As filed with the Securities and Exchange Commission on January 3, 2007

Registration No. 333-138922

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

AMENDMENT NO. 1 TO

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

RAM ENERGY RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	1311	20-700684
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

5100 East Skelly Drive, Suite 650

Tulsa, Oklahoma 74135

(918) 663-2800

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

John M. Longmire

Senior Vice President and Chief Financial Officer

5100 East Skelly Drive, Suite 650

Tulsa, Oklahoma 74135

(918) 663-2800

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

COPIES TO:

Theodore M. Elam, Esq.	Charles L. Strauss, Esq.
McAfee & Taft A Professional Corporation 211 North Robinson, Suite 1000 Oklahoma City, Oklahoma 73102 (405) 235-9621	Fulbright & Jaworski L.L.P. Fulbright Tower 1301 McKinney Street, Suite 5100 Houston, Texas 77010 (713) 651-5151

Approximate date of commencement of proposed sale of the securities to the public:

As soon as practicable on or after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 of the Securities Act of 1933, 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, please 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(c) 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.  ¨

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price (1)(2)	Amount of Registration Fee(1)(2)(3)
Common Stock, par value $0.0001 per share	$74,750,000	$7,999

(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933.

(2) Includes amounts attributable to shares which the underwriter has the option to purchase to cover over-allotments, if any.

(3) The Registrant paid $6,955 of this filing fee in connection with the filing of a Form S-1 with the Commission on November 22, 2006 (Commission File No. 333-138922).

The 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.

The information contained in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer, solicitation or sale is not permitted.

Subject to completion, dated January 3, 2007

PROSPECTUS

11,796,734 Shares

RAM Energy Resources, Inc.

Common Stock

We are offering 9,074,411 shares of our common stock and 2,722,323 shares are being offered by the selling stockholder identified in this prospectus. We will not receive any proceeds from the sale of the shares by the selling stockholder.

Our shares of common stock are quoted on the Nasdaq Capital Market under the symbol “RAME”. On December 29, 2006, the last reported sale price of our common stock was $5.51 per share.

You should read the risk factors beginning on page 12 of this prospectus to learn about certain factors you should consider before buying shares of our common stock.

PRICE $             PER SHARE

	Per Share	Total
Public Offering Price	$	$
Underwriting Discount	$	$
Net proceeds to RAM Energy Resources, Inc.	$	$
Net proceeds to the selling stockholder (1)	$	$

(1) We will pay all expenses, other than underwriting discounts payable by the selling stockholder, associated with the offering.

We have granted an over-allotment option to the underwriters. Under this option, the underwriters may elect to purchase a maximum of 1,769,510 additional shares from us at the public offering price less underwriting discount within 30 days following the date of this prospectus to cover over-allotments.

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

The underwriters expect to deliver the shares of common stock to investors on or about                     , 2007.

RBC CAPITAL MARKETS

JEFFERIES & COMPANY	JOHNSON RICE & COMPANY L.L.C.
SANDERS MORRIS HARRIS	FERRIS, BAKER WATTS INCORPORATED

GILFORD SECURITIES INCORPORATED

                    , 2007.

TABLE OF CONTENTS

	Page
Cautionary Statement Regarding Forward-Looking Statements	i
Prospectus Summary	1
Risk Factors	12
Use of Proceeds	19
Dividend Policy	19
Dilution	19
Capitalization	21
Selected Consolidated Financial Data	22
Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Quantitative and Qualitative Disclosures About Market Risk	39
Business and Properties	40

	Page
Management	56
Selling Stockholder and Security Ownership of Certain Beneficial Owners and Management	63
Certain Relationships and Related Party Transactions	64
Description of Capital Stock	68
Price Range of Securities and Dividends	72
Underwriting	73
Legal Matters	76
Experts	77
Where You Can Find More Information	78
Glossary of Oil and Natural Gas Terms	79
Index to Financial Statements	F-1

ABOUT THIS PROSPECTUS

You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this 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 about our:

Ÿ business strategy;

Ÿ reserves;

Ÿ technology;

Ÿ financial strategy;

Ÿ oil and natural gas realized prices;

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

Ÿ the amount, nature and timing of capital expenditures;

Ÿ drilling of wells;

Ÿ competition and government regulations;

Ÿ marketing of oil and natural gas;

Ÿ property acquisitions;

Ÿ costs of developing our properties and conducting other operations;

Ÿ general economic conditions;

Ÿ uncertainty regarding our future operating results; and

Ÿ plans, objectives, expectations and intentions contained in this prospectus that are not historical.

All forward-looking statements speak only as of the date of this prospectus, and we do not intend to update any of these forward-looking statements to reflect changes in events or circumstances that arise after the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data are also based on our good faith estimates. Although we believe these third-party sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness.

i

PROSPECTUS SUMMARY

This summary highlights information contained in other parts of our prospectus. Because it is a summary, it does not contain all information that you should consider before investing in our shares. You should read the entire prospectus carefully, including “Risk Factors,” our financial statements and the notes thereto. We have included definitions of technical terms important to an understanding of our business under “Glossary of Oil and Natural Gas Terms.”

Unless the context otherwise requires, all references in this prospectus to “RAM Energy Resources,” “our,” “us,” and “we” refer to RAM Energy Resources, Inc. (formerly known as Tremisis Energy Acquisition Corporation) and its subsidiaries, as a combined entity. All references in this prospectus to “RAM Energy” refer to RAM Energy, Inc., our wholly owned subsidiary. Unless the context otherwise requires, the information contained in this prospectus gives effect to the May 8, 2006 consummation of the merger of RAM Energy Acquisition, Inc., our wholly owned subsidiary, with and into RAM Energy, and the change of our name from Tremisis Energy Acquisition Corporation to RAM Energy Resources, Inc., which transactions are collectively called the “merger.” See “Prospectus Summary—Recent Events” for a discussion of the merger. As used in this prospectus, EBITDA refers to net income before interest expense, amortization, depreciation, accretion, income taxes, gain on early extinguishment of debt, gain on sale of oil and natural gas properties, share-based compensation, extraordinary gains or losses, the cumulative effects of changes in accounting principles and unrealized gains or losses on derivatives.

RAM Energy Resources, Inc.

We are an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of oil and natural gas properties, primarily in Texas, Louisiana and Oklahoma. Our producing properties are located in highly prolific basins with long histories of oil and natural gas operations. We have been active in these core areas since our inception in 1987 and have grown through a balanced strategy of acquisitions and development and exploratory drilling. We have completed over 20 acquisitions of producing oil and natural gas properties and related assets for an aggregate purchase price approximating $400 million. Through December 31, 2006, we have drilled or participated in the drilling of 561 oil and natural gas wells, 93% of which were successfully completed and produced hydrocarbons in commercial quantities. Our management team has extensive technical and operating expertise in all areas of our geographic focus.

