Company or any of its Restricted Subsidiaries;

(10) Liens securing Indebtedness incurred in connection with the acquisition by the Company or any Restricted Subsidiary of assets used in the Oil and Gas Business (including the office buildings and other real property used by the Company or such Restricted Subsidiary in conducting its operations); provided that (i) such Liens attach only to the assets acquired with the proceeds of such Indebtedness; (ii) such Indebtedness is not in excess of the purchase price of such fixed assets; and (iii) such Indebtedness is permitted to be incurred under the “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant;

(11) any Lien incurred in the ordinary course of business incidental to the conduct of the business of the Company or the Restricted Subsidiaries or the ownership of their property (including (a) easements, rights of way and similar encumbrances, (b) rights or title of lessors under leases (other than Capital Lease Obligations), (c) rights of collecting banks having rights of setoff, revocation, refund or chargeback with respect to money or instruments of the Company or the Restricted Subsidiaries on deposit with or in the possession of such banks, (d) Liens imposed by law, including Liens under workers’ compensation or similar legislation and mechanics’, carriers’, warehousemen’s, materialmen’s, suppliers’ and vendors’ Liens, and (e) Liens incurred to secure performance of obligations with respect to statutory or regulatory requirements, performance or return-of-money bonds, surety bonds or other obligations of a like nature and incurred in a manner consistent with industry practice;

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(12) Liens for taxes, assessments and governmental charges not yet due or the validity of which are being contested in good faith by appropriate proceedings, promptly instituted and diligently conducted, and for which adequate reserves have been established to the extent required by GAAP as in effect at such time;

(13) Liens incurred with respect to obligations that do not exceed $10.0 million at any one time outstanding; and

(14) Liens created for the benefit of (or to secure) Second Lien Obligations permitted pursuant to any Indenture Document or the Registration Rights Agreement.

“Permitted Refinancing Indebtedness” means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:

(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded (plus all accrued interest on the Indebtedness and the amount of all expenses and premiums incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness has a final maturity date no earlier than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(3) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the notes or the Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to the notes or the Guarantees on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and

(4) such Indebtedness is not incurred by a Restricted Subsidiary of the Company if the Company is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; provided, however, that a Restricted Subsidiary that is also a Guarantor may guarantee Permitted Refinancing Indebtedness incurred by the Company, whether or not such Restricted Subsidiary was an obligor or guarantor of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Production Payments” means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments.

“Registered Exchange Offer” has the meaning set forth for such term in the applicable registration rights agreement.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

“Sarbanes-Oxley Act of 2002” means the Public Company Accounting Reform and Investor Protection Act and the rules and regulations promulgated thereunder.

“Second Lien Obligations” means all Indebtedness and other Obligations arising permitted pursuant to the indenture, the notes, the Guarantees, the Exchange Notes, the Registration Rights Agreement (including Additional Interest, if any), the Additional Notes, if any and any Collateral Agreements.

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“Second Lien Secured Parties” means the holders of the Second Lien Obligations, the trustee, the Agent for any Second Lien Obligations and the Collateral Agent.

“Secured Parties” means, collectively, the First Lien Secured Parties and the Second Lien Secured Parties.

“Senior Credit Agreement” means the Third Amended and Restated Credit Agreement, as amended by the Second Amendment to the Third Amended and Restated Credit Agreement to be in effect on the Issue Date, among the Company, each of the Restricted Subsidiaries, Union Bank, N.A. as Administrative Agent, and Capital One, National Association, Regions Bank, Fortis Capital Corp. and Natixis as lenders, including any related notes, guarantees, collateral documents, instruments and agreements executed in connection therewith, and in each case as amended, restated, modified, renewed, refunded, replaced or refinanced from time to time, including with different lenders or in differing amounts of Indebtedness to the extent permitted under the indenture.

“Senior Debt” means all Indebtedness of the Company or any of its Restricted Subsidiaries permitted to be incurred under the terms of the indenture, including the notes, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the notes or any Guarantee, and all Obligations with respect to the foregoing.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation 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 original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“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 Voting Stock is at the time owned or controlled, directly or through another Subsidiary, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof).

“Transfer Restricted Securities” means the notes; provided, however, that a note, shall cease to be a Transfer Restricted Security upon the earliest to occur of the following: (i) in certain circumstances, the note has been exchanged for an Exchange Note (as such term is defined in the Registration Rights Agreement) in an Exchange Offer (as such term is defined in the Registration Rights Agreement); (ii) in certain circumstances, a Shelf Registration Statement (as such term is defined in the Registration Rights Agreement) registering such note under the Securities Act has been declared or becomes effective and such note has been sold or otherwise transferred by the holder thereof pursuant to and in a manner contemplated by such effective Shelf Registration Statement; (iii) such note is actually sold by the holder thereof pursuant to Rule 144 under the Securities Act, as amended, under circumstances in which any legend borne by such note relating to restrictions on transferability thereof, under the Securities Act or otherwise, is removed by the Company or pursuant to the indenture; or (iv) such note shall cease to be outstanding.

“Unrestricted Subsidiary” means any Subsidiary of the Company that is designated by the Board of Directors as an Unrestricted Subsidiary pursuant to a Board Resolution, but only to the extent that such Subsidiary:

(1) has no Indebtedness other than Non-Recourse Debt;

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(2) is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary of the Company unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company;

(3) is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(4) does not guarantee or otherwise directly or indirectly provide credit support for any Indebtedness of the Company or any of its Restricted Subsidiaries.

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

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all related undertakings and obligations.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors of such Person.

“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.

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BOOK-ENTRY; DELIVERY AND FORM

The new notes, like substantially all the old notes, will be issued in the form of one or more fully registered notes in global form, without interest coupons (the “Global Notes”). Each Global Note will be deposited with the Trustee as custodian for DTC, in New York, New York, and registered in the name of DTC or its nominee, in each case, for credit to an account of a direct or indirect participant in DTC as described below.

Ownership of beneficial interests in each Global Note will be limited to persons who have accounts with DTC (“DTC participants”) or persons who hold interests through DTC participants. We expect that under procedures established by DTC:

• upon deposit of each Global Note with DTC’s custodian, DTC will credit portions of the principal amount of the Global Notes to the accounts of the DTC participants designated by the exchange agent; and

• ownership of beneficial interests in each Global Note will be shown on, and transfer of ownership of those interests will be effected only through, records maintained by DTC (with respect to interests of DTC participants) and the records of DTC participants (with respect to other owners of beneficial interests in the Global Notes).

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.

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. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between the Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

Except as described below, owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest, premium on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, we and the Trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes.

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Consequently, neither we, the Trustee, the exchange agent nor any agent of ours, the Trustee, or the exchange agent has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee, the exchange agent or us. Neither we nor the Trustee nor the exchange agent will be liable for any delay by DTC or any of the Participants or the Indirect Participants in identifying the beneficial owners of the notes, and we, the Trustee and the exchange agent may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Subject to the transfer restrictions under applicable securities laws and the legends on the Global Notes, transfers between the Participants will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Subject to compliance with the transfer restrictions applicable to the notes described herein, cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for legended notes in certificated form, and to distribute such notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. None of us, the Trustee and any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

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Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes if:

(1) DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and, in either case, we fail to appoint a successor depositary;

(2) we, at our option, notify the Trustee in writing that they elect to cause the issuance of the Certificated Notes; provided that 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.

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.

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following discussion is a summary of certain U.S. federal income tax considerations relevant to the exchange of old notes for new notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. Some holders, including financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, persons whose functional currency is not the U.S. dollar, or persons who hold the notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction may be subject to special rules not discussed below.

We recommend that each holder consult his own tax advisor as to the particular tax consequences of exchanging such holder’s old notes for new notes, including the applicability and effect of any foreign, state, local or other tax laws or estate or gift tax considerations.

The exchange of old notes for new notes will not be an exchange or otherwise a taxable event to a holder for United States federal income tax purposes. Accordingly, a holder will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange, and the holder will have the same basis and holding period in the new note as it had in the corresponding old note immediately before the exchange.

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PLAN OF DISTRIBUTION

You may transfer new notes issued under the exchange offer in exchange for the old notes if:

• you acquire the new notes in the ordinary course of your business;

• you have no arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of such new notes in violation of the provisions of the Securities Act; and

• you are not our “affiliate” (within the meaning of Rule 405 under the Securities Act) or, if you are an “affiliate,” you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable; and.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities.

If you wish to exchange new notes for your old notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer — Purpose and Effect of the Exchange Offer” and “— Procedures for Tendering — Your Representations to Us” in this prospectus and in the letter of transmittal. In addition, if you are a broker-dealer who receives new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale by you of such new notes.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time on one or more transactions in any of the following ways:

• in the over-the-counter market;

• in negotiated transactions;

• through the writing of options on the new notes or a combination of such methods of resale;

• at market prices prevailing at the time of resale;

• at prices related to such prevailing market prices; or

• at 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 new notes.

Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities may be deemed to be an “underwriter” within the meaning of the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. We agreed to permit the use of this prospectus for a period of up to 180 days after the completion of the exchange offer by such broker-dealers to satisfy this prospectus delivery requirement. Furthermore, we agreed to use our best efforts to amend or supplement this prospectus during such period if so requested in order to expedite or facilitate the disposition of any new notes by broker-dealers.

We have agreed to pay all expenses incident to the exchange offer other than transfer taxes, if any, and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

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LEGAL MATTERS

The validity of the new notes being offered hereby and certain other legal matters will be passed upon by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements of RAAM Global Energy Company at December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

INDEPENDENT PETROLEUM ENGINEERS

The information included in this prospectus regarding estimated quantities of proved reserves applicable to our oil and natural gas properties as of December 31, 2010, were prepared or derived from estimates prepared by each of Netherland, Sewell & Associates, Inc. independent petroleum engineers, and H.J. Gruy and Associates, Inc., independent petroleum engineers, based on guidelines established by the SEC. These estimates applicable to our properties are included in this prospectus in reliance on the authority of such firm as experts in these matters.

AVAILABLE INFORMATION

We have filed with the SEC a registration statement on Form S-4 with respect to the new notes being offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the new notes offered by this prospectus, please review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of this material can also be obtained from the public reference section of the SEC at prescribed rates, or accessed at the SEC’s website at www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room.

The SEC’s proxy rules and regulations do not, nor do the rules of any stock exchange, require us to send an annual report to security holders or to holders of American depository receipts. Upon the effectiveness of this registration statement, we will become subject to the Exchange Act’s period reporting requirements, including the requirement to file current, annual, and quarterly reports with the SEC. The annual reports we file will contain financial information that has been examined and reported on, with an opinion by an independent certified public accounting firm.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

We have included below the definitions for certain oil and natural gas terms used in this prospectus:

“3-D seismic” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two dimensional, seismic.

“Analogous reservoir” Analogous reservoir, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an analogous reservoir refers to a reservoir that shares the following characteristics with the reservoir of interest: same geological formation (but not necessarily in pressure communication with the reservoir of interest), same environment of deposition, similar geological structure, and same drive mechanism.

“Basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl” One stock tank barrel or 42 United States gallons liquid volume of oil or other liquid hydrocarbons. “Bcf” One billion cubic feet of natural gas.

“Boe” One barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil. “Boepd” BOE per day.

“Bopd” Barrels of oil per day.

“Btu” A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one–pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

“Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Condensate” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“Developed acreage” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed oil and gas reserves” Reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

• gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, natural gas lines, and power lines, to the extent necessary in developing the proved reserves;

148

• drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly;

• acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

• provide improved recovery systems.

“Development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole or well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

“Farm-in” An agreement between a participant who brings a property into the venture and another participant who agrees to spend an agreed amount to explore and develop the property and has no right of reimbursement but may gain a vested interest in the venture. A “farm-in” describes the position of the participant who agrees to spend the agreed-upon sum of money to gain a vested interest in the venture.

“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation” A layer of rock which has distinct characteristics that differ from nearby rock.

“Gross acres or gross wells” The total acres or wells, as the case may be, in which a working interest is owned.

“Henry Hub” The pricing point for natural gas futures contracts traded on the NYMEX.

“Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Lease operating expenses” The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

“MBbl” One thousand barrels of oil or other liquid hydrocarbons. “MBoe” One thousand barrels of oil equivalent.

“Mcf” One thousand cubic feet of natural gas.

“Mcfpd” One thousand cubic feet of natural gas per day.

“MMBbl” One million barrels of oil or other liquid hydrocarbons. “MMBoe” One million barrels of oil equivalent.

“MMBtu” One million British thermal units.

149

“MMcf” One million cubic feet of natural gas.

“MMcfpd” One million cubic feet of natural gas per day.

“Natural gas liquids” The hydrocarbon liquids contained within natural gas.

“Net acres or net wells” The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

“NYMEX” The New York Mercantile Exchange. “Oil” Crude oil and condensate.

“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.

“PDNP” Proved developed non-producing. “PDP” Proved developed producing.

“Plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

“Producing well” A well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

“Production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and natural gas produced. Examples of production costs (sometimes called lifting costs) are:

• costs of labor to operate the wells and related equipment and facilities;

• repairs and maintenance;

• materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities;

• property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and

• severance taxes.

“Productive well” An exploratory, development or extension well that is not a dry well.

“Proved reserves” Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless

150

geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“PUD” Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

“Reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

“Recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserve life” A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years.

“Reserves” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

151

“Sand” A geological term for a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.

“Shallow water” Water at a depth of less than 500 feet.

“Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Successful well” A well capable of producing oil and/or natural gas in commercial quantities.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“Wellbore” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

“Working interest” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover” Operations on a producing well to restore or increase production.

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INDEX TO FINANCIAL STATEMENTS

RAAM GLOBAL ENERGY COMPANY

AND SUBSIDIARIES

Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2010 and 2009	F-3
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008	F-5
Consolidated Statements of Shareholders’ Equity for the years ended December  31, 2010, 2009 and 2008	F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008	F-7
Notes to Consolidated Financial Statements	F-8
Supplemental Oil and Gas Data (unaudited)	F-33
Unaudited Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010	F-38
Condensed Consolidated Statements of Operations for the three and six months ended June  30, 2011 and 2010	F-40
Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010	F-41
Notes to Unaudited Condensed Consolidated Financial Statements	F-42

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors of RAAM Global Energy Company

We have audited the accompanying consolidated balance sheets of RAAM Global Energy Company as of December 31, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity, 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. We were not engaged to perform an audit of the Company’s 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of RAAM Global Energy Company at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 5 to the consolidated financial statements, during 2009 the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

/s/ ERNST & YOUNG LLP

Louisville, Kentucky

March 17, 2011

F-2

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

	December 31 2010			December 31 2009
Assets
Current assets:
Cash and cash equivalents	$	81,032		$	28,888
Accounts receivable, net of $235 provision for bad debts in 2010 and 2009		22,412			4,692
Revenues receivable		21,703			26,279
Insurance receivable		—			6,050
Income taxes receivable		2,955			—
Commodity derivatives – current portion		9,377			26,996
Prepaid assets		4,200			6,857
Other current assets		3,784			3,921
Total current assets		145,463			103,683
Oil and gas properties (full-cost method):
Properties being amortized		1,009,071			903,365
Properties not subject to amortization		81,656			113,378
Less accumulated depreciation, depletion, and amortization		(653,777	)		(583,830	)
Net oil and gas properties		436,950			432,913
Other assets:
Other capitalized assets, net		7,246			7,227
Commodity derivatives		263			3,480
Equity investments		2,044			7,350
Other		5,320			1,195
Total other assets		14,873			19,252
Total assets	$	597,286		$	555,848

See accompanying notes to consolidated financial statements.

F-3

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

	December 31 2010			December 31 2009
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	19,587		$	25,181
Revenues payable		17,834			19,206
Interest payable – senior secured notes		5,048			—
Current taxes payable		924			314
Advances from joint interest partners		—			1,053
Commodity derivatives – current portion		1,973			—
Asset retirement obligations – current portion		2,406			2,543
Long-term debt – current portion		1,112			1,142
Deferred income taxes – current portion		1,810			8,803
Total current liabilities		50,694			58,242
Other liabilities:
Commodity derivatives		861			—
Asset retirement obligations		20,946			17,462
Long-term debt		2,860			112,980
Senior secured notes		148,681			—
Deferred income taxes		90,870			103,114
Total other liabilities		264,218			233,556
Total liabilities		314,912			291,798
Commitments and contingencies (see Note 15)
Noncontrolling interest		2,467			5,551
Shareholders’ equity:
Common stock, no par value, 380,000 shares authorized, 60,000 issued and outstanding in 2010 and 2009, respectively		56,096			56,096
Treasury stock, 5,166 shares in 2010 and 2009, respectively		(5,736	)		(5,736	)
Accumulated other comprehensive income, net of taxes		5,977			20,822
Retained earnings		223,570			187,317
Total shareholders’ equity		279,907			258,499
Total liabilities and shareholders’ equity	$	597,286		$	555,848

See accompanying notes to consolidated financial statements.

F-4

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

	2010			2009			2008
Revenues:
Gas sales	$	117,176		$	154,519		$	127,747
Oil sales		80,632			84,262			78,990
Insurance proceeds – business interruption		—			20,207			2,660
Total revenues		197,808			258,988			209,397
Costs and expenses:
Production and delivery costs		31,569			25,831			19,188
Workover costs		10,470			8,439			11,444
Depreciation, depletion and amortization		71,954			150,423			90,445
General and administrative expenses		16,633			18,119			10,418
Bad debt expense		98			2,454			—
Derivative (income) expense		(555	)		136			(1,007	)
Total operating expense		130,169			205,402			130,488
Income from operations		67,639			53,586			78,909
Other income (expenses):
Interest expense, net		(8,781	)		(3,986	)		(1,726	)
Gain on sale of oil and gas properties		—			—			48,208
Loss on disposal of inventory and properties		(1,463	)		(1,257	)		—
Income (loss) from equity investment		(5,156	)		492			(7,561	)
Other, net		434			861			469
Total other income (expenses)		(14,966	)		(3,890	)		39,390
Income before taxes		52,673			49,696			118,299
Income tax provision		13,440			23,995			44,585
Net income including noncontrolling interest	$	39,233		$	25,701		$	73,714
Net income attributable to noncontrolling interest (net of tax)		1,682			715			1,442
Net income attributable to RAAM Global	$	37,551		$	24,986		$	72,272

See accompanying notes to consolidated financial statements.