Our oil and natural gas assets are characterized by a combination of conventional and unconventional reserves and prospects. We have conventional reserves and production in four main onshore locations:

Ÿ Electra/Burkburnett, Wichita and Wilbarger Counties, Texas;

Ÿ Boonsville, Jack and Wise Counties, Texas;

Ÿ Vinegarone, Val Verde County, Texas; and

Ÿ Egan, Acadia Parish, Louisiana.

We have unconventional reserves and production in our Barnett Shale play located in Jack and Wise Counties, Texas, where we own interests in approximately 27,700 gross (6,800 net) acres.

In addition, we have positioned ourselves for participation in two emerging resource plays in southwest Texas. We have an exploratory play targeting the Barnett and Woodford Shale formations where we own interests in approximately 84,000 gross (6,600 net) acres. We also have an exploratory play targeting the Wolfcamp formation where we are actively acquiring acreage and have accumulated leases and options covering over 15,000 gross and net acres.

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At December 31, 2005, our estimated net proved reserves were 18.8 MMBoe, of which approximately 60% were crude oil, 30% were natural gas, and 10% were natural gas liquids, or NGLs. The PV-10 Value of our proved reserves was approximately $345.5 million based on prices we were receiving as of December 31, 2005, which were $58.63 per Bbl of oil, $35.89 per Bbl of NGLs and $9.14 per Mcf of natural gas. At December 31, 2005, our proved developed reserves comprised 70% of our total proved reserves, and the estimated reserve life for our total proved reserves was approximately 15 years.

We own interests in approximately 2,900 wells and are the operator of leases upon which approximately 1,900 of these wells are located. The PV-10 Value attributable to our interests in the properties we operate represented approximately 86% of our aggregate PV-10 Value as of December 31, 2005. We also own a drilling rig, various gathering systems, a natural gas processing plant, service rigs and a supply company that service our properties.

From January 1, 1997 through December 31, 2005, our reserve replacement percentage, through discoveries, extensions, revisions and acquisitions, but excluding divestitures, was 344%. Since January 1, 1997, our historical average finding cost from all sources, exclusive of divestitures, has been $6.27 per Boe. During the twelve months ended December 31, 2006, we drilled or participated in the drilling of 92 wells on our oil and natural gas properties, 80 of which were successfully completed as producing wells, four of which were dry holes and eight of which were either drilling or waiting to be completed at the end of that period. For the twelve months ended September 30, 2006 we generated EBITDA of $33.8 million from production averaging 3,740 Boe per day. For more information regarding our EBITDA, including a reconciliation to our net income (loss), see “Selected Consolidated Financial Data.”

Our Business Strategy and Strengths

Our primary objective is to enhance stockholder value by increasing our net asset value, net reserves and cash flow per share through acquisitions, development, exploitation, exploration and divestiture of oil and natural gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures in a combination of lower risk development and exploitation activities and higher potential exploration prospects. We intend to pursue acquisitions during periods of attractive acquisition values and emphasize development of our reserves during periods of higher acquisition values. Key elements of our business strategy include the following:

Ÿ Concentrate on Our Existing Core Areas. We intend to focus a significant portion of our growth efforts in our existing core areas. Our oil and natural gas properties in our core areas are characterized by long reserve lives and production histories in multiple oil and natural gas horizons. We believe our focus on and experience in our core areas may expose us to acquisition opportunities which may not be available to the entire industry.

Ÿ Accelerate Our North Texas Barnett Shale Development. Due to the high degree of commercial success in the north Texas Barnett Shale by the oil and natural gas industry, we plan to use proceeds of this offering to significantly accelerate drilling in our north Texas Barnett Shale properties. We have over 325 potential horizontal well locations on our properties. We have drilled nine gross (3.4 net) wells to date with a 100% success rate on our north Texas Barnett Shale properties and plan on drilling a minimum of four gross (2.1 net) wells to a maximum of seven gross (2.8 net) wells during 2007.

Ÿ Complete Selective Acquisitions and Divestitures. We seek to acquire producing oil and natural gas properties, primarily in our core areas. Our experienced senior management team has developed our acquisition criteria designed to increase reserves, production and cash flow per share on an accretive basis. We will seek acquisitions of producing properties that will provide us with opportunities for

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reserve additions and increased cash flow through operating improvements, production enhancement and additional development and exploratory prospect generation opportunities. In addition, from time to time, we may engage in strategic divestitures when we believe our capital may be redeployed to higher return projects.

Ÿ Develop and Exploit Existing Oil and Natural Gas Properties. We have historically increased stockholder value by fully developing or exploiting our acquired and discovered properties until we determine that it is no longer economically attractive to do so. As of December 31, 2006, we have identified 161 proved development and extension drilling projects and 166 recompletion/workover projects on our existing properties and wells.

Ÿ Increase Emphasis on Exploration Activity. We are committed to increasing our emphasis on exploration activities within the context of our balanced risk objectives. We will continue to acquire, review and analyze 3-D seismic data to generate exploratory prospects. Our exploration efforts utilize available geological and geophysical technologies to reduce our exploration and drilling risks and, therefore, maximize our probability of success.

We believe that the following strengths complement our business strategy:

Ÿ Inventory of Growth Opportunities in the North Texas Barnett Shale. We believe we have a significant inventory of growth opportunities beyond our proved reserve base. We have over 325 potential drilling locations within the north Texas Barnett Shale. We believe that our inventory of potential drilling locations should provide us the opportunity to grow organically for the foreseeable future without having to depend upon acquisitions of properties. Based on current cost estimates, we have approximately $250 million of potential future capital expenditures for the full development of our north Texas Barnett Shale acreage.

Ÿ Management Experience and Technical Expertise. Our key management and technical staff possess an average of 26 years of experience in the oil and natural gas industry, a substantial portion of which has been focused on operations in our core areas. We believe that the knowledge, experience and expertise of our staff will continue to support our efforts to enhance stockholder value.

Ÿ Balanced Oil and Natural Gas Production. At year-end 2005, approximately 60% of our estimated proved reserves were oil, 30% were natural gas and 10% were NGLs. We believe this balanced commodity mix, combined with our prudent use of derivative contracts, will provide sufficient diversification of sources of cash flow and will lessen the risk of significant and sudden decreases in revenue from localized or short-term commodity price movements.

Ÿ Operating Efficiency and Control. We currently operate wells that represent 86% of our aggregate PV-10 Value at December 31, 2005. Our high degree of operating control allows us to control capital allocation and expenses and the timing of additional development and exploitation of our producing properties.