F-5

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED STATEMENTS OF

SHAREHOLDERS’ EQUITY

(In thousands, except share data)

	Common Stock						Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Shares			Amount
Balance, January 1, 2008		55,299		$	45,927		$	(5,305	)	$	106,174		$	(1,098	)	$	145,698
Issuance of common stock		100			163												163
Treasury stock
Change in noncontrolling interest											(5,091	)					(5,091	)
Payment of dividends											(5,537	)					(5,537	)
Comprehensive income (loss):
Net income											72,272						72,272
Changes in fair value of hedges, net of taxes of $31,681														59,169			59,169
Comprehensive income																	131,441
Balance, December 31, 2008		55,399		$	46,090		$	(5,305	)	$	167,818		$	58,071		$	266,674
Issuance of common stock		4,761			12,850												12,850
Treasury stock		(160	)					(431	)								(431	)
Purchase of noncontrolling interest					(2,844	)											(2,844	)
Change in noncontrolling interest											176						176
Payment of dividends											(5,663	)					(5,663	)
Comprehensive income (loss):
Net income											24,986						24,986
Changes in fair value of hedges, net of taxes of $21,848														(37,249	)		(37,249	)
Comprehensive loss																	(12,263	)
Balance, December 31, 2009		60,000		$	56,096		$	(5,736	)	$	187,317		$	20,822		$	258,499
Change in noncontrolling interest											4,702						4,702
Payment of dividends											(6,000	)					(6,000	)
Comprehensive income:
Net income											37,551						37,551
Changes in fair value of hedges, net of taxes of $9,380														(14,845	)		(14,845	)
Comprehensive income																	22,706
Balance, December 31, 2010		60,000		$	56,096		$	(5,736	)	$	223,570		$	5,977		$	279,907

See accompanying notes to consolidated financial statements.

F-6

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	2010			2009			2008
Operating activities
Net income including noncontrolling interest	$	39,233		$	25,701		$	73,714
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		73,550			150,658			90,445
Deferred income taxes		(19,237	)		(12,293	)		61,544
Gain on sale of oil and gas properties		—			—			(48,208	)
Loss on disposal of inventory and properties, net		1,463			657			—
Impairment of equity method investment		5,156			—			—
Changes in components of working capital:
Accounts and revenues receivable		687			15,036			5,762
Insurance receivable		6,050			6,700			(12,750	)
Income tax receivables		(2,955	)		325			(24	)
Other current assets		2,370			(3,756	)		(1,054	)
Other non-current assets		—			2,400			—
Change in derivatives, net		8,825			22,602			(32,829	)
Accounts payable and accrued liabilities		(5,219	)		(14,075	)		(2,820	)
Current taxes payable		610			(6,918	)		7,233
Interest payable on Senior Notes		5,048			—			—
Revenues payable		(1,372	)		(1,532	)		(18,612	)
Net cash provided by operating activities		114,209			185,505			122,401
Investing activities
Change in restricted cash		—			2,000			18
Change in investments		150			(150	)		(52,264	)
Change in advances from joint interest partners		(1,052	)		658			(288	)
Additions to oil and gas properties and equipment		(86,936	)		(137,794	)		(193,350	)
Purchase of noncontrolling interest		—			(7,048	)		—
Proceeds from net sales of oil and gas properties		—			—			54,362
Net cash used in investing activities		(87,838	)		(142,334	)		(191,522	)
Financing activities
Proceeds from long-term borrowings		8,874			9,206			61,855
Payments on long-term borrowings		(119,024	)		(24,043	)		(11,179	)
Deferred loan costs		—			(1,409	)		—
Proceeds from issuance of 12.5% Senior Notes due 2015		148,629			—			—
Deferred bond costs		(6,701	)		—			—
Proceeds from issuance of common stock		—			—			163
Treasury stock		—			(431	)		—
Payment of dividends		(6,000	)		(5,663	)		(5,537	)
Other		(5	)		5			—
Net cash provided by (used in) financing activities		25,773			(22,335	)		45,302
Increase (decrease) in cash and cash equivalents		52,144			20,836			(23,819	)
Cash and cash equivalents, beginning of period		28,888			8,052			31,871
Cash and cash equivalents, end of period	$	81,032		$	28,888		$	8,052

See accompanying notes to consolidated financial statements.

F-7

RAAM GLOBAL ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Business

RAAM Global Energy Company (RAAM Global or the Company) is engaged primarily in the exploration and development of oil and gas properties and in the resulting production and sale of natural gas, condensate and crude oil. The Company’s production facilities are located in the Gulf of Mexico, offshore Louisiana and onshore Mississippi, Louisiana, Texas, and Oklahoma.

2. Significant Accounting Policies

Basis of Accounting and Principles of Consolidation

The accompanying consolidated financial statements are presented on the accrual basis of accounting in accordance with U.S. generally accepted accounting principles. The accompanying consolidated financial statements of RAAM Global include the accounts of RAAM Global, its wholly-owned subsidiaries, its majority-owned joint venture and variable interest entities where RAAM Global is the primary beneficiary. Significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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 may differ from those estimates. The Company’s most significant financial estimates are based on remaining proved oil and gas reserves.

Financial Instruments

The Company considers all highly liquid financial instruments with an original maturity of three months or less to be cash equivalents.

The Company includes fair value information in the notes to financial statements when the fair value of its financial instruments is different from the book value. The book values of those financial instruments that are classified as current assets or liabilities approximate fair value because of the short maturity of those instruments. The fair value of the Senior Secured Notes approximates the carrying value as of December 31, 2010, due to the short amount of time these notes have been on the market. The fair values of other borrowings approximate the carrying amounts as of December 31, 2010 and 2009, due to the variable interest features associated with these debt instruments.

Oil and Gas Properties

The Company uses the full-cost method of accounting for exploration and development costs. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including interest related to significant properties being evaluated and directly related overhead costs, are capitalized. Capitalized overhead costs amounted to $4.6 million, $5.5 million and $3.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.

All capitalized costs of oil and gas properties are amortized through depreciation, depletion and amortization (DD&A) using the future gross revenue method whereby the annual provision is computed by dividing revenue earned during the period by future gross revenues at the beginning of the period, and applying the resulting rate to the cost of oil and gas properties, including estimated future development and abandonment costs.

F-8

Investments in unproved properties and major development projects are not amortized until proved reserves are attributed to the projects or until impairment occurs. If the results of an assessment indicate that the properties are impaired, that portion of such costs is added to the capitalized costs to be amortized.

Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties were $81.7 million and $113.4 million at December 31, 2010 and December 31, 2009, respectively. The Company believes that the unevaluated properties at December 31, 2010 will be substantially evaluated during 2011, 2012 and 2013, and the costs will begin to be amortized at that time. The Company capitalized interest of $736,000, $0 and $2.2 million during the years ended December 31, 2010, 2009 and 2008, respectively, related to significant properties not subject to amortization.

Capitalized oil and gas property costs are subject to a “ceiling test,” which limits such costs to the aggregate of the estimated present value, discounted at 10%, of future net cash flows from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects. Details specific to the Company’s ceiling tests for the periods presented in the accompanying consolidated financial statements are discussed in Note 5, Property, Plant and Equipment and Asset Retirement Obligations.

Sales of proved and unproved properties are accounted for as adjustments of 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, in which case the gain or loss is recognized in current income.

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. See Note 14 for further information.

Other capitalized assets

Buildings, office equipment, software, furniture, fixtures, and leasehold equipment are depreciated over their estimated useful lives (2 – 32 years) using the straight-line method. See Note 5, Property, Plant and Equipment and Asset Retirement Obligations, for additional information.

Hedging Activities

The Company’s revenues are primarily the result of sales of its oil and natural gas production. Market prices of oil and natural gas may fluctuate and affect operating results. The Company engages in hedging activities that primarily include the use of floors, costless collars and futures transactions in order to minimize the downside risk from adverse price movements but allow for the realization of upside profits, if available. Costs and any benefits derived from the effective hedge portions of these activities are reflected in revenues from oil and gas production.

The Company follows the provisions of the Financial Accounting Standards Board (“FASB”) guidance related to accounting for derivative instruments and hedging activities. This guidance requires all derivatives to be reported as assets or liabilities at their fair values, and the balance-sheet caption Commodity Derivatives is being used in the accompanying consolidated balance sheets for this purpose. This guidance also imposes additional documentation requirements in order for derivatives to be accounted for as hedges of future risks. The Company designated all new commodity derivative instruments entered into in 2010 and 2009 as hedges for accounting purposes, so the related unrealized changes in their fair values are reported net of tax in the accompanying consolidated balance sheet as a component of other comprehensive income. Any hedge ineffectiveness (which represents the amount by which the change in fair value of the derivative exceeds the change in cash flows of the forecasted transaction) is recorded in current-period earnings in the accompanying consolidated statement of operations in Derivative (income) expense. Hedge ineffectiveness of actual monthly settlements is also recorded as hedging (losses) gains in Gas sales and Oil sales in the accompanying consolidated statement of operations.

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During the year ended December 31, 2010 and December 31, 2009, the amounts of other comprehensive income related to hedge transactions that settled and is recorded in the accompanying consolidated statements of operations were $17.5 million and $44.0 million, respectively, net of tax effects. During the year ended December 31, 2008, the amount of other comprehensive loss related to hedge transactions that settled and is recorded in the accompanying consolidated statements of operations was $1.1 million. The Company anticipates the amount of other comprehensive income related to hedge transactions that will settle during the next twelve months and be recorded in the 2011 consolidated statements of operations will be $4.8 million, net of tax effects.

Income Taxes

The Company follows FASB guidance on accounting for income taxes. The asset and liability method prescribed by this guidance requires recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the tax bases and financial reporting bases of assets and liabilities.

Revenue Recognition and Taxes Remitted to Governmental Authorities

The Company recognizes natural gas and oil sales from its interests in producing wells under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled, based on its interest in the properties. Gas balancing obligations as of December 31, 2010, 2009 and 2008 were not significant. The Company has adopted a policy of netting severance taxes paid to governmental authorities within oil and gas sales on the accompanying consolidated statement of operations. Severance taxes paid to governments were $5.7 million, $5.9 million and $9.6 million for 2010, 2009 and 2008, respectively.

Accounting for Asset Retirement Obligations

In accordance with the provisions of FASB guidance related to accounting for asset retirement obligations and FASB guidance on accounting for conditional asset retirement obligations, costs associated with the retirement of fixed assets (e.g., oil and gas production facilities, etc.) that the Company is legally obligated to incur are accrued. The fair value of the obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the fixed asset and are depreciated over the life of the applicable asset. The asset retirement cost recorded in oil and gas properties being amortized at December 31, 2010 was $18.8 million. Accretion of the discounted asset retirement obligations is recognized as an increase in the carrying amount of the liability and as an expense within depreciation, depletion and amortization on the accompanying consolidated statement of operations. See Note 5, Property, Plant and Equipment and Asset Retirement Obligations, for additional information.

Reclassifications

Certain prior year amounts have been reclassified in the accompanying consolidated financial statements to conform with the 2010 presentation. Such reclassifications are not material to the accompanying consolidated financial statements.

Operating Segments

The Company operates in one business segment — the exploration, development and sale of oil and gas.

Subsequent events

Management has reviewed subsequent events through the filing date, March 17, 2011.

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New Accounting Pronouncements

In June 2009, the FASB issued accounting guidance on the consolidation of variable interest entities (“VIEs”). This new guidance revises previous guidance by replacing the quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a VIE with a qualitative approach focused on identifying which enterprise has both the power to direct the activities of the VIE that most significantly impacts the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits that could be significant to the entity. In addition, this guidance requires reconsideration of whether an entity is a VIE when any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of the entity that most significantly impact the entity’s economic performance. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE and additional disclosures about an enterprise’s involvement in variable interest entities. This guidance is effective for fiscal years beginning after November 15, 2009. Our adoption of the new guidance during the first quarter of 2010 did not have a material effect on our consolidated financial statements.

In January 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-06,Fair Value Measurements and Disclosures (“ASU 2010-06”) which requires new disclosures and clarifies existing disclosures required under current fair value guidance. Under the new guidance, a reporting entity must 1) disclose separately gross transfers in and gross transfers out of Levels 1 and 2 and 2) include separate presentation of purchases, sales, issuances and settlements rather than net presentation in the Level 3 reconciliation. The ASU also amends required levels of disaggregation of asset classes and expands information required as to inputs and valuation techniques for recurring and non-recurring Level 2 and 3 measurements. With the exception of the disclosures in 2 above, the new disclosures became effective for interim and annual reporting periods beginning after December 15, 2009. Items in 2 above become effective one year later. Although it will expand disclosures the change did not and will not have a material effect on the Company.

In July 2010, the FASB issued ASU No. 2010-20,Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses(“ASU 2010-20”). The amendments of ASU 2010-20 require enhanced disclosures regarding the nature of credit risk in a company’s financing receivables and how that risk is analyzed. Disclosures required by ASU 2010-20 include credit quality indicators, non-accrual and past due information, and modifications of financing receivables. Sales-type and direct financing capital leases are in scope of the new requirements though trade accounts receivable that arose from the sale of goods or services and have contractual maturities of one year or less are specifically excluded. End of period disclosures will be effective for year-end 2010. Disclosures regarding activity will be effective in the first quarter of 2011. The amendments of ASU 2010-20 will have no impact on the Company’s consolidated financial results as these changes relate only to disclosures.

The FASB also issued several accounting standards updates during 2010, not discussed above, related to technical corrections of existing guidance or new guidance that is not meaningful to the Company’s current financial statements.

3. Fair Value Measurements

FASB guidance establishes a three-level hierarchy for fair value measurements. The hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date.

• Level 1 – Valuation is based upon unadjusted quoted prices for identical assets or liabilities in active markets.

• Level 2 – Valuation is based upon quoted prices for similar assets and liabilities in active markets, or other inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

• Level 3 – Valuation is based upon other unobservable inputs that are significant to the fair value measurements.

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The classification of fair value measurements within the hierarchy is based upon the lowest level of input that is significant to the measurement. At December 31, 2010 and 2009, the Company’s commodity derivative contracts were recorded at fair value. The fair values of these instruments were measured using valuations based upon quoted prices for similar assets and liabilities in active markets (Level 2) and are valued by reference to similar financial instruments, adjusted for credit risk and restrictions and other terms specific to the contracts.

Description	Book Value		Fair Value Measurements Using Significant Other Observable Inputs (Level 2)
	In thousands
Commodity derivatives December 31, 2010	$	6,806	$	6,806
Commodity derivatives December 31, 2009	$	30,476	$	30,476

4. Accounts and Revenues Receivable

Accounts and revenues receivable at December 31, 2010 and 2009 were $44.1 million and $31.0 million, respectively, all of which were due from companies in the oil and gas industry. Of the revenues receivable, $19.7 million was due from five companies and $25.7 million was due from five companies at December 31, 2010 and December 31, 2009, respectively. In addition, the Company had accrued insurance claims receivable of $6.1 million at December 31, 2009 related to Hurricane Ike for business interruption coverage, re-drilling of a well and costs to repair previously capitalized oil and gas properties. All insurance receivables recorded at December 31, 2009 were collected during 2010.

Since all of RAAM Global’s accounts receivable from purchasers and joint interest owners at December 31, 2010 and December 31, 2009 resulted from sales of crude oil, condensate, natural gas and/or joint interest billings to third-party companies in the oil and gas industry, this concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Management believes that allowances for doubtful accounts were adequate to absorb estimated losses as of December 31, 2010 and December 31, 2009. Management obtains letters of credit from its major purchasers and continually evaluates the creditworthiness of its partners.

The Company sold natural gas and oil production representing 10% or more of its natural gas and oil revenues for the years ended December 31, 2010, 2009 and 2008 to the following customers as listed below. In the exploration, development, and production business, production is normally sold to relatively few customers. However, based on the current demand for natural gas and oil, management believes that the loss of any major customers would not have a material adverse effect on operations. The Company believes that it could replace any one of the major customers if necessary without a major disruption in sales.

	2010			2009			2008
Company A		45	%		45	%		39	%
Company B		20	%		29	%		23	%
Company C		9	%		12	%		25	%
Company D		12	%		9	%		11	%

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5. Property, Plant and Equipment and Asset Retirement Obligations

Property, plant and equipment consisted of the following at December 31,

	December 31,
	2010			2009
	(In thousands)
Oil and natural gas properties (full cost method):
Properties being amortized	$	1,009,071		$	903,365
Properties not subject to amortization		81,656			113,378
Total oil and natural gas properties		1,090,727			1,016,743
Less accumulated depreciation, depletion and amortization		(653,777	)		(583,830	)
Net oil and gas properties		436,950			432,913
Land		1,025			1,025
Buildings and improvements		6,388			6,388
Office equipment and software		4,128			3,602
Leased equipment		345			345
Furniture and fixtures		713			646
Total		12,599			12,006
Less accumulated depreciation		(5,353	)		(4,779	)
Net capitalized costs		7,246			7,227
Property, plant and equipment, net	$	444,196		$	440,140

The Company utilizes useful lives of 31.5 years for buildings, 3 to 5 years for office equipment and software, 2 to 5 years for leased equipment and 7 years for furniture and fixtures when calculating depreciation.

Oil and Gas Properties

In January 2010, the Company adopted FASB guidance on oil and gas reserve estimation and disclosures. This guidance amends previous FASB guidance on oil and gas extractive activities to align the accounting requirements with the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements issued on December 31, 2008. In summary, the revisions in this guidance modernize the disclosure rules to better align with current industry practices and expand the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:

• An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.

• The use of an average of the first-day-of-the-month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.

• Amended definitions of key terms such as “reliable technology” and “reasonable certainty” which are used in estimating proved oil and gas reserve quantities.

• A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.

• Clarification that an entity’s equity investments must be considered in determining whether it has significant oil and gas activities and a requirement to disclose equity method investments in the same level of detail as is required for consolidated investments.

The new rules are considered a change in accounting principle that is inseparable from a change in accounting estimate, which does not require retroactive revision. This change in accounting principle has had a material effect on the consistency of the Company’s oil and gas reserve estimates, supplemental disclosures, the

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calculation of DD&A and the full-cost ceiling test. For the year ended December 31, 2010, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $75.96 per barrel of oil and $4.38 per MMBtu of natural gas. At December 31, 2009, the Company’s ceiling test computation resulted in a write-down of oil and gas properties of $44.7 million based on twelve-month average prices of $57.65 per barrel of oil and $3.87 per MMBtu of natural gas. In addition to lower natural gas and crude oil price assumptions, the December 31, 2009 write-down was primarily the result of lower than anticipated success rate on new drilling and higher than expected capital expenditures incurred.

Sale of Oil and Gas Properties

During the fourth quarter of 2010, the Company finalized an agreement to sell approximately 69,000 acres onshore Louisiana to an unrelated third party oil and gas company. The final sales price amounted to $13.7 million and is recorded in accounts receivable and as an accumulated reduction to our net oil and gas properties on the accompanying consolidated balance sheet. Under the full cost accounting method, the transaction is recorded as a reduction to net oil and gas properties with no income statement impact because the original cost of the acreage is not a significant percentage of the Company’s consolidated capitalized costs. The cash payment was collected during January 2011, pursuant to the agreement.

Asset Retirement Obligations

The change in the Company’s asset retirement obligations (ARO) is set forth below:

	In thousands
Balance of ARO as of January 1, 2008	$	15,416
Accretion expense		844
Additions		1,420
Settlements of ARO		(2,654	)
Changes in ARO estimate		5,230
Balance of ARO as of December 31, 2008	$	20,256
Accretion expense		727
Additions		818
Settlement of ARO		(2,582	)
Changes in ARO estimate		786
Balance of ARO as of December 31, 2009	$	20,005
Accretion expense		1,434
Additions		655
Settlement of ARO		(1,415	)
Changes in ARO estimate		2,673
Balance of ARO as of December 31, 2010	$	23,352

The change in estimate during 2010 was primarily due to changes in estimated future prices to perform plugging and abandonment work in shallow waters.

The asset retirement cost recorded in oil and gas properties being amortized at December 31, 2010 and 2009 was $18.8 million and $16.8 million, respectively.

6. Commodity Derivative Instruments and Hedging Activities

In order to manage the variability in cash flows associated with the sale of its oil and gas production, the Company has developed a strategy to combine the use of floors, costless collars and futures transactions in order to minimize the downside risk from adverse price movements but allow for the realization of upside profits, if available. The use of derivatives involves the risk that the counterparties to such instruments will be unable to

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meet the financial terms of those contracts. At December 31, 2010, Shell Energy North America (US), L.P., Union Bank of California N.A., BNP BARIBAS, NATIXIS and Regions Bank are the derivatives counterparties being used by the Company.

With respect to any collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price of such transaction. For any particular floor contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with the settlement of a floor contract. Monthly settlements of these contracts are reflected in revenue from oil and gas production.

All of the Company’s commodity derivative transactions are settled based on reported settlement prices on the NYMEX. The estimated fair value of these transactions is based on various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The calculation of the fair value of collars and floors utilizes the Black-Scholes option-pricing model. Since these transactions were designated as hedges, the Company is required to record the changes in fair value of these transactions as Other Comprehensive Income in the accompanying consolidated balance sheets with the ineffective portion of the change in fair value reported as Derivative (income) expense in the accompanying consolidated statements of operations. See Note 2, Significant Accounting Policies for additional information on the Company’s hedging activities.

At December 31, 2010, $6.8 million represents the fair value of the commodity derivatives. This $6.8 million is made up $9.6 million in assets, which is recorded in both current and long term assets and $2.8 million in liabilities recorded in current and long-term liabilities and the net amount is recorded as a net of tax deferred income item in accumulated other comprehensive income in the consolidated balance sheet less hedge ineffectiveness. Hedge ineffectiveness was $1.8 million for 2010. At December 31, 2009, $30.5 million represents the fair value of the commodity derivatives and is recorded as current and long-term assets and as a net of tax deferred income item in accumulated other comprehensive income in the consolidated balance sheet less hedge ineffectiveness. Hedge ineffectiveness was $0.6 million for 2009.

For the year ended December 31, 2010, the Company realized a net increase in oil and gas revenues related to hedging transactions of approximately $42.9 million. For the year ended December 31, 2009, the Company realized a net increase in oil and gas revenues related to hedging transactions of approximately $103.7 million. For the year ended December 31, 2008, the Company realized a net decrease in oil and gas revenues related to hedging transactions of approximately $6.1 million.

As of December 31, 2010, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast natural gas production for 2011 and 2012:

Remaining Contract Term	Contract Type		Volume in MMBtus/Month		NYMEX Strike Price
January 2011 – March 2011		Swap		250,000	$	7.42
January 2011 – March 2011		Swap		150,000	$	6.97
January 2011 – March 2011		Swap		150,000	$	6.95
January 2011 – June 2011		Swap		100,000	$	6.87
January 2011 – August 2011		Put		250,000	$	6.50
April 2011 – May 2011		Swap		150,000	$	6.50
April 2011 – December 2011		Swap		100,000	$	6.24
July 2011 – December 2011		Swap		100,000	$	6.33
January 2012 – February 2012		Swap		100,000	$	6.24
January 2012 – February 2012		Swap		100,000	$	6.33

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As of December 31, 2010, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast oil production for 2011 and 2012:

Remaining Contract Term	Contract Type		Volume in Bbls/Month		NYMEX Contract Price per Bbl
January 2011 – December 2011		Swap		6,000	$	86.76
January 2011 – December 2011		Swap		6,000	$	85.70
January 2011 – December 2011		Swap		10,000	$	85.25
January 2011 – December 2011		Swap		8,000	$	88.20
January 2011 – December 2011		Swap		9,000	$	85.50
January 2012 – March 2012		Swap		10,000	$	89.00
January 2012 – March 2012		Swap		8,000	$	88.24
January 2012 – March 2012		Swap		6,000	$	86.80
April 2012 – June 2012		Swap		6,000	$	88.52
April 2012 – June 2012		Swap		6,000	$	87.05
April 2012 – June 2012		Swap		5,000	$	87.50
July 2012 – September 2012		Swap		12,000	$	88.76
July 2012 – September 2012		Swap		5,000	$	87.80

Additional information regarding derivatives can be referenced in Note 3, Fair Value Measurements.

7. Equity Method Investments

Attune Australia

In November 2007, the Company purchased a 50% interest in Attune Australia LLC (“Attune”) for $7.2 million from RAAM Exploration LLC. Concordia Resources Inc., a related party, owns the remaining 50% of Attune Australia LLC. Attune’s operations consist of its ownership of an overriding royalty interest in an Australian oil field that began producing oil in November 2007. Due to the Company’s ability to exercise significant influence on this entity, the Company has accounted for the investment in Attune using the equity method.

The Company evaluates its equity method investments on a quarterly basis to ensure proper accounting treatment is being applied. During the Company’s equity method investment review in the fourth quarter of 2010, the Company researched information on the oil field and found reserve information published on the operator’s website, which the Company used to perform an economic reserve run. The results of this analysis led the Company to determine that the Attune investment had incurred an other than temporary impairment (“OTTI”). The company performed a discounted cash flow analysis using risk adjusted discount rates to estimate the current fair value of the Attune investment. The result of this analysis was a $5.2 million OTTI charge, which was recorded in the Consolidated Statements of Operation in (Loss) Income from Equity Method Investments.

Former Equity investment

During 2008, the Company became a 50% member of a limited liability company (the LLC) that participates as a working interest and revenue owner in certain of its oil and gas properties. The remaining 50% of the LLC units are owned by three unrelated third party entities. The Company contributed $60 million and $10.3 million of oil and gas properties to the LLC during 2008 and 2009, respectively. One member of the LLC did not make a contribution in 2009; this resulted in an increase in the Company’s ownership from 50% to 51%. This investment was accounted for using the equity method for 2008 and the first six months of 2009. The Company recorded its share of the entity’s net income and net loss, $0.5 million at June 30, 2009 and $(7.6) million at December 31, 2008, respectively, as income (loss) on equity investment in the accompanying consolidated statements of operations. On June 30, 2009, the Company withdrew its 51% share of the assets, liabilities, working interests and net revenue interests from the LLC. The Company owned $3.3 million of cash, $60.4 million of net oil and

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gas properties, and a $0.6 million asset retirement obligation. These values are included within the Company’s consolidated financial statements, and the Company’s share of the LLC reserves are included in the year end 2010 and 2009 reserve report information disclosed in the attached unaudited supplemental oil and gas data.

8. Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following at December 31, 2010 and 2009:

	December 31,
	2010		2009
Accounts payable	$	11,639	$	13,582
Oil and gas property costs accrual		4,850		7,062
Production and delivery costs accrual		1,733		—
Salaries and benefits accrual		888		3,267
Other		477		1,270
Total Accounts payable and Accrued liabilities	$	19,587	$	25,181

9. Debt

2015 Senior Secured Notes

On September 24, 2010, the Company completed an offering of $150.0 million senior secured notes at a coupon rate of 12.50% (the “2015 Senior Secured Notes”) with a maturity date of October 1, 2015. The interest on the 2015 Senior Secured Notes will be payable in cash semi-annually in arrears on April 1 and October 1 of each year, commencing on April 1, 2011, to holders of record at the close of business on the preceding March 15 or September 15. Interest on the notes will be computed on the basis of a 360-day year of twelve 30-day months. The notes were sold at 99.086% of their face amount and were recorded at their discounted amount, with the discount to be amortized over the life of the notes. The Company used a portion of the net proceeds from the offering to repay all outstanding indebtedness under the revolving credit facility and intends to use the remainder of the proceeds for funding a portion of the planned capital expenditures for development and drilling in 2011. As of December 31, 2010, $150.0 million notional amount of the 2015 Senior Secured Notes was outstanding. The carrying amount of the 2015 Senior Secured Notes was $148.7 million, net of discount, as of December 31, 2010.

The holders of the 2015 Senior Secured Notes entered into an Intercreditor Agreement with Union Bank, N.A. in its capacity as administrative agent for the First Lien Creditors who are parties to the Amended Revolving Credit Facility. The Intercreditor Agreement states that the holders of the 2015 Senior Secured Notes are Second Lien Note Holders and are collateralized by a second lien on all properties as collateralized by the First Lien Creditors.

The senior notes contain typical restrictions on liens, mergers and sales of assets. Until October 1, 2014, the Company may redeem up to 35% of the aggregate principal amount of the 2015 Senior Secured Notes at a price equal to 112.50% of the principal amount, plus accrued and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings. On or after October 1, 2014 until March 31, 2015, the Company may redeem some or all of the 2015 Senior Secured Notes at an initial redemption price equal to par value plus one-half the coupon plus accrued and unpaid interest to the date of redemption. On or after April 1, 2015, the Company may redeem some or all of the 2015 Senior Secured Notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption. The Company may also redeem some or all of the 2015 Senior Secured Notes at any time prior to October 1, 2014 at the “make-whole” prices and at any time on or after April 1, 2015 at par.

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Amended Revolving Credit Facility

On September 24, 2010, an amendment to the Company’s Revolving Credit Facility established a new borrowing base of $62.5 million which was undrawn at December 31, 2010. The Credit Agreement governing the amended revolving credit facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments, and distributions. The Company is in compliance with these debt covenants at December 31, 2010. The maturity date is September 3, 2012.

Promissory Note

The Company has a promissory note with GE Commercial Finance Business Property Corporation (“GECF”) in the amount of $3.5 million related to the construction of the Houston office building. The GECF note requires monthly installments of principal and interest in the amount of $27,000 until September 1, 2025. There are no covenant requirements under this note. The effective interest rate on this note was 7.05% at December 31, 2010 and 2009.

Finance Agreement

During May 2010, the Company entered into an agreement to finance the premiums for its annual insurance policies with Premium Assignment Corporation. The finance agreement requires monthly installments of principal and interest in the amount of $1.0 million until February 1, 2011. There are no covenant requirements under this agreement. The effective interest rate on this agreement was 4.92% at December 31, 2010 and 2009.

Long-term Debt Maturities

The future estimated maturities of long-term debt are as follows:

Year ending December 31:	In thousands
2011	$	1,112
2012		128
2013		137
2014		147
2015		150,158
Thereafter		2,290
Total	$	153,972

Cash payments for interest totaled $3.4 million, $4.0 million and $4.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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10. Income Taxes

Deferred income taxes reflect the net effects on temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2010 and 2009 are as follows:

	December 31,
	2010			2009
Deferred tax assets:
Asset retirement obligation	$	8,531		$	7,605
Equity investment in unconsolidated subsidiary		1,906			—
Net operating loss carryforward		3,268			3,132
	$	13,705		$	10,737
Deferred tax liabilities:
Property & equipment	$	(103,615	)	$	(105,992	)
Commodity derivatives & swap		(2,575	)		(11,648	)
Section 1031 transaction		—			(4,665	)
Other		(195	)		(349	)
	$	(106,385	)	$	(122,654	)

Deferred income taxes as of December 31, 2010 and 2009 are classified in the accompanying consolidated balance sheets as follows:

	December 31,
	2010			2009
Current liabilities	$	(1,810	)	$	(8,803	)
Long term liabilities		(90,870	)		(103,114	)
	$	(92,680	)	$	(111,917	)

The principal components of income tax provision (benefit) for the years ended December 31 are as follows:

	2010			2009			2008
Current income tax expense:
Federal	$	21,234		$	30,129		$	12,733
State and local		2,064			5,554			2,167
	$	23,298		$	35,683		$	14,900
Deferred income tax (benefit) expense:
Federal	$	(2,781	)	$	(13,741	)	$	27,637
State and local		(7,077	)		2,053			2,048
	$	(9,858	)	$	(11,688	)	$	29,685
Total income tax provision	$	13,440		$	23,995		$	44,585

Cash payments for income taxes totaled $26.8 million, $42.4 million and $7.9 million for the years ended December 31, 2010, 2009 and 2008, respectively. Interest and penalties are recorded as a component of income tax provision. The Company paid $380,000 in penalties to the U.S. Federal jurisdiction during 2010 related to the 2009 tax year.

F-19

RAAM Global’s 2010, 2009 and 2008 effective tax rates are 25.5%, 48.7% and 37.9%, respectively, and are comprised of the following:

	RAAM Global
	2010			2009			2008
Statutory federal income tax rate		35.0	%		35.0	%		34.2	%
State and local taxes, net of federal benefit		0.4	%		5.3	%		2.7	%
Deferred rate change		-5.3	%		12.7	%		0.0	%
Depletion in excess of basis		-0.8	%		-1.7	%		-0.6	%
Section 199 deduction		-2.9	%		-3.9	%		0.0	%
Other		-0.9	%		1.3	%		1.6	%
		25.5	%		48.7	%		37.9	%

The state effective tax rate varies based on production activity in the various state jurisdictions. During 2010 our production shifted to include more activity in states with lower tax rates than in 2009 due to the moratorium on drilling in the Gulf. The unfavorable effect of the deferred rate change in 2009 primarily relates to the impact on our deferred tax liabilities of the change in our federal rate from 34% to 35%. During 2010, our effective tax rate was favorably impacted by changes in estimates of our state apportionment factors.

The Charter companies’ 2010, 2009 and 2008 effective tax rates are 31.3%, 30.6% and 40.2%, respectively, and are comprised of the following:

	The Charters
	2010			2009			2008
Statutory federal income tax rate		34.0	%		34.0	%		34.0	%
State and local taxes, net of federal benefit		7.4	%		3.2	%		6.2	%
Depletion in excess of basis		-10.1	%		-6.6	%		0.0	%
		31.3	%		30.6	%		40.2	%

As of December 31, 2010, the Company had Federal net operating loss carryforwards of $6.2 million which will expire beginning in 2028 and state net operating loss carryforwards totaling $26.8 million which have expiration periods that vary according to state jurisdiction. Of the total $26.8 million state net operating loss carryforwards, $1.2 million will expire in 2014, and $3.6 million will expire 2015.

The Company and its subsidiaries file income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. As a general rule, the Company’s tax returns for calendar years after 2006 remain subject to examination by appropriate taxing authorities. The 2008 Federal tax return is currently undergoing an examination.

The Company has a large number of routine transactions for which it believes the tax law is clear and unambiguous. The Company’s management determined that the company does not have any uncertain tax positions that would require a disclosure under FASB income tax accounting guidance.

11. Employee Benefit Plans

Defined Contribution Plan

The Company maintains a 401(k) Retirement Savings Plan for employees. Under the 401(k) Plan, the Company matches employee contributions at rates approved by the Board. For the year ended December 31, 2010, the Company matched 100% of the first 8% of eligible pre-tax earnings (up to IRS limits) contributed by plan participants. The total employer contributions were approximately $482,000, $407,000 and $371,000 in 2010, 2009 and 2008, respectively.

F-20

12. Shareholders’ Equity

During March 2008, the Company issued 100 shares of common stock to one employee. During January 2009, the Company issued 50 shares of common stock to two employees. During September 2009, the Company issued 4,711 shares of common stock to two third-party entities that withdrew their interests from a limited liability company that the Company previously participated in. The two third-party entities exchanged their reserve values for ownership in the Company. During December 2009, the Company purchased 160 shares of its common stock for $431,000 from individual shareholders who desired to liquidate their investments in the Company. The Company did not repurchase any shares during the year ended December 31, 2010.

During 2010, dividends were paid at $25.00 per share to shareholders of record effective March 15, 2010, June 15, 2010, September 1, 2010 and December 15, 2010. During 2009, dividends were paid at $25.00 per share to shareholders of record effective March 1, 2009, June 15, 2009, September 15, 2009 and December 21, 2009. During 2008, dividends were paid at $25.00 per share to shareholders of record effective March 12, 2008, June 20, 2008, September 15, 2008 and December 5, 2008.