Ÿ Drilling Expertise and Success. Our management and technical staff have a long history of successfully drilling oil and natural gas wells. Through December 31, 2006, we have drilled or participated in the drilling of 561 oil and natural gas wells with a 93% success rate. We expect to continue to grow by utilizing our drilling expertise and developing and finding additional reserves, although our success rate may decline as we drill more exploratory wells.

Ÿ Ownership and Control of Service and Supply Assets. We own and control service and supply assets, including a drilling rig, service rigs, a supply company, gathering systems and other related assets. We believe that ownership and use of these assets for our own account provides us with a significant

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competitive advantage with respect to availability, lead-time and cost of these services. For calendar year 2007, approximately 75% of our projected capital expenditures will be in areas serviced by these assets.

Ÿ Insider Ownership. After giving effect to the completion of this offering, management and insiders will own approximately 54% of our outstanding shares, providing a strong alignment of interest between management, the board of directors and our outside stockholders.

Ÿ Balance Sheet Flexibility. After giving effect to the completion of this offering and application of the net proceeds as described in this prospectus, we will have significant liquidity for pursuing acquisitions, accelerating our development and exploratory activities and taking advantage of opportunities as they arise.

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Principal Producing Properties

The following is a summary of our oil and natural gas reserve information with respect to our principal properties as of December 31, 2005 and with respect to our producing wells, drilling locations and net acreage as of September 30, 2006:

	Electra/ Burkburnett			Boonsville			Egan			Barnett Shale			Vinegarone
Proved reserves (Mboe)		9,802			3,011			1,651			408			1,110
Percent proved developed		61	%		69	%		100	%		83	%		31	%
Percent oil		97	%		6	%		11	%		2	%		—
PV-10 Value (in thousands) (1)	$	182,920		$	43,403		$	38,424		$	10,410		$	21,480
Gross producing wells:
Operated by RAM Energy		503			87			10			2			—
Operated by others		—			1			—			7			7
Proved drilling locations		152			20			—			4			3
Potential unproven drilling locations		—			—			—			325			—
Total net acres		12,190			7,313			3,740			6,800			1,830

(1) The PV-10 Value of our proved reserves as of December 31, 2005 was calculated using unescalated prices of $58.63 per Bbl of oil, $35.89 per Bbl of NGLs, and $9.14 per Mcf of natural gas, which were the prices we were receiving as of December 31, 2005. The prices at which we sell natural gas are determined on the first day of each month for the entire month.

Principal Exploration Projects

The following is a summary of our principal exploration projects as of September 30, 2006, both of which are located in southwest Texas:

Name	Objective	Net Acres
Wolfcamp	Shale Gas	15,000
	Canyon Sands
Barnett/Woodford	Shale Gas	6,600

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Recent Events

Tremisis Merger. Prior to May 8, 2006, our corporate name was Tremisis Energy Acquisition Corporation, or Tremisis. On May 8, 2006, Tremisis acquired RAM Energy, Inc. through the merger of its recently formed, wholly owned subsidiary into RAM Energy, Inc. The merger was accomplished pursuant to the terms of an Agreement and Plan of Merger dated October 20, 2005, as amended, which is referred to as the merger agreement, among Tremisis, its acquisition subsidiary, RAM Energy, Inc. and the stockholders of RAM Energy, Inc. Upon completion of the merger, RAM Energy, Inc. became Tremisis’ wholly owned subsidiary and Tremisis changed its name from Tremisis Energy Acquisition Corporation to RAM Energy Resources, Inc.

Upon consummation of the merger, the stockholders of RAM Energy, Inc. received an aggregate of 25,600,000 shares of Tremisis’ common stock and $30.0 million of cash. Prior to consummation of the merger, and as permitted by the merger agreement, on April 6, 2006, RAM Energy, Inc. redeemed a portion of its outstanding stock for an aggregate consideration of $10.0 million.

The merger was accounted for as a reverse acquisition. RAM Energy, Inc. has been treated as the acquiring company and the continuing reporting entity for accounting purposes. Upon completion of the merger, the assets and liabilities of Tremisis were recorded at their fair value, which is considered to approximate historical cost, and added to those of RAM Energy, Inc. Because Tremisis had no active business operations prior to consummation of the merger, the merger was accounted for as a recapitalization of RAM Energy, Inc.

Acquisition of Properties. Effective September 1, 2006, we acquired 447,000 Boe of proved reserves and associated gathering assets in a field located in close proximity to our existing north Texas properties. Current production from the acquired properties is from the Bend Conglomerate. The acquired properties also included undeveloped deep rights, including the Barnett Shale formation. The purchase price was $4.6 million, or $9.84 per Boe of estimated proved reserves. The proved reserve mix in the acquired properties is 72% natural gas and 28% oil.

Stock Transactions. On September 22, 2006, we repurchased 739,175 shares of our common stock from an unaffiliated party in a negotiated transaction at a purchase price of $4.295 per share. On November 10, 2006, we approved the grant of restricted stock awards under our 2006 Long-Term Incentive Plan for an aggregate of 646,805 shares of our common stock to 22 of our employees, including two of our vice presidents, one of whom received an award of 75,100 shares, and the other who received an award of 69,170 shares. We will incur compensation expense of approximately $3.3 million, which will be recognized ratably through 2011, in connection with our November 10, 2006 restricted stock issuances.

Fourth Quarter Operations. During the fourth quarter of 2006 we drilled or participated in the drilling of 18 gross (18.0 net) development wells, of which 13 net wells are capable of commercial production, and five gross (5.0 net) wells were drilling, testing or in the completion process at year end. Wells drilled during the quarter included 18 gross (18.0 net) wells in our Electra/Burkburnett area. During the fourth quarter of 2006, we participated in the drilling of three gross (2.1 net) exploratory wells, two gross (2.0 net) of which were in our Wolfcamp prospect. All three exploratory wells were in various stages of completion at year end.

Our non-acquisition related capital expenditures during the fourth quarter of 2006 aggregated $6.4 million, of which $3.5 million was allocated to development and exploitation activities, and $2.9 million was allocated to exploration activities. Our total non-acquisition capital expenditures for 2006, were approximately $23.4 million, compared to our 2006 capital expenditure budget of $24.3 million. In addition, we expended $4.6 million in our acquisition of 447,000 Boe of proved reserves in the third quarter of 2006.

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Risks Related to Our Strategy

Prospective investors should carefully consider the matters we discuss under the caption “Risk Factors,” as well as the other information in this prospectus, including that the market for attractive opportunities to acquire properties with proved undeveloped reserves may not be available; our reserve estimates may not be accurate; our results will be affected by the volatile nature of oil and natural gas prices and we may experience delays in obtaining drilling rigs and shortages of equipment. One or more of these matters could negatively affect our ability to successfully implement our business strategy.

Our Executive Offices

Our principal executive offices are located at 5100 East Skelly Drive, Suite 650, Tulsa, Oklahoma 74135. Our telephone number is (918) 663-2800.