13. Variable Interest Entities

Certain related party entities known as the Charter entities have been consolidated in the Company’s financial statements in accordance with FASB accounting guidance related to Variable Interest Entities. The Charter entities were established as C-corporations to maintain a joint interest in certain wells owned and operated by the Company. Certain employees and executive officers of the Company were provided an opportunity to purchase a number of shares of the applicable Charter Company based upon rank and tenure with the Company for $1 per share. The purpose of the establishment of these entities was to provide the employees with an opportunity to share in the success of the Company through the joint interest in the properties owned by the Charter entities The first of these entities, Charter II, was established in 2006 followed by Charter III in 2008, Charter IV in 2009, and Charter V in 2010.

In performing an analysis of these entities for consolidation, the Company reviewed the guidance contained in FIN 46R, Consolidation of Variable Interest Entities, the accounting guidance in place at the time these entities were established, as well as the guidance contained in FAS 167, Amendments to FASB Interpretation No. 46R, now codified in ASC 810, Consolidation. The Company considered the following facts in this analysis:

• The employee owners contributed minimal funds ($1 per share) as an initial capital investment in each of the respective Charter entities and become the legal owner of the applicable shares of Charter stock. Accordingly, the Charter entities were not funded with sufficient equity to fund their operations without sufficient additional financial support from RAAM.

• The Company requires no initial investment from the Charter entities to acquire the joint interest in the properties. Payables incurred by Charter to RAAM for costs incurred in developing the wells are not required to be paid until revenues are generated from the properties at which time they are deducted from the joint interest billings due to the Charter entity. In addition, the employee owners have no obligation to invest additional funds should the wells not produce sufficient revenues to cover the costs. Accordingly, RAAM assumes all of the risk if the wells are dry or do not produce sufficient revenues to offset the costs incurred to develop the properties and fund the operation of the wells.

• The Board of Directors of the Charter entities are comprised of members of senior management of RAAM. While the employee owners have voting rights to elect the Directors of Charter they have no rights to vote on key operating or management decisions, including sale or disposition of entity. Since the shareholders of the Charter entities are employees of RAAM and all key decisions are made by the Board of Directors their voting rights are not considered substantive.

• The employees are not permitted to sell or assign their shares to any party other than RAAM. There is no present obligation for RAAM to purchase (i.e. call) the shares nor can the employees put the shares to RAAM for cash other than through termination, separation, or retirement as noted below.

F-21

• Upon termination, separation or retirement from the Company, Charter must purchase the shares from the employees at the estimated fair market value at the time of termination.

Given the conclusion regarding consolidation noted above, the issuance of the Charter shares to employees represents the issuance of shares of a consolidated subsidiary to employees qualifying for consideration as compensation costs in accordance with ASC Topic 718, Compensation-Stock Compensation (ASC 718).

The provision requiring the Charter entity to repurchase the shares at fair market value upon termination, separation or retirement represents an embedded employee put option. Under ASC 718, liability classification is required for embedded employee put options if the award “permits” the employee to avoid the risks and rewards described below. Liability classification is required even if it is unlikely that the employee will exercise his or her put right. An award is classified as a liability if either of the following conditions is met:

1. The award permits the employee to avoid bearing the risks and rewards normally associated with equity share ownership. Generally, if a repurchase feature provides for a repurchase at fair value of the shares on the date of purchase (as in the case of the Charter shares), an employee would bear the risks and rewards of ownership (although as discussed in Condition 2 below, those risks and rewards must be held for a minimum period to avoid liability classification).

2. The risks and rewards of share ownership are not retained for a reasonable period of time from the date the requisite service is rendered and the share is issued. The FASB has defined a “reasonable period of time” as a period of six months. The six-month “clock” begins on “the date the requisite service is rendered and the share is issued.” As such, the clock begins when (a) a share is vested or (b) an option is exercised and not subject to forfeiture through a repurchase feature that operates as a forfeiture provision.

Additionally, under ASC 718, if the employee has the ability to put shares back to the employer for fair value within six months of option exercise or share vesting, but chooses not to do so, the shares must be reclassified to equity at fair value on the date of reclassification. Public companies must classify the redemption amount outside of permanent equity, as required by ASR 268.

The Charter shares meet both criteria for liability accounting as noted above. However, since generally the employees held the shares for six months and chose not to leave the company and exercise the put right, the shares have been accounted for as a non-controlling interest requiring mark to market accounting classified to “mezzanine or “temporary equity” not as a liability but outside of permanent equity with mark to market accounting. Adjustments to the fair value of the shares are recorded as an increase or decrease to retained earnings in accordance with ASR 268.

The Charter shares meet both criteria for liability accounting as noted above. However, since generally the employees held the shares for six months and chose not to leave the company and exercise the put right, the shares are accounted for as a liability requiring mark to market accounting and compensation expense for the first six months after issuance and then be reclassified to “mezzanine or “temporary equity” not as a liability but outside of permanent equity with mark to market accounting. Since there are no vesting provisions, any required compensation expense would be recognized immediately. Once classified in temporary equity, any adjustments to the fair value of the shares are recorded as an increase or decrease to retained earnings in accordance with ASR 268.

In consideration of this guidance, the Company performed an analysis of the value of these entities at the date of share issuances and six months subsequent to that date. This analysis was performed in order to determine RAAM’s compensation cost, equal to the amount the fair value of the Charter shares in excess of the purchase price. Generally speaking, at inception, and throughout the first year the reserves of the Charter entities have minimal fair value as the properties are in the early stages of being established and there is much uncertainty regarding the drilling prospects (i.e. dry well vs. active producing well). As a result, the estimated value of the reserves do not surpass the amount of the payable to RAAM until later in the drilling stage of the various wells when more certainty exists regarding the future reserve prospects. Accordingly, no compensation expense has been recognized in the consolidated financial statements.

F-22

14. Related-Party Transactions

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. Amounts due from such related parties of approximately $734,000 and $7.9 million at December 31, 2010 and 2009, respectively, are included in Accounts receivable in the Company’s consolidated balance sheets and represent joint interest owner receivables. Amounts due to such related parties of $4.5 million and $6.0 million at December 31, 2010 and 2009, respectively, are included in Revenues payable in the Company’s consolidated balance sheets and represent revenue owner payables. The Company paid $84,000 in consulting fees to a related party in each of the years ended December 31, 2010, 2009 and 2008, and this is recorded in General and administrative expenses on the consolidated statements of operations.

A related party entity owned 100% by a majority shareholder is a working interest and revenue partner in certain of the Company’s properties. The related party entity executed a Joint Operating Agreement with the Company effective December 1, 2004, to participate in properties to be developed by the Company. The entity receives joint interest bills from the Company for its respective share of lease and drilling costs. The costs under these agreements owed to the Company at December 31, 2010 and 2009 totaled approximately $20,000 and $29,000, respectively, are included in accounts receivable in the Company’s consolidated balance sheets, and represent joint interest owner receivables. Revenues owed to the entity at December 31, 2010 and 2009 totaled $2.0 million and $1.9 million respectively, are included in revenues payable in the Company’s consolidated balance sheets, and represent revenue owner payables.

Beginning in May 2002, the Lexington office space was leased from a related party entity owned 100% by a majority shareholder of the Company; total rent payments were approximately $213,000, $189,000 and $185,000 during 2010, 2009 and 2008, respectively. See Note 15, Commitments and Contingencies for further information.

15. Commitments and Contingencies

The Company leases office space for its Lexington, Kentucky, New Orleans, Louisiana and Denver, Colorado offices under operating leases expiring in various years through 2015. The Lexington, Kentucky office space is leased from a related party (see Note 14). At December 31, 2010, future minimum rental payments required under these leases are as follows:

Year ending December 31:	Minimum Lease Payments
	(In thousands)
2011	$	283
2012		286
2013		294
2014		240
2015		215
Total	$	1,318

Rent expense under operating leases was approximately $530,000, $667,000 and $579,000 for 2010, 2009 and 2008, respectively.

Historically, the majority of the Company’s proved oil and gas properties have been located in the Gulf of Mexico, resulting in a concentration of its operations in one geographic area. Management has concentrated its efforts since 1996 in developing prospects in other geographic areas in order to mitigate this risk. During 2010 and 2009, the Company drilled successful wells onshore and has developed additional onshore drilling prospects that are anticipated to be drilled during 2011.

The Company has been named as a defendant in certain lawsuits arising in the ordinary course of business. While the outcome of the lawsuits cannot be predicted with certainty, management does not expect that these matters will have a material adverse effect on the financial position, cash flows or results of operations of the Company.

F-23

16. Condensed Consolidating Financial Information

The following condensed consolidating financial information is presented in accordance with SEC regulation S-X requirements relating to multiple subsidiary guarantors of securities issued by the parent company of those subsidiaries. During 2010, RAAM Global issued the 2015 Senior Secured Notes, described in Note 9, Debt. Each of RAAM Global’s wholly owned subsidiaries are guarantors of these notes. The guarantees are full and unconditional and joint and several.

The following tables present condensed consolidating balance sheets as of December 31, 2010 and 2009, and condensed consolidated statements of operations and cash flows for the years ended December 31, 2010, 2009 and 2008, and should be read in conjunction with the consolidated financial statements herein.

F-24

Condensed Consolidating Balance Sheets

At December 31, 2010

	RAAM Global Energy Company			Subsidiary Guarantors		Non- guarantor VIEs			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	45,683		$	35,320	$	29		$	—		$	81,032
Receivables, net		3,491			52,019		528			(8,968	)		47,070
Commodity derivatives – current portion		—			9,377		—			—			9,377
Prepaids and other current assets		1,724			6,260		—			—			7,984
Total current assets		50,898			102,976		557			(8,968	)		145,463
Net oil and gas properties		55,808			370,000		11,142			—			436,950
Total other assets		34,444			270,496		—			(290,067	)		14,873
Total assets	$	141,150		$	743,472	$	11,699		$	(299,035	)	$	597,286
Liabilities and shareholders’ equity
Current liabilities:
Payables and accrued liabilities	$	6,423		$	37,490	$	8,448		$	(8,968	)	$	43,393
Commodity derivatives – current portion		—			1,973		—			—			1,973
Asset retirement obligations – current portion		—			2,406		—			—			2,406
Long-term debt – current portion		110			1,002		—			—			1,112
Deferred income taxes – current portion		—			1,810		—			—			1,810
Total current liabilities		6,533			44,681		8,448			(8,968	)		50,694
Other liabilities:
Commodity derivatives		—			861		—			—			861
Asset retirement obligations		872			19,923		151			—			20,946
Long-term debt		2,860			—		—			—			2,860
Senior secured notes		148,681			—		—			—			148,681
Deferred income taxes		5,198			84,827		845			—			90,870
Total other liabilities		157,611			105,611		996			—			264,218
Total liabilities		164,144			150,292		9,444			(8,968	)		314,912
Noncontrolling interest		—			—		2,467			—			2,467
Total shareholders’ equity		(22,994	)		593,180		(212	)		(290,067	)		279,907
Total liabilities and shareholders’ equity	$	141,150		$	743,472	$	11,699		$	(299,035	)	$	597,286

F-25

Condensed Consolidating Balance Sheets

At December 31, 2009

	RAAM Global Energy Company		Subsidiary Guarantors		Non- guarantor VIEs			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	3,190	$	25,681	$	17		$	—		$	28,888
Receivables, net		3,390		44,352		843			(11,564	)		37,021
Commodity derivatives – current portion		—		26,996		—						26,996
Prepaids and other current assets		353		10,425		—						10,778
Total current assets		6,933		107,454		860			(11,564	)		103,683
Net oil and gas properties		66,633		358,263		8,017			—			432,913
Total other assets		34,763		273,347		—			(288,858	)		19,252
Total assets	$	108,329	$	739,064	$	8,877		$	(300,422	)	$	555,848
Liabilities and shareholders’ equity
Current liabilities:
Payables and accrued liabilities	$	3,019	$	45,364	$	7,882		$	(11,564	)	$	44,701
Advances from joint interest partners		—		1,053		—						1,053
Asset retirement obligations – current portion		—		2,543		—						2,543
Long-term debt – current portion		102		1,040		—						1,142
Deferred income taxes – current portion		—		8,803		—						8,803
Total current liabilities		3,121		58,803		7,882			(11,564	)		58,242
Other liabilities:
Asset retirement obligations		844		16,561		57						17,462
Long-term debt		2,980		110,000		—						112,980
Deferred income taxes		8,466		94,346		302						103,114
Total other liabilities		12,290		220,907		359			—			233,556
Total liabilities		15,411		279,710		8,241			(11,564	)		291,798
Noncontrolling interest		—		—		5,551						5,551
Total shareholders’ equity		92,918		459,354		(4,915	)		(288,858	)		258,499
Total liabilities and shareholders’ equity	$	108,329	$	739,064	$	8,877		$	(300,422	)	$	555,848

F-26

Condensed Consolidating Statements of Operations

For the year ended December 31, 2010

	RAAM Global Energy Company			Subsidiary Guarantors			Non guarantor VIEs		Eliminations		Consolidated
Revenues
Gas sales	$	1,132		$	113,487		$	2,557	$	—	$	117,176
Oil sales		936			77,439			2,257		—		80,632
Total revenues		2,068			190,926			4,814		—		197,808
Costs and expenses:
Production and delivery costs		388			30,837			344		—		31,569
Workover costs		22			10,442			6		—		10,470
Depreciation, depletion and amortization		11,251			58,502			2,201		—		71,954
General and administrative expenses		4,872			11,737			24		—		16,633
Bad debt expense		—			98			—		—		98
Derivative (income) expense		—			(555	)		—		—		(555	)
Total operating expense		16,533			111,061			2,575		—		130,169
Income from operations		(14,465	)		79,865			2,239		—		67,639
Other income (expenses):
Interest expense, net		(5,786	)		(2,995	)		—		—		(8,781	)
Loss on disposal of inventory and properties		—			(1,463	)		—		—		(1,463	)
Income (loss) from equity investment		(5,156	)		—			—		—		(5,156	)
Other, net		180			254			—		—		434
Total other income (expenses):		(10,762	)		(4,204	)		—		—		(14,966	)
Income before taxes		(25,227	)		75,661			2,239		—		52,673
Income tax provision (benefit)		16,406			(3,524	)		558		—		13,440
Net income including noncontrolling interest	$	(41,633	)	$	79,184		$	1,682	$	—	$	39,233
Net income attributable to noncontrolling interest (net of tax)		—			—			1,682		—		1,682
Net income attributable to RAAM Global	$	(41,633	)	$	79,184		$	—	$	—	$	37,551

Totals may not foot due to rounding.

F-27

Condensed Consolidating Statements of Operations

For the year ended December 31, 2009

	RAAM Global Energy Company			Subsidiary Guarantors			Non guarantor VIEs		Eliminations		Consolidated
Revenues
Gas sales	$	1,822		$	151,873		$	824	$	—	$	154,519
Oil sales		867			82,216			1,179		—		84,262
Insurance proceeds – business interruption		—			20,207			—		—		20,207
Total revenues		2,689			254,296			2,003		—		258,988
Costs and expenses:
Production and delivery costs		506			25,203			122		—		25,831
Workover costs		18			8,420			1		—		8,439
Depreciation, depletion and amortization		19,575			130,022			826		—		150,423
General and administrative expenses		7,558			10,524			37		—		18,119
Bad debt expense		—			2,454			—		—		2,454
Derivative (income) expense		—			136			—		—		136
Total operating expense		27,657			176,759			986		—		205,402
Income from operations		(24,968	)		77,537			1,017		—		53,586
Other income (expenses):
Interest expense, net		(209	)		(3,777	)		—		—		(3,986	)
Loss on disposal of inventory and properties		—			(1,257	)		—		—		(1,257	)
Income (loss) from equity investment		492			—			—		—		492
Other, net		681			180			—		—		861
Total other income (expenses):		964			(4,854	)		—		—		(3,890	)
Income before taxes		(24,004	)		72,683			1,017		—		49,696
Income tax provision (benefit)		33,715			(10,022	)		302		—		23,995
Net income including noncontrolling interest	$	(57,719	)	$	82,705		$	715	$	—	$	25,701
Net income attributable to noncontrolling interest (net of tax)		—			—			715		—		715
Net income attributable to RAAM Global	$	(57,719	)	$	82,705		$	—	$	—	$	24,986

Totals may not foot due to rounding.

F-28

Condensed Consolidating Statements of Operations

For the year ended December 31, 2008

	RAAM Global Energy Company			Subsidiary Guarantors			Non guarantor VIEs		Eliminations		Consolidated
Revenues
Gas sales	$	3,128		$	121,771		$	2,848	$	—	$	127,747
Oil sales		1,625			74,517			2,848		—		78,990
Insurance proceeds – business interruption		—			2,660			—		—		2,660
Total revenues		4,753			198,948			5,696		—		209,397
Costs and expenses:
Production and delivery costs		432			18,467			289		—		19,188
Workover costs		292			11,092			60		—		11,444
Depreciation, depletion and amortization		4,162			82,544			3,739		—		90,445
General and administrative expenses		3,689			6,709			20		—		10,418
Derivative (income) expense		—			(1,007	)		—		—		(1,007	)
Total operating expense		8,575			117,805			4,108		—		130,488
Income from operations		(3,822	)		81,143			1,588		—		78,909
Other income (expenses):
Interest expense, net		(180	)		(1,546	)		—		—		(1,726	)
Gain on sale of oil and gas properties		8,733			39,475			—		—		48,208
Income (loss) from equity investment		(7,561	)		—			—		—		(7,561	)
Other, net		343			126			—		—		469
Total other income (expenses):		1,335			38,055			—		—		39,390
Income before taxes		(2,487	)		119,198			1,588		—		118,299
Income tax provision		13,040			31,397			148		—		44,585
Net income including noncontrolling interest	$	(15,527	)	$	87,799		$	1,442	$	—	$	73,714
Net income attributable to noncontrolling interest (net of tax)		—			—			1,442		—		1,442
Net income attributable to RAAM Global	$	(15,527	)	$	87,799		$	—	$	—	$	72,272

Totals may not foot due to rounding.