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The Offering

Common stock offered by us 9,074,411 Shares

Common stock offered by selling stockholder (1) 2,722,323 Shares

Option We have granted the underwriters a 30-day option to purchase up to an aggregate of 1,769,510 additional shares of common stock.

Common stock outstanding after the offering (2) 42,513,941 Shares

Use of Proceeds We intend to use the net proceeds from this offering primarily to repay indebtedness outstanding under our 11 ¹/2% senior notes and our senior credit facility and to provide additional working capital for general corporate purposes, including acquisition, development, exploitation and exploration of oil and natural gas properties.

Nasdaq Capital Market symbol RAME

(1) The selling stockholder is Danish Knights, A Limited Partnership, which is a family limited partnership formed by Dr. William W. Talley II, a founder and former chairman of RAM Energy, Inc. Dr. Talley passed away in 2005. No partner of Danish Knights is a director or officer of RAM Energy Resources, Inc.

(2) The shares of common stock outstanding after this offering do not include approximately 12,650,000 shares issuable upon the exercise of outstanding warrants at an exercise price of $5.00 per share and 825,000 shares of our common stock issuable upon the exercise of currently exercisable options to purchase 275,000 units at an exercise price of $9.90 per unit, each unit consisting of one share of our common stock and two warrants, each warrant to purchase one share of our common stock at an exercise price of $6.25 per share. Such warrants, when issued, will be immediately exercisable. The shares of common stock to be outstanding after this offering do not include shares of our common stock that we will issue upon the exercise of options or other awards that may be granted under our 2006 Long-Term Incentive Plan. We have remaining a maximum of 1,423,195 shares of common stock reserved for issuance upon the exercise of options that may be granted and pursuant to awards that may be made under our 2006 Long-Term Incentive Plan. In addition, the shares of common stock to be outstanding after this offering do not include shares of our common stock which may be issued to the underwriter pursuant to its over-allotment option.

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SUMMARY CONSOLIDATED FINANCIAL INFORMATION AND OTHER DATA

We are providing the following summary consolidated financial information and other data to assist you in your analysis of our financial condition and results of operations. We acquired RAM Energy effective May 8, 2006, by the merger of our recently formed, wholly owned subsidiary with and into RAM Energy, which transaction we refer to as the merger. See “Prospectus Summary—Recent Events” for a discussion of the merger. For accounting and financial reporting purposes, the merger was accounted for under the purchase method of accounting as a reverse acquisition and, in substance, as a capital transaction, because Tremisis had no active business operations prior to consummation of the merger. Accordingly, for accounting and financial reporting purposes, the merger was treated as the equivalent of RAM Energy issuing stock for the net monetary assets of Tremisis, accompanied by a recapitalization. The net monetary assets of Tremisis have been stated at their fair value, essentially equivalent to historical costs, with no goodwill or other intangible assets recorded. The accumulated deficit of RAM Energy has been carried forward. Operations prior to the merger are those of RAM Energy.

The consolidated balance sheet data as of December 31, 2004 and 2005 and the consolidated statement of operations data for the years ended December 31, 2003, 2004 and 2005 are derived from RAM Energy’s consolidated financial statements audited by UHY Mann Frankfort Stein & Lipp CPAs, LLP, independent registered public accountants, and are included elsewhere in this prospectus. The consolidated balance sheet data as of December 31, 2003 and the consolidated statement of operations data for the year ended December 31, 2002 are derived from RAM Energy’s consolidated financial statements audited by UHY Mann Frankfort Stein & Lipp CPAs, LLP, independent registered public accountants, which are not included in this prospectus. The consolidated balance sheet data of RAM Energy as of December 31, 2001 and 2002 and the consolidated statement of operations data for the year ended December 31, 2001 are derived from RAM Energy’s unaudited consolidated financial statements, which are not included in this prospectus.

The summary consolidated financial information and other data presented below is only a summary and should be read in conjunction with the historical consolidated financial statements of each of RAM Energy and Tremisis, and the related notes, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business and Properties.” The historical results included below and elsewhere in this prospectus may not be indicative of our future performance. RAM Energy’s financial position and results of operations for 2003, 2004 and 2005 may not be comparative to other periods as a result of certain divestitures and acquisitions, as more fully described in RAM Energy’s financial statements included elsewhere in this prospectus.

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Summary Consolidated Financial Information

(in thousands)

	Year Ended December 31,															Nine Months Ended September 30,
Statement of Operations Data	2001			2002			2003			2004			2005 (1)			2005 (1)			2006 (1)
																(unaudited)
Oil and natural gas sales	$	25,404		$	10,166		$	20,053		$	17,975		$	66,243		$	48,140		$	53,050
Production taxes		2,755			1,044			1,408			1,263			3,320			2,460			2,527
Production expenses		5,975			3,023			3,527			3,600			16,099			11,453			13,222
General and administrative expenses		4,061			5,858			6,331			6,601			8,610			6,285			6,351
Depreciation and amortization		9,766			2,947			4,098			3,273			12,972			9,213			10,019
Interest expense		(14,410	)		(8,963	)		(4,871	)		(5,035	)		(12,539	)		(8,728	)		(12,975	)
Operating income (loss)		4,839			(2,689	)		4,608			14,844			13,888			2,882			19,889
Income (loss) from continuing operations		3,751			13,256			(491	)		6,076			543			(3,624	)		3,990
Statement of Cash Flow Data
Cash provided by (used in):
Operating activities	$	2,240		$	(14,842	)	$	5,774		$	1,793		$	18,359		$	10,616		$	25,294
Investing activities		44,520			(46	)		7,422			(64,852	)		(12,554	)		(9,877	)		(18,710	)
Financing activities		(27,803	)		(3,731	)		(12,333	)		62,116			(6,910	)		(161	)		938
Other Data
Capital expenditures (2)	$	11,349		$	6,700		$	5,258		$	102,719		$	13,526		$	11,078		$	21,529
EBITDA (3)		14,709			473			8,670			18,153			33,747			27,208			26,888
	As of December 31,															As of September 30,
Balance Sheet Data	2001			2002			2003			2004			2005 (1)			2005 (1)			2006 (1)
																(unaudited)
Total assets	$	98,322		$	62,192		$	45,908		$	140,324		$	143,276		$	140,708		$	158,157
Total debt		91,400			56,267			46,057			117,344			112,846			117,301			131,696
Stockholders’ deficit		(20,347	)		(16,842	)		(19,653	)		(19,912	)		(20,769	)		(24,436	)		(29,043	)

(1) We acquired WG Energy Holdings, Inc. in December 2004.

(2) Includes costs of acquisitions.

(3) EBITDA for the twelve months ended September 30, 2006 was $33.8 million. For more information regarding our EBITDA, including a reconciliation to our net income (loss), see “Selected Consolidated Financial Data.”

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Summary Reserve Data

	As of December 31,
	2003			2004			2005
Proved reserves:
Oil (MBbls)		2,322			10,667			11,199
Natural gas (MMcf)		34,567			38,195			34,234
Natural gas liquids (MBbls)		—			2,087			1,891
Total (MBoe)		8,083			19,120			18,796
Percent proved developed		80.7	%		67.9	%		70.2	%
Percent oil		28.7	%		55.8	%		59.6	%
Estimated future net revenues before income taxes (in thousands)	$	160,456		$	434,028		$	601,111
PV-10 Value (in thousands)	$	104,570		$	236,201		$	345,501
Prices used to calculate PV-10 Value:
Oil (per Bbl)	$	29.25		$	40.25		$	58.63
Natural gas (per Mcf)		6.17			6.02			9.14
Natural gas liquids (per Bbl)		—			27.56			35.89

Summary Operating Data

The following tables present certain information with respect to oil and natural gas production, prices and costs attributable to our oil and natural gas properties for the three years ended December 31, 2005 and the nine months ended September 30, 2006. We acquired WG Energy in December 2004. Our operating data for 2004 includes operations of WG Energy from the date of acquisition.

	Year ended December 31,						Nine months Ended September 30, 2006
	2003		2004		2005
Production volumes:
Oil (MBbls)		277		178		787		592
Natural gas liquids (MBbls)		5		12		170		103
Natural gas (MMcf)		2,334		1,928		2,681		1,761
Total (MBoe)		671		511		1,405		989
Average realized prices (after effect of derivative contracts):
Oil (per Bbl)	$	29.47	$	33.15	$	52.35	$	57.46
Natural gas liquids (per Bbl)		16.94		26.41		36.33		41.89
Natural gas (Per Mcf)		5.06		5.73		5.57		6.12
Per Boe		29.89		33.77		44.38		49.68
Expenses (per Boe):
Oil and natural gas production taxes	$	2.10	$	2.47	$	2.36	$	2.56
Oil and natural gas production expenses		5.26		7.04		11.46		13.38
Amortization of full cost pool		5.64		5.89		8.93		9.63
General and administrative		9.44		12.90		6.13		6.42

11

RISK FACTORS

You should carefully consider the following risk factors, together with all of the other information included in this prospectus.

The volatility of oil and natural gas prices greatly affects our profitability.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write-downs of the carrying values of our oil and natural gas properties as a result of our use of the full cost accounting method.

Wide fluctuations in oil and natural gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond our control, including:

Ÿ worldwide and domestic supplies of oil and natural gas;

Ÿ weather conditions;

Ÿ the level of consumer demand;

Ÿ the price and availability of alternative fuels;

Ÿ the availability of drilling rigs and completion equipment;

Ÿ the availability of pipeline capacity;

Ÿ the price and volume of foreign imports;

Ÿ domestic and foreign governmental regulations and taxes;

Ÿ the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

Ÿ political instability or armed conflict in oil-producing regions; and

Ÿ the overall economic environment.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves.

Our success depends on acquiring or finding additional reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are produced, except to the extent that we conduct successful exploration or development activities or acquire

12

properties containing proved reserves, or both. To increase reserves and production, we must commence exploratory drilling, undertake other replacement activities or utilize third parties to accomplish these activities. There can be no assurance, however, that we will have sufficient resources to undertake these actions, that our exploratory projects or other replacement activities will result in significant additional reserves or that we will succeed in drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

In accordance with customary industry practice, we rely in part on independent third party service providers to provide most of the services necessary to drill new wells, including drilling rigs and related equipment and services, horizontal drilling equipment and services, trucking services, tubular goods, fracing and completion services and production equipment. The oil and natural gas industry has experienced significant volatility in cost for these services in recent years and this trend is expected to continue into the future. Any future cost increases could significantly increase our development costs and decrease the return possible from drilling and development activities, and possibly render the development of certain proved undeveloped reserves uneconomical.

Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures, including many factors beyond our control. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

We expect to obtain a substantial portion of our funds for the drilling and development of our oil and natural gas properties through borrowings. If such funds were not available to us, or if the terms upon which such funds would be available to us were unfavorable, the further development of our oil and natural gas reserves, and our financial condition and results of operations, could be adversely affected.

We expect to fund a substantial portion of our future leasehold acquisitions and our drilling and development operations with borrowed funds. To the extent such funds are not available to us at all, or if the terms under which such funds would be available to us would be unfavorable, the further development of our oil and natural gas reserves could be adversely impacted and we could be limited as to the amount of additional leasehold acreage we could acquire. In such events, we may be unable to replace our reserves of oil and natural gas which, subsequently, could adversely affect our financial condition and results of operations.

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Operating hazards and uninsured risks may result in substantial losses.

Our operations are subject to all of the hazards and operating risks inherent in drilling for, and the production of, oil and natural gas, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks. There can be no assurance that any insurance will be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase. In addition, we may be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities would not be covered by our insurance.

Several of our subsidiaries are defendants in a pending class action suit alleging the underpayment of oil and natural gas royalties. If our subsidiaries were ultimately determined to be liable, the amount of the judgment could adversely affect our financial condition.

Several of our subsidiaries are named defendants in a pending class action suit in which the plaintiffs are seeking monetary damages for our alleged underpayment of oil and natural gas royalties. The plaintiffs seek unspecified damages for alleged breach of contract, alleged tortious breach of implied covenants and alleged breach of fiduciary duty, together with punitive damages and other equitable relief. The aggregate dollar amount of the damages sought by the plaintiffs has not yet been calculated. If the amount of any damages ultimately awarded to the plaintiffs were material, it could adversely affect our financial condition. For a further discussion of this litigation, please see “Business and Properties—Legal Proceedings” appearing elsewhere in this prospectus.

Our operations are subject to various governmental regulations that require compliance that can be burdensome and expensive.

Our operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge from drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. These laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management, and compliance with these laws may cause delays in the additional drilling and development of our properties. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. While historically we have not experienced any material adverse effect from regulatory delays, there can be no assurance that such delays will not occur in the future.

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Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value, which could affect our stockholder equity and net profit or loss.

We use the full cost method of accounting for our investment in oil and natural gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves are capitalized into a “full cost pool.” Capitalized costs in the pool are amortized and charged to operations using the units-of-production method based on the ratio of current production to total proved oil and natural gas reserves. To the extent that such capitalized costs, net of amortization, exceed the present value of our proved oil and natural gas reserves (using a 10% discount rate) at any reporting date, such excess costs are charged to operations. Although we have never incurred a write down of the value of oil and natural gas properties, if a writedown is incurred, it is not reversible at a later date, even if the present value of our proved oil and natural gas reserves increases as a result of an increase in oil or natural gas prices.