F-29

Condensed Consolidating Statements of Cash Flows

For the year ended December 31, 2010

	RAAM Global Energy Company			Subsidiary Guarantors			Non guarantor VIEs			Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(23,557	)	$	132,371		$	5,395		$	—	$	114,209
Investing activities
Change in investments		—			150			—			—		150
Change in investments between affiliates		(69,691	)		69,691			—			—		—
Change in advances from joint interest partners		—			(1,052	)		—			—		(1,052	)
Additions to oil and gas properties and equipment		(76	)		(81,477	)		(5,383	)		—		(86,936	)
Net cash used in investing activities		(69,767	)		(12,688	)		(5,383	)		—		(87,838	)
Financing activities
Proceeds from long-term borrowings		—			8,874			—			—		8,874
Payments on long-term borrowings		(112	)		(118,912	)		—			—		(119,024	)
Proceeds from Issuance of 12.5% Senior Notes due 2015		148,629			—			—			—		148,629
Deferred bond costs		(6,701	)		—			—			—		(6,701	)
Payment of dividends		(6,000	)		—			—			—		(6,000	)
Other		—			(5	)		—			—		(5	)
Net cash provided by (used in) financing activities		135,816			(110,043	)		—			—		25,773
Increase (decrease) in cash and cash equivalents		42,492			9,640			12			—		52,144
Cash and cash equivalents, beginning of period		3,190			25,681			17			—		28,888
Cash and cash equivalents, end of period	$	45,682		$	35,321		$	29		$	—	$	81,032

Totals may not foot due to rounding.

F-30

Condensed Consolidating Statements of Cash Flows

For the year ended December 31, 2009

	RAAM Global Energy Company			Subsidiary Guarantors				Non guarantor VIEs			Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(33,311	)	$	216,082			$	2,734		$	—	$	185,505
Investing activities
Change in restricted cash		—			2,000				—			—		2,000
Change in investments		—			(150	)			—			—		(150	)
Change in investments between affiliates		53,351			(53,351	)			—			—		—
Change in advances from joint interest partners		—			658				—			—		658
Additions to oil and gas properties and equipment		(5,958	)		(129,088	)			(2,748	)		—		(137,794	)
Purchase of noncontrolling interest		(7,048	)		—				—			—		(7,048	)
Net cash provided by (used in) investing activities		40,345			(179,931	)			(2,748	)		—		(142,334	)
Financing activities
Proceeds from long-term borrowings		—			9,206				—			—		9,206
Payments on long-term borrowings		(104	)		(23,939	)			—			—		(24,043	)
Deferred loan costs		—			(1,409	)			—			—		(1,409	)
Treasury stock		(431	)		—				—			—		(431	)
Payment of dividends		(5,663	)		—				—			—		(5,663	)
Other		—			5				—			—		5
							��
Net cash used in financing activities		(6,198	)		(16,137	)			—			—		(22,335	)
Increase (decrease) in cash and cash equivalents		836			20,014				(14	)		—		20,836
Cash and cash equivalents, beginning of period		2,354			5,666				32			—		8,052
Cash and cash equivalents, end of period	$	3,190		$	25,680			$	18		$	—	$	28,888

Totals may not foot due to rounding.

F-31

Condensed Consolidating Statements of Cash Flows

For the year ended December 31, 2008

	RAAM Global Energy Company			Subsidiary Guarantors			Non guarantor VIEs			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(15,545	)	$	126,561		$	11,385		$	—		$	122,401
Investing activities
Change in restricted cash		—			18			—			—			18
Change in investments		(52,439	)		175			—			—			(52,264	)
Change in investments between affiliates		85,330			(85,330	)		—			—			—
Change in advances from joint interest partners		—			(288	)		—			—			(288	)
Additions to oil and gas properties and equipment		(11,940	)		(170,056	)		(11,354	)		—			(193,350	)
Proceeds from net sales of oil and gas properties		—			54,362			—			—			54,362
Net cash provided by (used in) investing activities		20,951			(201,119	)		(11,354	)		—			(191,522	)
Financing activities
Proceeds from long-term borrowings		—			61,855			—			—			61,855
Payments on long-term borrowings		(97	)		(11,082	)		—			—			(11,179	)
Proceeds from issuance of common stock		163			—			—			—			163
Payment of dividends		(5,537	)		—			—			—			(5,537	)
Net cash provided by (used in) financing activities		(5,471	)		50,773			—			—			45,302
Increase (decrease) in cash and cash equivalents		(65	)		(23,785	)		31			—			(23,819	)
Cash and cash equivalents, beginning of period		2,419			29,452			—			—			31,871
Cash and cash equivalents, end of period	$	2,354		$	5,667		$	31		$	—	��	$	8,052

Totals may not foot due to rounding.

F-32

Supplemental Oil and Gas Data

(Unaudited)

The supplemental information that follows shows estimates of the discounted future net cash flows from proved oil and gas reserves, changes in such estimates and various cost data. This information has been prepared in accordance with requirements prescribed by Statement of Financial Accounting Standards No. 69 (SFAS 69). SFAS 69 was codified into FASB ASC Topic 932 Extractive Activities — Oil and Gas. Inherent in the underlying calculations of such data are many variables and assumptions, the more significant of which are described below:

• Estimates of all discounted future net cash flows from proved oil and gas reserves are primarily based on reports of independent petroleum engineers. Probable and possible reserves, a portion of which experience has indicated generally become proved once further exploration work has been conducted, are not considered.

• Future net cash flows have been discounted at an annual rate of 10% and have been reduced by applicable estimates of future production, development and net abandonment costs, all of which are based on current costs.

• The reserve estimates have been valued using the average of the first-day-of-the month price for the 12-month period. Therefore, the value of the reserves is not an estimate of fair value. The prices received for oil and gas are subject to great variation and may increase or decrease according to market conditions.

In view of the uncertainties inherent in developing this supplemental data, it is emphasized that the information represents estimates of future net cash flows and caution should accompany its use and interpretation. In addition, this information should not be viewed as representative of the current value of the Company.

F-33

Costs Incurred (Unaudited)

The following represents the total costs incurred during 2010, 2009 and 2008 with respect to oil and gas producing activities:

	2010		2009		2008
	(in thousands)
Costs incurred:
Unproved property	$	35,332	$	45,364	$	53,489
Proved property		0		61,420		63,176
Exploration costs		27,030		45,166		49,647
Development costs		23,738		32,134		29,524
Total costs incurred	$	86,100	$	184,084	$	195,836

F-34

Proved Oil and Gas Reserves (Unaudited)

The following sets forth estimates in proved and proved developed reserves of oil and gas and changes in estimates of proved reserves for 2010, 2009 and 2008. Oil, including condensate, is stated in barrels, and gas is stated in thousands of cubic feet at 14.73 P.S.I. All oil and gas reserves are located within the United States:

	2010
	Oil			Gas
Beginning of year		11,750			50,724
Revisions of previous estimates		281			3,330
Production		(1,066	)		(16,172	)
Extensions and discoveries		473			6,159
Proved reserves end of year		11,438			44,041
Proved developed reserves at beginning of year		4,292			40,563
Proved developed reserves at end of year		3,851			35,917

	2009
	Oil			Gas
Beginning of year		9,391			53,275
Revisions of previous estimates		1,580			5,898
Production		(1,058	)		(18,291	)
Extensions and discoveries		835			6,553
Purchase of reserves in-place		1,002			3,289
Proved reserves end of year		11,750			50,724
Proved developed reserves at beginning of year		4,399			45,598
Proved developed reserves at end of year		4,292			40,563

	2008
	Oil			Gas
Beginning of year		3,703			49,412
Revisions of previous estimates		(261	)		484
Production		(826	)		(14,801	)
Extensions and discoveries		6,546			10,973
Purchase of reserves in-place		229			7,206
Proved reserves end of year		9,391			53,274
Proved developed reserves at beginning of year		2,659			38,380
Proved developed reserves at end of year		4,399			45,598

F-35

Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves (Unaudited)

(In Thousands)

The Standardized measure of discounted future net cash flows from proved oil and gas reserves at 2010, 2009 and 2008 is as follows:

	2010			2009			2008
	(in thousands)
Future cash flows	$	1,035,152		$	857,811		$	741,188
Future production costs		(246,090	)		(245,377	)		(172,555	)
Future development and abandonment costs		(130,802	)		(130,179	)		(91,668	)
Future net cash flows before income taxes and discount for timing		658,260			482,255			476,965
Future income taxes		(196,810	)		(145,713	)		(136,462	)
Discount for estimated timing of net cash flows		(190,401	)		(132,625	)		(111,746	)
Standardized measure of discounted future net cash flows	$	271,049		$	203,917		$	228,757

F-36

Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

(In Millions)

The primary sources of change in the standardized measure of discounted future net cash flows are as follows:

	2010			2009			2008
	(in millions)
Standardized measure of discounted future net cash flows from proved oil and gas reserves at beginning of year	$	204		$	229		$	225
Extensions and discoveries and improved recovery, net of future production and development costs		25			20			203
Purchase of reserves in-place		0			22			28
Development costs incurred during the period		(23	)		32			30
Revenues, net of production costs		(124	)		(109	)		(204	)
Revisions of estimates:
Net change in prices		163			(23	)		(103	)
Changes in estimated future development costs		(9	)		(54	)		(34	)
Revision of quantity estimates		23			56			(3	)
Net change in income taxes		(25	)		(17	)		42
Accretion of discount		31			33			36
Changes in production rates (timing) and other		6			15			9
Standardized measure of discounted future net cash flows from proved oil and gas reserves at end of year	$	271		$	204		$	229

F-37

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

(unaudited)

	June 30, 2011			December 31, 2010
Assets
Current assets:
Cash and cash equivalents	$	71,221		$	81,032
Accounts receivable, net of $1,005 and $235 provision for bad debts in 2011 and 2010, respectively		3,204			22,412
Revenues receivable		28,741			21,703
Income taxes receivable		2,987			2,955
Commodity derivatives – current portion		2,669			9,377
Prepaid assets		10,150			4,200
Other current assets		3,900			3,784
Total current assets		122,872			145,463
Oil and gas properties (full-cost method):
Properties being amortized		1,065,479			1,009,071
Properties not subject to amortization		95,640			81,656
Less accumulated depreciation, depletion, and amortization		(684,113	)		(653,777	)
Net oil and gas properties		477,006			436,950
Other assets:
Other capitalized assets, net		7,249			7,246
Commodity derivatives		611			263
Equity investments		2,044			2,044
Other		18,449			5,320
Total other assets		28,353			14,873
Total assets	$	628,231		$	597,286

See accompanying notes to the condensed consolidated financial statements.

F-38

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

(unaudited)

	June 30, 2011			December 31, 2010
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	14,074		$	19,587
Revenues payable		26,320			17,834
Interest payable – senior secured notes		4,688			5,048
Current taxes payable		614			924
Advances from joint interest partners		909			—
Commodity derivatives – current portion		2,479			1,973
Asset retirement obligations – current portion		2,406			2,406
Long-term debt – current portion		6,390			1,112
Deferred income taxes – current portion		797			1,810
Total current liabilities		58,677			50,694
Other liabilities:
Commodity derivatives		610			861
Asset retirement obligations		22,342			20,946
Long-term debt		2,787			2,860
Senior secured notes		148,781			148,681
Deferred income taxes		99,102			90,870
Total other liabilities		273,622			264,218
Total liabilities		332,299			314,912
Commitments and contingencies (see Note 10)
Noncontrolling interest		20,956			2,467
Shareholders’ equity:
Common stock, no par value, 380,000 shares authorized, 60,000 issued and outstanding in 2011 and 2010, respectively		56,096			56,096
Treasury stock, 5,166 shares in 2011 and 2010		(5,736	)		(5,736	)
Accumulated other comprehensive income, net of taxes		1,593			5,977
Retained earnings		223,023			223,570
Total shareholders’ equity		274,976			279,907
Total liabilities and shareholders’ equity	$	628,231		$	597,286

See accompanying notes to the condensed consolidated financial statements.

F-39

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues:
Gas sales	$	25,110		$	33,828		$	49,424		$	68,587
Oil sales		25,747			21,052			46,906			42,998
Total revenues		50,857			54,880			96,330			111,585
Costs and expenses:
Production and delivery costs		8,890			6,923			16,352			14,811
Workover costs		786			777			1,218			2,067
Depreciation, depletion and amortization		13,927			13,842			31,066			39,542
General and administrative expenses		3,966			3,253			8,345			6,391
Bad debt expense		770			—			770			—
Derivative (income) expense		(292	)		515			(539	)		309
Total operating expense		28,047			25,310			57,212			63,120
Income from operations		22,810			29,570			39,118			48,465
Other income (expenses):
Interest expense, net		(2,949	)		(900	)		(6,348	)		(1,638	)
Other, net		(13	)		470			181			536
Total other income (expenses):		(2,962	)		(430	)		(6,167	)		(1,102	)
Income before taxes		19,848			29,140			32,951			47,363
Income tax provision		9,354			10,541			12,010			17,214
Net income including noncontrolling interest	$	10,494		$	18,599		$	20,941		$	30,149
Net income attributable to noncontrolling interest (net of tax)		1,022			573			1,476			946
Net income attributable to RAAM Global	$	9,472		$	18,026		$	19,465		$	29,203

See accompanying notes to the condensed consolidated financial statements.

F-40

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)

	Six Months Ended June 30,
	2011			2010
Operating activities
Net income including noncontrolling interest	$	20,941		$	30,149
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		31,936			39,894
Deferred income taxes		7,219			4,739
Loss on disposal of inventory and properties		20			—
Changes in components of working capital:
Accounts and revenues receivable		12,171			6,493
Insurance receivable		—			6,050
Income tax receivables		—			(3,880	)
Other current assets		(6,085	)		(6,829	)
Change in derivatives, net		2,230			2,603
Accounts payable and accrued liabilities		(4,520	)		(20,613	)
Current taxes payable		(343	)		(314	)
Interest payable on Senior Notes		(361	)		—
Revenues payable		8,486			(1,187	)
Net cash provided by operating activities		71,694			57,105
Investing activities
Change in investments		—			149
Change in advances from joint interest partners		909			(991	)
Payment of prepaid drilling expenses		(14,000	)		—
Additions to oil and gas properties and equipment		(72,845	)		(28,972	)
Proceeds from net sales of oil and gas properties		2,125			—
Net cash used in investing activities		(83,811	)		(29,814	)
Financing activities
Proceeds from long-term borrowings		8,037			8,874
Payments on long-term borrowings		(2,832	)		(12,055	)
Deferred loan costs		—			304
Payment of dividends		(3,000	)		(3,000	)
Other		101			—
Net cash provided by (used in) financing activities		2,306			(5,877	)
(Decrease) increase in cash and cash equivalents		(9,811	)		21,414
Cash and cash equivalents, beginning of period		81,032			28,888
Cash and cash equivalents, end of period	$	71,221		$	50,302

See accompanying notes to the condensed consolidated financial statements.

F-41

RAAM GLOBAL ENERGY COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Business

RAAM Global Energy Company (“RAAM Global” or the “Company”) is engaged primarily in the exploration and development of oil and gas properties and in the resulting production and sale of natural gas, condensate and crude oil. The Company’s production facilities are located in the Gulf of Mexico, offshore Louisiana and onshore Mississippi, Louisiana, Texas, and Oklahoma.

2. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of RAAM Global include the accounts of RAAM Global, its wholly-owned subsidiaries, its majority-owned joint venture and variable interest entities where RAAM Global is the primary beneficiary. Significant intercompany accounts and transactions have been eliminated in consolidation. The accompanying interim Condensed Consolidated Financial Statements are unaudited; however, in the opinion of the Company’s management, all adjustments necessary for a fair statement of the interim financial results have been included. These adjustments were of a normal recurring nature. The results for the interim periods are not necessarily indicative of results to be expected for any other interim period or for the entire year.

The Condensed Consolidated Balance Sheet as of December 31, 2010, was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”). Certain notes and other information have been condensed or omitted from the interim financial statements presented in this quarterly report. Therefore, these financial statements and notes should be read in conjunction with the Company’s audited financial statements included in our registration statement on Form S-4 (File No. 333-172897) filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates

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 may differ from those estimates. The Company’s most significant financial estimates are based on remaining proved oil and gas reserves.

Oil and Gas Properties

The Company uses the full-cost method of accounting for exploration and development costs. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including interest related to significant properties being evaluated and directly related overhead costs, are capitalized. Capitalized overhead costs amounted to $1.3 million and $0.9 million for the three months ended June 30, 2011 and 2010, respectively, and these costs amounted to $2.5 million and $1.6 million for the six months ended June 30, 2011 and 2010, respectively.

All capitalized costs of oil and gas properties are amortized through depreciation, depletion and amortization (“DD&A”) using the future gross revenue method whereby the annual provision is computed by dividing revenue earned during the period by future gross revenues at the beginning of the period, and applying the resulting rate to the cost of oil and gas properties, including estimated future development and abandonment costs.

Investments in unproved properties and major development projects are not amortized until proved reserves are attributed to the projects or until impairment occurs. If the results of an assessment indicate that the properties are impaired, that portion of such costs is added to the capitalized costs to be amortized.

F-42

Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties were $95.6 million and $81.7 million at June 30, 2011 and December 31, 2010, respectively. The Company believes that the unevaluated properties at June 30, 2011 will be substantially evaluated during 2011, 2012 and 2013, and the costs will begin to be amortized at that time. The Company capitalized interest of $2.2 million and $0.3 million during the three months ended June 30, 2011 and 2010, respectively, related to significant properties not subject to amortization. The Company capitalized interest of $4.0 million and $0.4 million during the six months ended June 30, 2011 and 2010, respectively, related to significant properties not subject to amortization.

Capitalized oil and gas property costs are subject to a “ceiling test,” which limits such costs to the aggregate of the estimated present value, discounted at 10%, of future net cash flows from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects. Details specific to the Company’s ceiling tests for the periods presented in the accompanying condensed consolidated financial statements are discussed later in this footnote section.