Properties that we acquire may not produce as projected, and we may be unable to identify liabilities associated with the properties or obtain protection from sellers against them.

As part of our business strategy, we continually seek acquisitions of oil and natural gas properties. Our most recent significant acquisition, which closed in December 2004, was our purchase of WG Energy Holdings, Inc. The successful acquisition of oil and natural gas properties requires assessment of many factors, which are inherently inexact and may be inaccurate, including the following:

Ÿ future oil and natural gas prices;

Ÿ the amount of recoverable reserves;

Ÿ future operating costs;

Ÿ future development costs;

Ÿ failure of titles to properties;

Ÿ costs and timing of plugging and abandoning wells; and

Ÿ potential environmental and other liabilities.

Our assessment will not necessarily reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. With respect to properties on which there is current production, we may not inspect every well location, every potential well location, or pipeline in the course of our due diligence. Inspections may not reveal structural and environmental problems such as pipeline corrosion or groundwater contamination. We may not be able to obtain or recover on contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We face extensive competition in our industry.

We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies, many of whom have financial and other resources substantially in excess of those available to us. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation.

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Risk Related to Our Common Stock

Purchasers in this offering will experience immediate and substantial dilution in the book value of their investment.

Purchasers of our common stock in this offering will experience an immediate, substantial dilution of $5.19 per share of common stock (based on an assumed offering price of $5.51, the last sale price of our common stock as reported on The Nasdaq Capital Market on December 29, 2006) because the price per share of common stock in this offering is substantially higher than the net tangible book value of each share of common stock outstanding immediately after this offering. Our net tangible book value as of September 30, 2006 on a pro forma basis after giving effect to this offering and the application of proceeds from such offering is approximately $13.6 million, or $0.32 per share of common stock. In addition, purchasers may experience further dilution from issuances of shares of our common stock in the future. See “Dilution.”

We do not currently pay dividends on our common stock and do not anticipate doing so in the future.

Prior to consummation of the merger, RAM Energy regularly paid cash dividends to its stockholders. We intend to retain any future earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future.

A substantial number of shares of our common stock will be available for sale in the future, which may increase the volume of common stock available for sale in the open market and may cause a decline in the market price of our common stock.

Sales of a substantial number of shares of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. We issued 25,600,000 shares of our common stock in connection with our acquisition of RAM Energy. These shares were not registered under the Securities Act of 1933, and their resale is restricted. All of such shares are subject to a lock-up agreement and cannot be sold publicly until the expiration of the restricted periods set out in the lock-up agreement (a maximum of one year after May 8, 2006) and under Rule 144 promulgated under the Securities Act of 1933. However, the holders of such shares have certain registration rights and will be able to sell their shares in the public market prior to such times if registration is effected. The presence of this additional number of shares of common stock eligible for trading in the public market may have an adverse effect on the market price of our common stock.

Voting control by our executive officers, directors and other affiliates may limit your ability to influence the outcome of director elections and other matters requiring stockholder approval.

Persons who beneficially own approximately 80% (57% after giving effect to the completion of this offering) of our outstanding common stock are parties to a voting agreement. These persons have agreed to vote for each other’s designees to our board of directors through director elections in 2008. Accordingly, they will be able to control the election of directors and, therefore, our policies and direction during the term of the voting agreement. This concentration of voting power could have the effect of delaying or preventing a change in our control or discouraging a potential acquirer from attempting to obtain control of us, which in turn could have a material adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the market price for their shares of common stock.

You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock, which could have an adverse effect on our stock price.

We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders and purchasers of common stock offered hereby. We

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are currently authorized to issue 100.0 million shares of common stock and one million shares of preferred stock with such designations, preferences and rights as determined by our board of directors. As of the date of this prospectus, we had outstanding 33,439,530 shares of common stock, warrants to purchase 12,650,000 shares of our common stock and an agreement to issue 825,000 shares of our common stock upon the exercise of currently exercisable options to purchase 275,000 units, each unit consisting of one share of common stock and two warrants, each warrant to purchase one share of our common stock. These warrants when issued will be immediately exercisable. In addition, we have reserved an additional 1,423,195 shares for future issuance to employees as restricted stock or stock option awards pursuant to our 2006 Long-Term Incentive Plan. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future issuances of our securities for capital raising purposes or for other business purposes. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.

Certain provisions of Delaware law, our certificate of incorporation and bylaws could hinder, delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

Certain provisions of Delaware law, our certificate of incorporation and bylaws could have the effect of discouraging, delaying or preventing transactions that involve an actual or threatened change in control of our company. Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. In addition, our certificate of incorporation and bylaws include the following provisions:

Ÿ Classified Board of Directors. Our board of directors is divided into three classes with staggered terms of office of three years each. The classification and staggered terms of office of our directors make it more difficult for a third party to gain control of our board of directors. At least two annual meetings of stockholders, instead of one, generally would be required to effect a change in a majority of the board of directors.

Ÿ Removal of Directors. Under Delaware law, directors that serve on a classified board, such as our directors, may be removed only for cause by the affirmative vote of the holders of at least a majority of the voting power of the outstanding shares of our capital stock.

Ÿ Number of Directors, Board Vacancies, Term of Office. Our certificate of incorporation and our bylaws provide that only the board of directors may set the number of directors. We have elected to be subject to certain provisions of Delaware law which vest in the board of directors the exclusive right, by the affirmative vote of a majority of the remaining directors, to fill vacancies on the board even if the remaining directors do not constitute a quorum. When effective, these provisions of Delaware law, which are applicable even if other provisions of Delaware law or the charter or bylaws provide to the contrary, also provide that any director elected to fill a vacancy shall hold office for the remainder of the full term of the class of directors in which the vacancy occurred, rather than the next annual meeting of stockholders as would otherwise be the case, and until his or her successor is elected and qualifies.

Ÿ Advance Notice Provisions for Stockholder Nominations and Proposals. Our bylaws require advance written notice for stockholders to nominate persons for election as directors at, or to bring other business before, any meeting of stockholders. This bylaw provision limits the ability of stockholders to make nominations of persons for election as directors or to introduce other proposals unless we are notified in a timely manner prior to the meeting.

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Ÿ Amending the Bylaws. Our certificate of incorporation permits our board of directors to adopt, alter or repeal any provision of the bylaws or to make new bylaws. Our certificate of incorporation also provides that our bylaws may be amended by the affirmative vote of the holders of at least 80% of the voting power of the outstanding shares of our capital stock.

Ÿ Authorized but Unissued Shares. Under our certificate of incorporation, our board of directors has authority to cause the issuance of preferred stock from time to time in one or more series and to establish the terms, preferences and rights of any such series of preferred stock, all without approval of our stockholders. Nothing in our certificate of incorporation precludes future issuances without stockholder approval of the authorized but unissued shares of our common stock.