Sales of proved and unproved properties are accounted for as adjustments of 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, in which case the gain or loss is recognized in current income.

During the second quarter of 2011, the Company sold approximately 16,000 acres onshore Mississippi to an unrelated third party oil and gas company. The final sales price amounted to $2.2 million and was recorded in cash and as an accumulated reduction to our net oil and gas properties on the accompanying condensed consolidated balance sheet at June 30, 2011. Under the full cost accounting method, the transaction is recorded as a reduction to net oil and gas properties with no income statement impact because the original cost of the acreage is not a significant percentage of the Company’s consolidated capitalized costs. The cash payment was collected during May 2011.

During the second quarter of 2011, the Company entered into an agreement with an unrelated third party to acquire a 40% working interest in drilling activities in Oklahoma. The Company prepaid $14 million in drilling expenses for this program. This prepayment is recorded in Other, in the Other assets section of the condensed consolidated balance sheet. The third party we have entered into the agreement with will send the Company joint interest billing information on a periodic basis reflecting the amount of our prepayment that has been utilized for drilling activities. Based on this information, the prepayment will be reduced by the amount of utilization and be transferred fromOther intoOil and gas properties.

In January 2010, the Company adopted the Financial Accounting Standards Board (“FASB”) guidance on oil and gas reserve estimation and disclosures. This guidance amends previous FASB guidance on oil and gas extractive activities to align the accounting requirements with the Securities and Exchange Commission’s final rule,Modernization of the Oil and Gas Reporting Requirements issued on December 31, 2008. In summary, the revisions in this guidance modernize the disclosure rules to better align with current industry practices and expand the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:

• An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.

• The use of an average of the first-day-of-the-month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.

• Amended definitions of key terms such as “reliable technology” and “reasonable certainty” which are used in estimating proved oil and gas reserve quantities.

• A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.

F-43

• Clarification that an entity’s equity investments must be considered in determining whether it has significant oil and gas activities and a requirement to disclose equity method investments in the same level of detail as is required for consolidated investments.

The new rules are considered a change in accounting principle that is inseparable from a change in accounting estimate, which does not require retroactive revision. This change in accounting principle has had a material effect on the consistency of the Company’s oil and gas reserve estimates, supplemental disclosures, the calculation of DD&A and the full-cost ceiling test. At June 30, 2011, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $88.44 per barrel of oil and $4.19 per MMBtu of natural gas. At December 31, 2010, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $75.96 per barrel of oil and $4.38 per MMBtu of natural gas.

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. See Note 9 for further information.

Hedging Activities

The Company’s revenues are primarily the result of sales of its oil and natural gas production. Market prices of oil and natural gas may fluctuate and affect operating results. The Company engages in hedging activities that primarily include the use of floors, costless collars and futures transactions in order to minimize the downside risk from adverse price movements but allow for the realization of upside profits, if available. Costs and any benefits derived from the effective hedge portions of these activities are reflected in revenues from oil and gas production.

The Company follows the provisions of FASB guidance related to accounting for derivative instruments and hedging activities. This guidance requires all derivatives to be reported as assets or liabilities at their fair values, and the balance-sheet captionCommodity Derivatives is being used in the accompanying condensed consolidated balance sheets for this purpose. This guidance also imposes additional documentation requirements in order for derivatives to be accounted for as hedges of future risks. The Company designated all new commodity derivative instruments entered into in 2011 and 2010 as hedges for accounting purposes, so the related unrealized changes in their fair values are reported net of tax in the accompanying condensed consolidated balance sheet as a component of other comprehensive income. Any hedge ineffectiveness (which represents the amount by which the change in fair value of the derivative exceeds the change in cash flows of the forecasted transaction) is recorded in current-period earnings in the accompanying condensed consolidated statement of operations inDerivative income. Hedge ineffectiveness of actual monthly settlements is recorded as hedging (losses) gains inGas sales andOil sales in the accompanying condensed consolidated statement of operations. During the three months ended June 30, 2011 and 2010, the amounts of other comprehensive income related to hedge transactions that settled and were recorded in the accompanying condensed consolidated statements of operations were $1.8 million and $7.4 million, respectively, net of tax effects. During the six months ended June 30, 2011 and 2010, the amounts of other comprehensive income (loss) related to hedge transactions that settled and were recorded in the accompanying condensed consolidated statements of operations were a loss of $4.7 million and income of $4.1 million, respectively, net of tax effects. The Company anticipates the amount of other comprehensive loss related to hedge transactions that will settle during the next twelve months and be recorded in the 2011 and 2012 consolidated statements of operations will be $124,000, net of tax effects.

Accounting for Asset Retirement Obligations

In accordance with the provisions of FASB guidance related to accounting for asset retirement obligations and FASB guidance on accounting for conditional asset retirement obligations, costs associated with the retirement of fixed assets (e.g., oil and gas production facilities, etc.) that the Company is legally obligated to incur are

F-44

accrued. The fair value of the obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the fixed asset and are depreciated over the life of the applicable asset. The asset retirement cost recorded inOil and gas properties being amortized at June 30, 2011 and December 31, 2010 were $19.7 million and $18.8 million, respectively. Accretion of the discounted asset retirement obligations is recognized as an increase in the carrying amount of the liability and as an expense within depreciation, depletion and amortization on the accompanying condensed consolidated statement of operations.

The change in the Company’s asset retirement obligations (ARO) is set forth below:

In thousands
Balance of ARO as of January 1, 2011	$	23,352
Accretion expense		404
Additions		968
Settlement of ARO		—
Changes in ARO estimate		24
Balance of ARO as of June 30, 2011	$	24,748

Operating Segments

The Company operates in one business segment – the exploration, development and sale of oil and gas.

Subsequent events

Management has reviewed subsequent events through the filing date. See Note 13 for additional information regarding a subsequent event.

New Accounting Pronouncements

ASU Number 2011-5 was issued in June 2011, amending Topic 220 – Comprehensive Income. The ASU modifies alternative presentation standards, eliminating the option for disclosure of the elements of other comprehensive income within the statement of stockholder’s equity. Adoption of this ASU by the Company will change our existing presentation, but will not impact the components of other comprehensive income. The ASU is effective for fiscal periods beginning after December 15, 2011.

3. Fair Value Measurements

FASB guidance establishes a three-level hierarchy for fair value measurements. The hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date.

• Level 1 – Valuation is based upon unadjusted quoted prices for identical assets or liabilities in active markets.

• Level 2 – Valuation is based upon quoted prices for similar assets and liabilities in active markets, or other inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

• Level 3 – Valuation is based upon other unobservable inputs that are significant to the fair value measurements.

The classification of fair value measurements within the hierarchy is based upon the lowest level of input that is significant to the measurement. At June 30, 2011 and December 31, 2010, the Company’s commodity derivative contracts were recorded at fair value. The fair values of these instruments were measured using valuations based

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upon quoted prices for similar assets and liabilities in active markets (Level 2) and are valued by reference to similar financial instruments, adjusted for credit risk and restrictions and other terms specific to the contracts.

Description	Fair Value Measurements Using Significant Other Observable Inputs  (Level 2)
In thousands	June 30, 2011			December 31, 2010
Assets:
Fair value of commodity derivatives – current assets	$	2,669		$	9,377
Fair value of commodity derivatives – long-term assets		611			263
Total Assets	$	3,280		$	9,640
Liabilities:
Fair value of commodity derivatives – current liabilities	$	(2,479	)	$	(1,973	)
Fair value of commodity derivatives – long-term liabilities		(610	)		(861	)
Total Liabilities	$	(3,089	)	$	(2,834	)

4. Accounts and Revenues Receivable

Accounts and revenues receivable at June 30, 2011 and December 31, 2010 were $31.9 million and $44.1 million, respectively, all of which were due from companies in the oil and gas industry. Of the revenues receivable, $28.2 million was due from six companies and $19.7 million was due from five companies at June 30, 2011 and December 31, 2010, respectively.

Since all of RAAM Global’s accounts receivable from purchasers and joint interest owners at June 30, 2011 and December 31, 2010 resulted from sales of crude oil, condensate, natural gas and/or joint interest billings to third-party companies in the oil and gas industry, this concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Management believes that allowances for doubtful accounts were adequate to absorb estimated losses as of June 30, 2011 and December 31, 2010. Management obtains letters of credit from its major purchasers and continually evaluates the creditworthiness of its partners.

5. Commodity Derivative Instruments and Hedging Activities

In order to manage the variability in cash flows associated with the sale of its oil and gas production, the Company has developed a strategy to combine the use of floors, costless collars and futures transactions in order to minimize the downside risk from adverse price movements but allow for the realization of upside profits, if available. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of those contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty.

With respect to any collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price of such transaction. For any particular floor contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with the settlement of a floor contract. Monthly settlements of these contracts are reflected in revenue from oil and gas production.

All of the Company’s commodity derivative transactions are settled based on reported settlement prices on the New York Mercantile Exchange (“NYMEX”). The estimated fair value of these transactions is based on various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The calculation of the fair value of collars and floors utilizes the Black-Scholes option-pricing

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model. Since these transactions were designated as hedges, the Company is required to record the changes in fair value of these transactions asOther Comprehensive Income in the accompanying condensed consolidated balance sheets with the ineffective portion of the change in fair value reported asDerivative (income) expense in the accompanying condensed consolidated statements of operations. See Note 2, Basis of Presentation and Significant Accounting Policies, for additional information on the Company’s hedging activities.

For the three and six months ended June 30, 2011, the Company realized a net increase in oil and gas revenues related to hedging transactions of approximately $939,000 and $6.7 million, respectively. For the three and six months ended June 30, 2010, the Company realized a net increase in oil and gas revenues related to hedging transactions of approximately $14.8 million and $25.9 million, respectively. Hedge ineffectiveness was $(436,000) and $(231,000) for the three and six months ended June 30, 2011, respectively. Hedge ineffectiveness was $1.8 million for 2010.

As of June 30, 2011, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast natural gas production for 2011, 2012 and 2013:

Remaining Contract Term	Contract Type		Volume in MMBtus/Month		NYMEX Strike Price
July 2011 – August 2011		Put		250,000	$	6.50
July 2011 – December 2011		Swap		100,000	$	6.24
July 2011 – October 2011		Swap		92,250	$	4.60
July 2011 – October 2011		Swap		92,250	$	4.80
July 2011 – October 2011		Swap		153,750	$	4.50
July 2011 – December 2011		Swap		100,000	$	6.33
November 2011 – December 2011		Swap		91,500	$	4.85
November 2011 – December 2011		Swap		91,500	$	4.85
November 2011 – February 2012		Call		151,250	$	5.60
November 2011 – February 2012		Put		151,250	$	5.00
November 2011 – February 2012		Put		151,250	$	4.00
January 2012 – February 2012		Swap		100,000	$	6.24
January 2012 – February 2012		Swap		100,000	$	6.33
January 2012 – December 2012		Swap		61,000	$	5.05
January 2012 – December 2012		Swap		61,000	$	5.00
March 2012 – December 2012		Put		153,000	$	3.75
March 2012 – December 2012		Put		153,000	$	5.00
March 2012 – December 2012		Call		153,000	$	6.15
January 2013 – December 2013		Swap		152,083	$	5.40

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As of June 30, 2011, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast oil production for 2011 and 2012:

Remaining Contract Term	Contract Type		Volume in BBls/Month		NYMEX Strike Price
July 2011 – December 2011		Swap		6,000	$	86.76
July 2011 – December 2011		Swap		6,000	$	85.70
July 2011 – December 2011		Swap		10,000	$	85.25
July 2011 – December 2011		Swap		8,000	$	88.20
July 2011 – December 2011		Swap		9,000	$	85.50
January 2012 – March 2012		Swap		10,000	$	89.00
January 2012 – March 2012		Swap		8,000	$	88.24
January 2012 – March 2012		Swap		6,000	$	86.80
January 2012 – December 2012		Put		3,660	$	110.00
April 2012 – June 2012		Swap		6,000	$	88.52
April 2012 – June 2012		Swap		6,000	$	87.05
April 2012 – June 2012		Swap		5,000	$	87.50
July 2012 – September 2012		Swap		12,000	$	88.76
July 2012 – September 2012		Swap		5,000	$	87.80

Additional information regarding derivatives can be referenced in Note 3, Fair Value Measurements.

6. Debt

2015 Senior Secured Notes

On September 24, 2010, we completed an offering of $150.0 million senior secured notes at a coupon rate of 12.50% (the “2015 Senior Secured Notes”) with a maturity date of October 1, 2015. The interest on the notes will be payable in cash semi-annually in arrears on April 1 and October 1 of each year, commencing on April 1, 2011, to holders of record at the close of business on the preceding March 15 or September 15. Interest on the notes will be computed on the basis of a 360-day year of twelve 30-day months. The notes were sold at 99.086% of their face amount and were recorded at their discounted amount, with the discount to be amortized over the life of the notes. The Company used a portion of the net proceeds from the offering to repay all outstanding indebtedness under the revolving credit facility and intends to use the remainder of the proceeds for funding a portion of the planned capital expenditures for development and drilling during 2011. As of June 30, 2011, $150.0 million notional amount of the 2015 Senior Secured Notes was outstanding. The carrying amount of the 2015 Senior Secured Notes was $148.8 million as of June 30, 2011.

The 2015 Senior Secured Notes are guaranteed on a senior secured basis by each of our existing and future domestic subsidiaries that guarantee indebtedness under our Amended Revolving Credit Facility. The 2015 Senior Secured Notes and the guarantees are secured by a security interest in substantially all of our and our existing future domestic subsidiaries’ (other than certain future unrestricted subsidiaries’) assets to the extent they constitute collateral under our Amended Revolving Credit Facility, subject to certain exceptions. Pursuant to an Intercreditor Agreement, the lien securing the notes is subordinated and junior to liens securing our Amended Revolving Credit Facility.

Amended Revolving Credit Facility

On September 24, 2010, an amendment to the Company’s Revolving Credit Facility established a new borrowing base of $62.5 million which was undrawn at June 30, 2011. The Credit Agreement governing the amended revolving credit facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments, and distributions.

F-48

Promissory Note

The Company has a promissory note with GE Commercial Finance Business Property Corporation (“GECF”) with a balance of $2.9 million at June 30, 2011 related to the construction of the Houston office building. The GECF note requires monthly installments of principal and interest in the amount of $27,000 until September 1, 2025. There are no covenant requirements under this note.

Finance Agreement

During May 2011, the Company entered into an agreement to finance the premiums for its annual insurance policies with Imperial Credit Corporation. The finance agreement requires monthly installments of principal and interest in the amount of $0.9 million until February 1, 2012. There are no covenant requirements under this agreement.

7. Income Taxes

TheIncome tax provision for the three months ended June 30, 2011 was $9.4 million or an effective tax rate of 47.1%, compared to $10.5 million or an effective tax rate of 36.2% for the three months ended June 30, 2010. TheIncome tax provision for the six months ended June 30, 2011 was $12.0 million or an effective tax rate of 36.4%, compared to $17.2 million or an effective tax rate of 36.3% for the six months ended June 30, 2010. The difference in these rates for the three months ended June 30, 2011 and June 30, 2010 was primarily due to changes in the expected annual financial results, which affected both the federal and state annualized tax rates.

8. Shareholders’ Equity

During 2011, dividends were paid at $25.00 per share to shareholders of record as of March 1, 2011 and June 15, 2011. During 2010, dividends were paid at $25.00 per share to shareholders of record effective March 15, 2010 and June 15, 2010.

9. Related-Party Transactions

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. Amounts due from such related parties of approximately $912,000 and $734,000 at June 30, 2011 and December 31, 2010, respectively, are included inAccounts receivable in the Company’s condensed consolidated balance sheets and represent joint interest owner receivables. Amounts due to such related parties of $7.2 million and $4.5 million at June 30, 2011 and December 31, 2010, respectively, are included inRevenues payable in the Company’s condensed consolidated balance sheets and represent revenue owner payables.

10. Commitments and Contingencies

The Company has been named as a defendant in certain lawsuits arising in the ordinary course of business. While the outcome of the lawsuits cannot be predicted with certainty, management does not expect that these matters will have a material adverse effect on the financial position, cash flows or results of operations of the Company.

11. Other Comprehensive Income

The Company had Other comprehensive income of $12.1 million and $7.3 million for the three months ended June 30, 2011 and 2010, respectively. The Company had Other comprehensive income of $15.1 million and $24.8 million for the six months ended June 30, 2011 and 2010, respectively.

12. Condensed Consolidating Financial Information

The following condensed consolidating financial information is presented in accordance with SEC regulation S-X requirements relating to multiple subsidiary guarantors of securities issued by the parent company

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of those subsidiaries. During 2010, RAAM Global issued the 2015 Senior Secured Notes, described in Note 6, Debt. Each of RAAM Global’s wholly owned subsidiaries are guarantors of these notes. The guarantees are full and unconditional and joint and several.

The following tables present condensed consolidating balance sheets as of June 30, 2011 and December 31, 2010, condensed consolidating statements of operations for the three and six months ended June 30, 2011 and 2010 and condensed consolidating statements of cash flows for the six months ended June 30, 2011 and 2010, and should be read in conjunction with the condensed consolidated financial statements herein.