We could issue additional preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover effects.

We are authorized to issue up to one million shares of preferred stock, which shares may be issued from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions thereof, if any, of each such series of our preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of the our certificate of incorporation and Delaware law, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series of our preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock.

In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving our control by the current stockholders.

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USE OF PROCEEDS

We estimate that our net proceeds from the sale of the shares of common stock that we are offering will be approximately $46.0 million. If the underwriters fully exercise the over-allotment option, the net proceeds of the shares we sell will be approximately $55.1 million. Net proceeds are what we expect to receive after paying the underwriting discounts and the other estimated expenses of this offering. For the purpose of estimating net proceeds, we are assuming that the offering price will be $5.51 per share, which is the closing price of our common stock on the Nasdaq Capital Market on December 29, 2006. We will not receive any proceeds from the sale of shares by the selling stockholder.

We intend to use the net proceeds of this offering to repurchase all of our outstanding 11 ¹/2% senior notes ($28.4 million principal amount plus a $1.1 million charge related to a prepayment premium) and to reduce the outstanding balance under our revolving credit facility ($13.0 million outstanding at December 31, 2006). The remainder of the net proceeds of this offering will be used for working capital and other corporate purposes. We expect to repurchase our 11 ¹/2% senior notes on or after February 15, 2007 at 103.84% of the stated principal amount.

The following table illustrates our expected use of the net proceeds of this offering (in millions). To the extent the several underwriters exercise their over-allotment option, the proceeds derived from those exercises will be added to our working capital and used for general corporate purposes:

Repurchase of 11 ½% senior notes	$	29.5
Repayment of existing revolving credit facility		13.0
General corporate purposes		4.1
Total	$	46.0

Our revolving credit facility matures in 2010 and our term facility matures in 2011. At December 31, 2006, the interest rate on borrowings outstanding under our revolving credit facility was 7.4% per annum and under our term facility was 11.1% per annum. Borrowings under our credit facility have been used primarily for acquisition and development of our oil and natural gas properties, working capital and general corporate purposes. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for additional information about our credit facility and our 11 ¹/2% senior notes.

Until we use the proceeds from this offering, we will invest the funds in short-term, investment grade, interest-bearing securities.

DIVIDEND POLICY

Prior to the consummation of the merger, RAM Energy regularly paid cash dividends to its stockholders. We have paid no dividends since the date of the merger. We currently intend to retain all of our earnings to finance our operations, repay indebtedness and fund our future growth. We do not expect to pay any dividends on our common stock for the foreseeable future. In addition, covenants contained in the instruments governing our credit facility limit our ability to pay dividends on our common stock. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources.”

DILUTION

The net tangible book value of our issued and outstanding common stock at September 30, 2006, was $(32.4) million, or $(0.99) per share, based on the number of shares of our common stock outstanding at

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September 30, 2006. After giving effect, as of that date, to our sale of 9,074,411 shares of common stock at an estimated price of $5.51 per share and the receipt by us of approximately $46.0 million in net proceeds from this offering, the pro forma net tangible book value would have been $13.6 million, or $0.32 per share of common stock. This amount represents an immediate increase in net tangible book value per share of $1.31 to existing stockholders and immediate dilution of $5.19 in net tangible book value per share to persons purchasing shares of common stock at an estimated price of $5.51 per share. The following table illustrates this dilution on a per share basis:

Estimated per share offering price	$	5.51
Net tangible book value per share at September 30, 2006 (1)	$	(0.99	)
Increase attributable to sale of shares of common stock (2)	$	1.31
Pro forma net tangible book value per share after the offering (2)	$	0.32
Dilution in net tangible book value per share to new investors (2) (3)	$	5.19

(1) Net tangible book value per share of common stock is determined by dividing our tangible net worth (total tangible assets ($154.8 million) less total liabilities ($187.2 million)) by the number of shares of common stock outstanding.

(2) After deducting estimated expenses of this offering payable by us.

(3) Dilution is determined by subtracting net tangible book value per share of common stock after the offering from the offering price per share.

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CAPITALIZATION

The following table shows our capitalization on September 30, 2006 and our capitalization on September 30, 2006, as adjusted to give effect to the completion of this offering at an assumed offering price of $5.51 per share and the use of the net proceeds as described under “Use of Proceeds.”

	Actual			As Adjusted
	(in thousands)
Cash and cash equivalents	$	7,592		$	11,106
Current portion of long-term debt	$	194		$	194
Long-term debt, less current portion	$	131,502		$	90,106
Stockholders’ equity (deficit):
Preferred stock, $0.0001 par value, 1,000,000 shares authorized; no shares issued or outstanding	$	—		$	—
Common stock, $0.0001 par value, 100,000,000 shares authorized; 32,792,725 shares issued and outstanding, actual; 41,867,136 shares issued and outstanding, as adjusted		3			4
Additional paid-in capital		2,218			48,217
Treasury stock		(3,768	)		(3,768	)
Accumulated deficit		(27,496	)		(28,530	)
Total stockholders’ equity (deficit)	$	(29,043	)	$	15,923
Total capitalization	$	102,459		$	106,029

The shares of common stock issued and outstanding do not include approximately 12,650,000 shares reserved for issuance upon the exercise of outstanding warrants and 825,000 shares of our common stock issuable upon the exercise of currently exercisable options to purchase 275,000 units, each unit consisting of one share of our common stock and warrants to purchase two shares of our common stock; an aggregate of 1,423,195 shares remaining reserved for issuance upon the exercise of options that may be granted by us or awards that may be made under our 2006 Long-Term Incentive Plan; 646,805 shares of common stock issued as restricted stock awards on November 10, 2006 under our 2006 Long-Term Incentive Plan; and a maximum of 1,769,510 shares issuable to the underwriters upon exercise of their over-allotment option.

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SELECTED CONSOLIDATED FINANCIAL DATA

We are providing the following selected financial information to assist you in your analysis of our financial condition and results of operations. We acquired RAM Energy effective May 8, 2006, by the merger of our recently formed, wholly owned subsidiary with and into RAM Energy. See “Prospectus Summary—Recent Events” for a description of the merger. For accounting and financial reporting purposes, the merger was accounted for under the purchase method of accounting as a reverse acquisition and, in substance, as a capital transaction, because Tremisis had no active business operations prior to consummation of the merger. Accordingly, for accounting and financial reporting purposes, the merger was treated as the equivalent of RAM Energy issuing stock for the net monetary assets of Tremisis accompanied by a recapitalization. The net monetary assets of Tremisis have been stated at their fair value, essentially equivalent to historical costs, with no goodwill or other intangible assets recorded. The accumulated deficit of RAM Energy has been carried forward. Operations prior to the merger are those of RAM Energy.