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Condensed Consolidating Balance Sheets

At June 30, 2011

	RAAM Global Energy Company			Subsidiary Guarantors		Non- Guarantor VIEs			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	35,931		$	35,272	$	18		$	—		$	71,221
Receivables, net		2,955			40,311		245			(8,579	)		34,932
Commodity derivatives – current portion		—			2,669		—			—			2,669
Prepaids and other current assets		1,614			12,436		—			—			14,050
Total current assets		40,500			90,688		263			(8,579	)		122,872
Net oil and gas properties		51,823			411,530		13,653			—			477,006
Total other assets		33,678			284,742		—			(290,067	)		28,353
Total assets	$	126,001		$	786,960	$	13,916		$	(298,646	)	$	628,231
Liabilities and shareholders’ equity
Current liabilities:
Payables and accrued liabilities	$	5,809		$	39,939	$	8,527		$	(8,579	)	$	45,696
Advances from joint interest partners		—			909		—			—			909
Commodity derivatives – current portion		—			2,479		—			—			2,479
Asset retirement obligations – current portion		—			2,406		—			—			2,406
Long-term debt – current portion		124			6,266		—			—			6,390
Deferred income taxes – current portion		—			797		—			—			797
Total current liabilities		5,933			52,796		8,527			(8,579	)		58,677
Other liabilities:
Commodity derivatives		—			610		—			—			610
Asset retirement obligations		874			21,220		248			—			22,342
Long-term debt		2,787			—		—			—			2,787
Senior secured notes		148,781			—		—			—			148,781
Deferred income taxes		5,198			92,493		1,411			—			99,102
Total other liabilities		157,640			114,323		1,659			—			273,622
Total liabilities		163,573			167,119		10,186			(8,579	)		332,299
Noncontrolling interest		—			—		20,956			—			20,956
Total shareholders’ equity		(37,572	)		619,841		(17,226	)		(290,067	)		274,976
Total liabilities and shareholders’ equity	$	126,001		$	786,960	$	13,916		$	(298,646	)	$	628,231

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Condensed Consolidating Balance Sheets

At December 31, 2010

	RAAM Global Energy Company			Subsidiary Guarantors		Non- guarantor VIEs			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	45,683		$	35,320	$	29		$	—		$	81,032
Receivables, net		3,491			52,019		528			(8,968	)		47,070
Commodity derivatives – current portion		—			9,377		—			—			9,377
Prepaids and other current assets		1,724			6,260		—			—			7,984
Total current assets		50,898			102,976		557			(8,968	)		145,463
Net oil and gas properties		55,808			370,000		11,142			—			436,950
Total other assets		34,444			270,496		—			(290,067	)		14,873
Total assets	$	141,150		$	743,472	$	11,699		$	(299,035	)	$	597,286
Liabilities and shareholders’ equity
Current liabilities:
Payables and accrued liabilities	$	6,423		$	37,490	$	8,448		$	(8,968	)	$	43,393
Commodity derivatives – current portion		—			1,973		—			—			1,973
Asset retirement obligations – current portion		—			2,406		—			—			2,406
Long-term debt – current portion		110			1,002		—			—			1,112
Deferred income taxes – current portion		—			1,810		—			—			1,810
Total current liabilities		6,533			44,681		8,448			(8,968	)		50,694
Other liabilities:
Commodity derivatives		—			861		—			—			861
Asset retirement obligations		872			19,923		151			—			20,946
Long-term debt		2,860			—		—			—			2,860
Senior secured notes		148,681			—		—			—			148,681
Deferred income taxes		5,198			84,827		845			—			90,870
Total other liabilities		157,611			105,611		996			—			264,218
Total liabilities		164,144			150,292		9,444			(8,968	)		314,912
Noncontrolling interest		—			—		2,467			—			2,467
Total shareholders’ equity		(22,994	)		593,180		(212	)		(290,067	)		279,907
Total liabilities and shareholders’ equity	$	141,150		$	743,472	$	11,699		$	(299,035	)	$	597,286

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Condensed Consolidating Statements of Operations

For the three months ended June 30, 2011

	RAAM Global Energy Company			Subsidiary Guarantors			Non- guarantor VIEs		Eliminations		Consolidated
Revenues:
Gas sales	$	254		$	23,904		$	952	$	—	$	25,110
Oil sales		259			24,505			983		—		25,747
Total revenues		513			48,409			1,935		—		50,857
Costs and expenses:
Production and delivery costs		97			8,672			121		—		8,890
Workover costs		—			747			39		—		786
Depreciation, depletion and amortization		1,703			11,908			316		—		13,927
General and administrative expenses		1,138			2,821			7		—		3,966
Bad debt expense		—			770			—		—		770
Derivative income		—			(292	)		—		—		(292	)
Total operating expense		2,938			24,626			483		—		28,047
Income from operations		(2,425	)		23,783			1,452		—		22,810
Other income (expenses):
Interest expense, net		(2,875	)		(74	)		—		—		(2,949	)
Other, net		—			(13	)		—		—		(13	)
Total other income (expenses):		(2,875	)		(87	)		—		—		(2,962	)
Income (loss) before taxes		(5,300	)		23,696			1,452		—		19,848
Income tax provision		2,000			6,924			430		—		9,354
Net income (loss) including noncontrolling interest	$	(7,300	)	$	16,772		$	1,022	$	—	$	10,494
Net income attributable to noncontrolling interest (net of tax)		—			—			1,022		—		1,022
Net income (loss) attributable to RAAM Global	$	(7,300	)	$	16,772		$	—	$	—	$	9,472

F-53

Condensed Consolidating Statements of Operations

For the three months ended June 30, 2010

	RAAM Global Energy Company			Subsidiary Guarantors			Non- guarantor VIEs		Eliminations		Consolidated
Revenues:
Gas sales	$	301		$	32,894		$	633	$	—	$	33,828
Oil sales		236			20,221			595		—		21,052
Total revenues		537			53,115			1,228		—		54,880
Costs and expenses:
Production and delivery costs		97			6,737			89		—		6,923
Workover costs		14			763			—		—		777
Depreciation, depletion and amortization		2,871			10,421			550		—		13,842
General and administrative expenses		915			2,322			16		—		3,253
Derivative income		—			515			—		—		515
Total operating expense		3,897			20,758			655		—		25,310
Income from operations		(3,360	)		32,357			573		—		29,570
Other income (expenses):
Interest expense, net		(33	)		(867	)		—		—		(900	)
Other, net		46			424			—		—		470
Total other income (expenses)		13			(443	)		—		—		(430	)
Income (loss) before taxes		(3,347	)		31,914			573		—		29,140
Income tax provision		10,045			496			—		—		10,541
Net income (loss) including noncontrolling interest	$	(13,392	)	$	31,418		$	573	$	—	$	18,599
Net income attributable to noncontrolling interest (net of tax)		—			—			573		—		573
Net income (loss) attributable to RAAM Global	$	(13,392	)	$	31,418		$	—	$	—	$	18,026

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Condensed Consolidating Statements of Operations

For the six months ended June 30, 2011

	RAAM Global Energy Company			Subsidiary Guarantors			Non- guarantor VIEs		Eliminations		Consolidated
Revenues:
Gas sales	$	396		$	47,406		$	1,622	$	—	$	49,424
Oil sales		469			44,828			1,609		—		46,906
Total revenues		865			92,234			3,231		—		96,330
Costs and expenses:
Production and delivery costs		215			15,915			222		—		16,352
Workover costs		—			1,177			41		—		1,218
Depreciation, depletion and amortization		4,155			26,015			896		—		31,066
General and administrative expenses		2,568			5,769			8		—		8,345
Bad debt expense		—			770			—		—		770
Derivative income		—			(539	)		—		—		(539	)
Total operating expense		6,938			49,107			1,167		—		57,212
Income from operations		(6,073	)		43,127			2,064		—		39,118
Other income (expenses):
Interest expense, net		(6,193	)		(155	)		—		—		(6,348	)
Other, net		184			(3	)		—		—		181
Total other income (expenses)		(6,009	)		(158	)		—		—		(6,167	)
Income (loss) before taxes		(12,082	)		42,969			2,064		—		32,951
Income tax provision		2,000			9,422			588		—		12,010
Net income (loss) including noncontrolling interest	$	(14,082	)	$	33,547		$	1,476	$	—	$	20,941
Net income attributable to noncontrolling interest (net of tax)		—			—			1,476		—		1,476
Net income (loss) attributable to RAAM Global	$	(14,082	)	$	33,547		$	—	$	—	$	19,465

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Condensed Consolidating Statements of Operations

For the six months ended June 30, 2010

	RAAM Global Energy Company			Subsidiary Guarantors			Non- guarantor VIEs		Eliminations		Consolidated
Revenues:
Gas sales	$	684		$	66,697		$	1,206	$	—	$	68,587
Oil sales		469			41,385			1,144		—		42,998
Total revenues		1,153			108,082			2,350		—		111,585
Costs and expenses:
Production and delivery costs		205			14,455			151		—		14,811
Workover costs		20			2,047			—		—		2,067
Depreciation, depletion and amortization		5,631			32,811			1,100		—		39,542
General and administrative expenses		1,747			4,628			16		—		6,391
Derivative income		—			309			—		—		309
Total operating expense		7,603			54,250			1,267		—		63,120
Income from operations		(6,450	)		53,832			1,083		—		48,465
Other income (expenses):
Interest expense, net		(85	)		(1,553	)		—		—		(1,638	)
Other, net		66			470			—		—		536
Total other income (expenses):		(19	)		(1,083	)		—		—		(1,102	)
Income (loss) before taxes		(6,469	)		52,749			1,083		—		47,363
Income tax provision		10,045			7,032			137		—		17,214
Net income (loss) including noncontrolling interest	$	(16,514	)	$	45,717		$	946	$	—	$	30,149
Net income attributable to noncontrolling interest (net of tax)		—			—			946		—		946
Net income (loss) attributable to RAAM Global	$	(16,514	)	$	45,717		$	—	$	—	$	29,203

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Condensed Consolidating Statements of Cash Flows

For the six months ended June 30, 2011

	RAAM Global Energy Company			Subsidiary Guarantors			Non- guarantor VIEs			Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(9,226	)	$	77,528		$	3,392		$	—	$	71,694
Investing activities
Change in investments between affiliates		2,498			(2,498	)		—			—		—
Change in advances from joint interest partners		—			909			—			—		909
Payment of prepaid drilling expenses		—			(14,000	)		—			—		(14,000	)
Additions to oil and gas properties and equipment		(66	)		(69,376	)		(3,403	)		—		(72,845	)
Proceeds from net sales of oil and gas properties		—			2,125			—			—		2,125
Net cash provided by (used in) investing activities		2,432			(82,840	)		(3,403	)		—		(83,811	)
Financing activities
Proceeds from long-term borrowings		—			8,037			—			—		8,037
Payments on long-term borrowings		(59	)		(2,773	)		—			—		(2,832	)
Payment of dividends		(3,000	)		—			—			—		(3,000	)
Other		101			—			—			—		101
Net cash used in financing activities		(2,958	)		5,264			—			—		2,306
Increase (decrease) in cash and cash equivalents		(9,752	)		(48	)		(11	)		—		(9,811	)
Cash and cash equivalents, beginning of period		45,683			35,320			29			—		81,032
Cash and cash equivalents, end of period	$	35,931		$	35,272		$	18		$	—	$	71,221

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Condensed Consolidating Statements of Cash Flows

For the six months ended June 30, 2010

	RAAM Global Energy Company			Subsidiary Guarantors			Non- guarantor VIEs			Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(13,734	)	$	68,770		$	2,069		$	—	$	57,105
Investing activities
Change in investments		—			149			—			—		149
Change in investments between affiliates		16,438			(16,438	)		—			—		—
Change in advances from joint interest partners		—			(991	)		—			—		(991	)
Additions to oil and gas properties and equipment		(167	)		(26,729	)		(2,076	)		—		(28,972	)
Net cash provided by (used in) investing activities		16,271			(44,009	)		(2,076	)		—		(29,814	)
Financing activities
Proceeds from long-term borrowings		—			8,874			—			—		8,874
Payments on long-term borrowings		(46	)		(12,009	)		—			—		(12,055	)
Deferred loan costs		—			304			—			—		304
Payment of dividends		(3,000	)		—			—			—		(3,000	)
Net cash used in financing activities		(3,046	)		(2,831	)		—			—		(5,877	)
Increase (decrease) in cash and cash equivalents		(509	)		21,930			(7	)		—		21,414
Cash and cash equivalents, beginning of period		3,190			25,681			17			—		28,888
Cash and cash equivalents, end of period	$	2,681		$	47,611		$	10		$	—	$	50,302

13. Subsequent Events

Issuance and Sale of Senior Notes

On July 15, 2011, the Company successfully completed the issuance and sale of $50.0 million aggregate principal amount of additional 12.50% Senior Notes due 2015 (the “Notes”). The Notes are Additional Notes issued pursuant to the indenture dated as of September 24, 2010, pursuant to which the Company initially issued $150.0 million aggregate principal amount of its 12.50% Notes, as supplemented by the First Supplemental Indenture dated as of July 15, 2011. The Additional Notes have identical terms, other than the issue date and issue price, and constitute part of the same series as the initially issued notes, although they bear a different CUSIP number than the initially issued notes until they are no longer restricted securities under the Securities Act. The Additional Notes are jointly and severally, and unconditionally, guaranteed on a senior secured basis by all of the Company’s current and future domestic subsidiaries that guarantee indebtedness under our Amended Revolving Credit Facility.

Interest on the Notes accrues from and including April 1, 2011 at a rate of 12.50% per year. Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, commencing on October 1, 2011. The Notes mature on October 1, 2015.

The purchase price for the Notes was 102.50% of their principal amount, plus accrued interest from April 1, 2011. The Company received net proceeds from the issuance and sale of the Notes of approximately $51.7 million, after discounts and estimated offering expenses. The Company intends to use the net proceeds from the offering for general corporate purposes.

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Annex A

LETTER OF TRANSMITTAL

TO TENDER

OLD 12.50% SENIOR NOTES DUE 2015

(CUSIPs: 74920AAD1 AND U7501BAB7)

OF

RAAM GLOBAL ENERGY COMPANY

PURSUANT TO THE EXCHANGE OFFER AND PROSPECTUS

DATED                     , 2011

THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M., NEW YORK

CITY TIME, ON                     , 2011 (THE “EXPIRATION DATE”), UNLESS THE EXCHANGE OFFER IS

EXTENDED BY THE ISSUER.

The Exchange Agent for the Exchange Offer is The Bank of New York Mellon Trust Company, N.A., and its contact information is as follows:

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

c/o The Bank of New York Mellon Corporation

Corporate Trust Operations — Reorganization Unit

101 Barclays St., Floor 7E

New York, NY 10286

By Facsimile (for Eligible Institutions only):

(212) 298-1915

For Information or Confirmation by

Telephone:

If you wish to exchange your issued and outstanding 12.50% Senior Notes due 2015 (the “old notes”) for an equal aggregate principal amount of 12.50% Senior Notes due 2015 (the “new notes”) with materially identical terms that have been registered under the Exchange Act of 1933 (the “Exchange Act”) pursuant to the exchange offer, you must validly tender (and not withdraw) old notes to the Exchange Agent prior to the Expiration Date.

We refer you to the Prospectus, dated                     , 2011 (the “Prospectus”), of RAAM Global Energy Company (the “Issuer”), and this Letter of Transmittal (this “Letter of Transmittal”), which together describe the Issuer’s offer (the “Exchange Offer”) to exchange the old notes for a like aggregate principal amount new notes. Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

The Issuer reserves the right, at any time or from time to time, to extend the Exchange Offer at its discretion, in which event the term “Expiration Date” shall mean the latest date to which the Exchange Offer is extended. The Issuer shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

This Letter of Transmittal is to be used by holders of the old notes. Tender of the old notes is to be made according to the Automated Tender Offer Program (“ATOP”) of The Depository Trust Company (“DTC”) pursuant to the procedures set forth in the Prospectus under the caption “Exchange Offer — Procedures for Tendering.” DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC,

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which will verify the acceptance and execute a book-entry delivery to the Exchange Agent’s DTC account. DTC will then send a computer generated message known as an “agent’s message” to the Exchange Agent for its acceptance. For you to validly tender your old notes in the Exchange Offer, the Exchange Agent must receive, prior to the Expiration Date, an agent’s message under the ATOP procedures that confirms that:

• DTC has received your instructions to tender your old notes; and

• you agree to be bound by the terms of this Letter of Transmittal.

BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

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PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.

Ladies and Gentlemen:

1. By tendering old notes in the Exchange Offer, you acknowledge receipt of the Prospectus and this Letter of Transmittal.

2. By tendering old notes in the Exchange Offer, you represent and warrant that you have (1) full authority to tender the old notes described above and will, upon request, execute and deliver any additional documents deemed by the Issuer to be necessary or desirable to complete the tender of old notes, (2) the Issuer will acquire good, marketable and unencumbered title to the tendered old notes, free and clear of all liens, restrictions, charges and other encumbrances, and (3) the old notes tendered hereby are not subject to any adverse claims or proxies.

3. You understand that the tender of the old notes pursuant to all of the procedures set forth in the Prospectus will constitute an agreement between you and the Issuer as to the terms and conditions set forth in the Prospectus.

4. By tendering old notes in the Exchange Offer, you acknowledge that the Exchange Offer is being made in reliance upon interpretations contained in no-action letters issued to third parties by the staff of the Securities and Exchange Commission (the “SEC”), including Exxon Capital Holdings Corp., SEC No-Action Letter (available April 13, 1989), Morgan Stanley & Co., Inc., SEC No-Action Letter (available June 5, 1991) and Shearman & Sterling, SEC No-Action Letter (available July 2, 1993), that the new notes issued in exchange for the old notes pursuant to the Exchange Offer may be offered for resale, resold and otherwise transferred by holders thereof without compliance with the registration and prospectus delivery provisions of the Securities Act of 1933 (the “Securities Act”) (other than a broker-dealer who purchased old notes exchanged for such new notes directly from the Issuer to resell pursuant to Rule 144A or any other available exemption under the Securities Act and any such holder that is an “affiliate” of the Issuer within the meaning of Rule 405 under the Securities Act), provided that such new notes are acquired in the ordinary course of such holders’ business and such holders are not participating in, and have no arrangement with any other person to participate in, the distribution of such new notes.

5. By tendering old notes in the Exchange Offer, you hereby represent and warrant that:

(a) the new notes acquired pursuant to the Exchange Offer are being obtained in the ordinary course of business of you, whether or not you are the holder;

(b) you have no arrangement or understanding with any person to participate in the distribution of old notes or new notes within the meaning of the Securities Act;

(c) you are not an “affiliate,” as such term is defined under Rule 405 promulgated under the Securities Act, of the Company; and

(d) if you are a broker-dealer, that you will receive the new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities and that you acknowledge that you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your old notes registered in the shelf registration statement described in the Registration Rights Agreement, dated as of September 24, 2010 (the “Registration Rights Agreement”), by and among the Issuer, the several guarantors named therein, and the Initial Purchasers (as defined therein). Such election may be made by notifying the Issuer in writing at 1537 Bull Lea Road, Suite 200, Lexington, Kentucky 40511, Attention: Corporate Secretary. By making such election, you agree, as a holder of old notes participating in a shelf registration, to indemnify and hold harmless the Issuer, each of the directors of the Issuer, each of the officers of the Issuer who signs such shelf

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registration statement, each person who controls the Issuer within the meaning of either the Securities Act or the Securities Exchange Act of 1934 (the “Exchange Act”), and each other holder of old notes, from and against any and all losses, claims, damages or liabilities caused by any untrue statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to you furnished in writing by or on behalf of you expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provision of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.

6. If you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities, you acknowledge by tendering old notes in the Exchange Offer, that you will deliver a prospectus in connection with any resale of such new notes; however, by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act.

7. If you are a broker-dealer and old notes held for your own account were not acquired as a result of market-making or other trading activities, such old notes cannot be exchanged pursuant to the Exchange Offer.

8. Any of your obligations hereunder shall be binding upon your successors, assigns, executors, administrators, trustees in bankruptcy and legal and personal representatives.

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INSTRUCTIONS

FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER

1. Book-Entry Confirmations.

Any confirmation of a book-entry transfer to the Exchange Agent’s account at DTC of old notes tendered by book-entry transfer (a “Book-Entry Confirmation”), as well as Agent’s Message and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at one of its addresses set forth herein prior to 5:00 p.m., New York City time, on the Expiration Date.

2. Partial Tenders.

Tenders of old notes will be accepted only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The entire principal amount of old notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all old notes is not tendered, then old notes for the principal amount of old notes not tendered and new notes issued in exchange for any old notes accepted will be delivered to the holder via the facilities of DTC promptly after the old notes are accepted for exchange.

3. Validity of Tenders.

All questions as to the validity, form, eligibility (including time of receipt), acceptance, and withdrawal of tendered old notes will be determined by the Issuer, in its sole discretion, which determination will be final and binding. The Issuer reserves the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Issuer, be unlawful. The Issuer also reserves the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any old notes. The Issuer’s interpretation of the terms and conditions of the Exchange Offer (including the instructions on the Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as the Issuer shall determine. Although the Issuer intends to notify holders of defects or irregularities with respect to tenders of old notes, neither the Issuer, the Exchange Agent, nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any old notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders, unless otherwise provided in the Letter of Transmittal, promptly following the Expiration Date.

4. Waiver of Conditions.

The Issuer reserves the absolute right to waive, in whole or part, up to the expiration of the Exchange Offer, any of the conditions to the Exchange Offer set forth in the Prospectus or in this Letter of Transmittal.

5. No Conditional Tender.

No alternative, conditional, irregular or contingent tender of old notes will be accepted.

6. Request for Assistance or Additional Copies.

Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent using the contact information set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.

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7. Withdrawal.

Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption “Exchange Offer — Withdrawal of Tenders.”

8. No Guarantee of Late Delivery. There is no procedure for guarantee of late delivery in the Exchange Offer.

IMPORTANT: BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

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RAAM Global Energy Company

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of Directors and Officers.

Section 145(a) of the General Corporation Law of the State of Delaware (the “DGCL”), in which RAAM Global Energy Company is incorporated, provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that the person is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by the person in connection with such action, suit or proceeding if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe the person’s conduct was unlawful. Section 145(b) of the DGCL provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that the person is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys’ fees) actually and reasonably incurred by the person in connection with the defense or settlement of such action or suit if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper. To the extent that a present or former director or officer of a corporation has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to in subsections (a) and (b) of Section 145 of the DGCL, or in defense of any claim, issue or matter therein, such person shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred by such person in connection therewith.

Any indemnification under subsections (a) and (b) of Section 145 of the DGCL (unless ordered by a court) shall be made by the corporation only as authorized in the specific case upon a determination that indemnification of the present or former director, officer, employee or agent is proper in the circumstances because the person has met the applicable standard of conduct set forth in subsections (a) and (b) of Section 145. Such determination shall be made, with respect to a person who is a director or officer at the time of such determination, (1) by a majority vote of the directors who are not parties to such action, suit or proceeding, even though less than a quorum, or (2) by a committee of such directors designated by majority vote of such directors, even though less than a quorum, or (3) if there are no such directors, or if such directors so direct, by independent legal counsel in a written opinion, or (4) by the stockholders. Expenses (including attorneys’ fees) incurred by an officer or director in defending any civil, criminal, administrative or investigative action, suit or proceeding may be paid by the corporation in advance of the final disposition of such action, suit or proceeding upon receipt of an undertaking by or on behalf of such director or officer to repay such amount if it shall ultimately be determined that such person is not entitled to be indemnified by the corporation as authorized in this section. Such expenses (including attorneys’ fees) incurred by former directors and officers or other employees and agents may be so paid upon such terms and conditions, if any, as the corporation deems appropriate. The indemnification and advancement of expenses provided by, or granted pursuant to, Section 145 shall not be deemed exclusive of any other rights to which those seeking indemnification or advancement of expenses may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise, both as to action in such person’s official capacity and as to action in another capacity while holding such office.

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Section 145 of the DGCL also empowers a corporation to purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against any liability asserted against such person and incurred by such person in any such capacity, or arising out of such person’s status as such, whether or not the corporation would have the power to indemnify such person against such liability under Section 145.

Article Seven of our Certificate of Incorporation provides that any person who is permitted to be indemnified under Section 145 of the DGCL shall be indemnified to the fullest extent permitted by Section 145 of the DGCL and Section 9.1 of our Bylaws provides a non-exclusive indemnification for certain acts by persons acting as an officer, director, employee or agent of the Company.

The Company determines whether the indemnification of the present or former director, officer, employee or agent is proper in the circumstances in accordance with Section 145 of the DGCL as described above.

We carry directors and officers liability coverages designed to insure our officers and directors and those of our subsidiaries against certain liabilities incurred by them in the performance of their duties, and also providing for reimbursement in certain cases to us and our subsidiaries for sums paid to directors and officers as indemnification for similar liability.

Item 21. Exhibits and Financial Statement Schedules.

(a) The exhibits required to be filed pursuant to the requirements of Item 601 of Regulation S-K are set forth in the Index to Exhibits accompanying this registration statement.

Schedules are omitted because they either are not required or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.

Item 22. Undertakings.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrants, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of a registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, such registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

Each registrant hereby undertakes:

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(a) to include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(b) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from

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the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

(c) to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, if such registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

That, for the purpose of determining liability of such registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, in a primary offering of securities of such registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(a) any preliminary prospectus or prospectus of the undersigned registrants relating to the offering required to be filed pursuant to Rule 424;

(b) any free writing prospectus relating to the offering prepared by or on behalf of such registrant or used or referred to by the undersigned registrants;

(c) the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrants or their securities provided by or on behalf of such registrant; and

(d) any other communication that is an offer in the offering made by such registrant to the purchaser.

That, for purposes of determining any liability under the Securities Act of 1933, each filing of a registrant annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

To deliver or cause to be delivered with the prospectus, to each person to whom the prospectus is sent or given, the latest annual report to security holders that is incorporated by reference in the prospectus and furnished pursuant to and meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Securities Exchange Act of 1934; and, where interim financial information required to be presented by Article 3 of Regulation S-X are not

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set forth in the prospectus, to deliver, or cause to be delivered to each person to whom the prospectus is sent or given, the latest quarterly report that is specifically incorporated by reference in the prospectus to provide such interim financial information.

To respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lexington, State of Kentucky, on October 6, 2011.

RAAM GLOBAL ENERGY COMPANY
By:	/s/ Howard A. Settle
	Howard A. Settle
	President and Chief Executive Officer

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Howard A. Settle and Jeffrey T. Craycraft, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this registration statement (including post-effective amendments and registration statements filed pursuant to Rule 462 or otherwise) and to file the same, with all exhibits thereto, and the other documents in connection therewith, with the Securities and Exchange Commission, and hereby grants to such attorneys-in-fact and agents and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.

Signatures	Title	Date
/s/ Howard A. Settle Howard A. Settle	Chairman of the Board, Director, President and Chief Executive Officer (principal executive officer)	October 6, 2011
/s/ Jeffrey T. Craycraft Jeffrey T. Craycraft	Chief Financial Officer and Vice President (principal financial and accounting officer)	October 6, 2011
/s/ Jonathan B. Rudney Jonathan B. Rudney	Director	October 6, 2011
/s/ Michael J. Willis Michael J. Willis	Director, Chief Operating Officer	October 6, 2011
/s/ Thomas M. Lewry Thomas M. Lewry	Director, Vice President	October 6, 2011
/s/ Robert E. Fox Robert E. Fox	Director	October 6, 2011

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lexington, State of Kentucky, on October 6, 2011.

CENTURY EXPLORATION NEW ORLEANS, LLC
By:	/s/ Howard A. Settle
	Howard A. Settle
	President

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.

Signatures	Title	Date
/s/ Howard A. Settle Howard A. Settle	President and Manager (principal executive officer)	October 6, 2011
/s/ Jeffrey T. Craycraft Jeffrey T. Craycraft	Treasurer (principal financial and accounting officer)	October 6, 2011
/s/ Jonathan B. Rudney Jonathan B. Rudney	Manager	October 6, 2011
/s/ Michael J. Willis Michael J. Willis	Manager	October 6, 2011
/s/ Thomas M. Lewry Thomas M. Lewry	Manager	October 6, 2011
/s/ Robert E. Fox Robert E. Fox	Manager	October 6, 2011

II-6

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lexington, State of Kentucky, on October 6, 2011.

CENTURY EXPLORATION HOUSTON, LLC
By:	/s/ Howard A. Settle
	Howard A. Settle
	President

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.

Signatures	Title	Date
/s/ Howard A. Settle Howard A. Settle	President and Manager (principal executive officer)	October 6, 2011
/s/ Jeffrey T. Craycraft Jeffrey T. Craycraft	Treasurer (principal financial and accounting officer)	October 6, 2011
/s/ Jonathan B. Rudney Jonathan B. Rudney	Manager	October 6, 2011
/s/ Michael J. Willis Michael J. Willis	Manager	October 6, 2011
/s/ Thomas M. Lewry Thomas M. Lewry	Manager	October 6, 2011
/s/ Robert E. Fox Robert E. Fox	Manager	October 6, 2011

II-7

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lexington, State of Kentucky, on October 6, 2011.

CENTURY EXPLORATION RESOURCES, LLC
By:	/s/ Jonathan B. Rudney
	Jonathan B. Rudney
	President

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.

Signatures	Title	Date
/s/ Jonathan B. Rudney Jonathan B. Rudney	President and Manager (principal executive officer)	October 6, 2011
/s/ Jeffrey T. Craycraft Jeffrey T. Craycraft	Treasurer (principal financial and accounting officer)	October 6, 2011
/s/ Howard A. Settle Howard A. Settle	Manager	October 6, 2011
/s/ Michael J. Willis Michael J. Willis	Manager	October 6, 2011
/s/ Thomas M. Lewry Thomas M. Lewry	Manager	October 6, 2011
/s/ Robert E. Fox Robert E. Fox	Manager	October 6, 2011

II-8

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lexington, State of Kentucky, on October 6, 2011.

SITA ENERGY, LLC
By:	RAAM Global Energy Company, its Sole Member
By:	/s/ Howard A. Settle
	Howard A. Settle
	President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.

Signatures	Title	Date
/s/ Howard A. Settle Howard A. Settle	Sole Manager (principal executive, financial and accounting officer)	October 6, 2011

II-9

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lexington, State of Kentucky, on October 6, 2011.

WINDSTAR ENERGY, LLC
By:	RAAM Global Energy Company, its Sole Member
By:	/s/ Howard A. Settle
	Howard A. Settle
	President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.

Signatures	Title	Date
/s/ Howard A. Settle Howard A. Settle	Sole Manager (principal executive, financial and accounting officer)	October 6, 2011

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INDEX TO EXHIBITS

Exhibit Number	Description
3.1	Certificate of Incorporation of RAAM Global Energy Company, dated November 19, 2003 (incorporated by reference from Exhibit 3.1 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
3.2	Bylaws of RAAM Global Energy Company (incorporated by reference from Exhibit 3.2 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
4.1	Indenture, dated as of September 24, 2010, among RAAM Global Energy Company, the several guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference from Exhibit 4.1 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
4.2	First Supplemental Indenture, dated as of July 15, 2011, by and among RAAM Global Energy Company, the several guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference to Exhibit 4.2 to the Form 8-K filed on July 19, 2011 (File No. 333-172897)).
4.3	Registration Rights Agreement dated as of July 15, 2011, among RAAM Global Energy Company, the Guarantor parties named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.3 to the Form 8-K filed on July 19, 2011 (File No. 333-172897)).
4.4	Intercreditor Agreement, dated as of September 24, 2010, by and among Union Bank, N.A., as administrative agent for the first lien creditors named therein, The Bank of New York Mellon Trust Company, N.A., as indenture trustee for the second lien creditors named therein, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC and RAAM Global Energy Company (incorporated by reference from Exhibit 4.3 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
4.5	Security Agreement, dated September 24, 2010, by RAAM Global Energy Company and the several guarantors name therein in favor of The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference from Exhibit 4.4 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
5.1*	Opinion of Vinson & Elkins L.L.P.
10.1	Third Amended and Restated Credit Agreement, dated September 4, 2009, by and among Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Union Bank, N.A., individually and as administrative agent, and the lenders named therein (incorporated by reference from Exhibit 10.1 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.2	First Amendment to Third Amended and Restated Credit Agreement, dated March 1, 2010, by and among Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Union Bank, N.A., individually and as administrative agent, and the lenders party to the Third Amended and Restated Credit Agreement, dated September 4, 2009 (incorporated by reference from Exhibit 10.2 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.3	Second Amendment to Third Amended and Restated Credit Agreement, dated September 24, 2010, by and among Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Union Bank, N.A., individually and as administrative agent, and the lenders party to the Third Amended and Restated Credit Agreement, dated September 4, 2009 (incorporated by reference from Exhibit 10.3 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).

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Exhibit Number	Description
10.4	Third Amendment to Third Amended and Restated Credit Agreement, dated March 4, 2011, by and among Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Union Bank, N.A., individually and as administrative agent, and the lenders party to the Third Amended and Restated Credit Agreement, dated September 4, 2009 (incorporated by reference from Exhibit 10.4 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.5*	Fourth Amendment to Third Amended and Restated Credit Agreement, dated July 14, 2011, by and among Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Union Bank, N.A., individually and as administrative agent, and the lenders party to the Third Amended and Restated Credit Agreement, dated September 4, 2009.
10.6	Premium Finance Agreement, dated May 1, 2010, between RAAM Global Energy Company and Century Exploration Resources, LLC, as borrowers, and USI Southwest-Houston, as lender (incorporated by reference from Exhibit 10.6 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.7	Promissory Note, dated August 8, 2005, between RAAM Global Energy Company and GE Commercial Finance Business Property Corporation (incorporated by reference from Exhibit 10.6 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.8†	Employment Agreement, dated January 1, 2011, between RAAM Global Energy Company and Howard A. Settle (incorporated by reference from Exhibit 10.7 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.9†	Employment Agreement, dated January 1, 2011, between Century Exploration Resources, LLC and Jonathan B. Rudney (incorporated by reference from Exhibit 10.8 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.10†	Employment Agreement, dated January 1, 2011, between Century Exploration Houston, LLC and Wayne L. Adams (incorporated by reference from Exhibit 10.9 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.11†	Employment Agreement, dated December 17, 2007, between RAAM Global Energy Company and Harry C. Kelly, Jr. (incorporated by reference from Exhibit 10.10 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.12	Lease Agreement, dated January 1, 2011, between ATMA Investments, LLC and RAAM Global Energy Company (incorporated by reference from Exhibit 10.11 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.13	December 2004 Agreement, dated December 1, 2004, between RAAM Global Energy and RAAM Exploration LLC (incorporated by reference from Exhibit 10.12 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.14	Termination of the December 2004 Agreement, dated June 3, 2009, between RAAM Global Energy and Ram Development LLC and RAAM Exploration LLC (incorporated by reference from Exhibit 10.13 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.15	September 2003 Agreement, dated September 22, 2003, between Century Exploration Company and RAAM Exploration LLC (incorporated by reference from Exhibit 10.14 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
10.16	Participation and Exploration Agreement, dated August 3, 2009, between RAAM Global Energy Company, Century Exploration Houston, LLC and TechXplore, L.P. (incorporated by reference from Exhibit 10.15 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).

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Exhibit Number	Description
10.17†	After Payout Overriding Royalty Plan of RAAM Global Energy Company and Century Exploration New Orleans, LLC, dated December 1, 2004 (incorporated by reference from Exhibit 10.16 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
12.1*	Computation of Ratio of Earnings to Fixed Charges.
21.1	Subsidiaries of RAAM Global Energy Company (incorporated by reference from Exhibit 21.1 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
23.1*	Consent of Ernst & Young LLP.
23.2*	Consent of Netherland, Sewell & Associates, Inc.
23.3*	Consent of H.J. Gruy and Associates, Inc.
23.4*	Consent of Vinson & Elkins L.L.P. (included in Exhibit 5.1).
24.1*	Powers of Attorney (included on the signature pages hereto).
25.1*	Statement of Eligibility on Form T-1 of The Bank of New York Mellon Trust Company, N.A.
99.1	Summary Report of Netherland, Sewell & Associates, Inc. (incorporated by reference from Exhibit 99.1 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
99.2	Summary Report of H.J. Gruy and Associates, Inc. (incorporated by reference from Exhibit 99.2 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
101*	Interactive data file.

* Filed herewith.

† Management contract or compensatory plan or arrangement.

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