Our consolidated balance sheet data as of December 31, 2004 and 2005 and our consolidated statement of operations data for the years ended December 31, 2003, 2004 and 2005 are derived from RAM Energy’s consolidated financial statements audited by UHY Mann Frankfort Stein & Lipp CPAs, LLP, independent registered public accountants, and are included elsewhere in this prospectus. The consolidated balance sheet data as of December 31, 2003 and the consolidated statement of operations data for the year ended December 31, 2002 are derived from RAM Energy’s consolidated financial statements audited by UHY Mann Frankfort Stein & Lipp CPAs, LLP, independent registered public accountants, which are not included in this prospectus. The consolidated balance sheet data of RAM Energy as of December 31, 2001 and 2002 and the consolidated statement of operations data for the year ended December 31, 2001 are derived from RAM Energy’s unaudited consolidated financial statements, which are not included in this prospectus.

The selected consolidated financial information presented below should be read in conjunction with the historical consolidated financial statements of each of RAM Energy and Tremisis and the related notes, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained elsewhere in this prospectus. The historical results included below and elsewhere in this prospectus may not be indicative of our future performance. RAM Energy’s financial position and results of operations for 2003, 2004 and 2005 may not be comparative to other periods as a result of certain divestitures and acquisitions, as more fully described in RAM Energy’s financial statements included elsewhere in this prospectus.

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Selected Consolidated Financial Data

(in thousands, except share data)

	Year Ended December 31,															Nine Months Ended September 30,
	2001			2002			2003			2004			2005 (1)			2005 (1)			2006 (1)
																(unaudited)
Revenues and Other Operating Income:
Oil and natural gas sales	$	25,404		$	10,166		$	20,053		$	17,975		$	66,243		$	48,140		$	53,050
Pipeline system		15,602			—			—			—			—			—			—
Gain on sale of subsidiary		—			—			—			12,139			—			—			—
Other		210			163			170			338			851			983			466
Realized and unrealized gains (losses) from derivatives		—			(146	)		(203	)		(793	)		(11,695	)		(16,613	)		1,108
Total revenues and other operating income		41,216			10,183			20,020			29,659			55,399			32,510			54,624
Operating Expenses:
Oil and natural gas production taxes		2,755			1,044			1,408			1,263			3,320			2,460			2,527
Oil and natural gas production expenses		5,975			3,023			3,527			3,600			16,099			11,453			13,222
Pipeline purchases		12,227			—			—			—			—			—			—
Pipeline operations		489			—			—			—			—			—			—
Depreciation and amortization		9,766			2,947			4,098			3,273			12,972			9,213			10,019
Accretion expense		—			—			48			78			510			217			398
Contract termination and severance payments		1,104			—			—			—			—			—			—
Share-based compensation		—			—			—			—			—			—			2,218
General and administrative, net of operator’s overhead fees		4,061			5,858			6,331			6,601			8,610			6,285			6,351
Total operating expenses		36,377			12,872			15,412			14,815			41,511			29,628			34,735
Operating income (loss)		4,839			(2,689	)		4,608			14,844			13,888			2,882			19,889
Other Income (Expense):
Gain on early extinguishment of debt		—			32,883			—			—			—			—			—
Gain on sale of oil and natural gas properties		17,320			—			—			—			—			—			—
Interest expense		(14,514	)		(9,240	)		(4,912	)		(5,070	)		(12,614	)		(8,769	)		(13,213	)
Interest income		104			277			41			35			75			41			238
Income (Loss) from Continuing Operations Before Income Taxes and Extraordinary Item		7,749			21,231			(263	)		9,809			1,349			(5,846	)		6,914
Income Tax Provision (Benefit)		2,900			7,975			228			3,733			806			(2,222	)		2,924
Income (Loss) from Continuing Operations Before Extraordinary Item		4,849			13,256			(491	)		6,076			543			(3,624	)		3,990
Extraordinary loss on acquisition of debt, net of income tax benefit of $674		(1,098	)		—			—			—			—			—			—
Income (Loss) from Continuing Operations		3,751			13,256			(491	)		6,076			543			(3,624	)		3,990

23

Selected Consolidated Financial Data (continued)

(in thousands, except share data)

	Year Ended December 31,															Nine Months Ended September 30,
	2001			2002			2003			2004			2005 (1)			2005 (1)			2006 (1)
																(unaudited)
Discontinued operations:
Loss from discontinued operations		—			(18,016	)		(1,723	)		—			—			—			—
Income tax benefit		—			(6,846	)		(655	)		—			—			—			—
Loss from discontinued operations		—			(11,170	)		(1,068	)		—			—			—			—
Income (loss) before cumulative effect of change in accounting principle		3,751			2,086			(1,559	)		6,076			543			(3,624	)		3,990
Cumulative effect of change in accounting principle (net of tax benefit of $275)		—			—			(448	)		—			—			—			—
Net income (loss)	$	3,751		$	2,086		$	(2,007	)	$	6,076		$	543		$	(3,624	)	$	3,990
Net income (loss) per share attributable to common stockholders — basic
Income (loss) from continuing operations before extraordinary item	$	1.78		$	4,861.01		$	(180.05	)	$	2,383.67		$	238.94		$	(0.47	)	$	0.19
Extraordinary loss		(0.40	)		—			—			—			—			—			—
Loss from discontinued operations		—			(4,096.08	)		(391.64	)		—			—			—			—
Cumulative effect of change in accounting principle		—			—			(164.28	)		—			—			—			—
Net income (loss) per share	$	1.38		$	764.93		$	(735.97	)	$	2,383.67		$	238.94		$	(0.47	)	$	0.19
Cash dividends per share	$	—		$	—		$	294.83		$	470.77		$	615.93		$	0.12		$	0.02
Earnings (loss) per share:
Basic	$	1.38		$	764.93		$	(735.97	)	$	2,383.67		$	238.94		$	(0.47	)	$	0.19
Diluted		1.38			764.93			(735.97	)		2,299.77			230.72			(0.47	)		0.18
Weighted average shares outstanding:
Basic		2,727,000			2,727			2,727			2,549			2,273			7,700,000			21,501,633
Diluted		2,727,000			2,727			2,727			2,642			2,354			7,700,000			21,105,987
Statement of Cash Flow Data
Cash provided by (used in):
Operating activities	$	2,240		$	(14,842	)	$	5,774		$	1,793		$	18,359		$	10,616		$	25,294
Investing activities		44,520			(46	)		7,422			(64,852	)		(12,554	)		(9,877	)		(18,710	)
Financing activities		(27,803	)		(3,731	)		(12,333	)		62,116			(6,910	)		(161	)		938
Other Data
Capital expenditures (2)	$	11,349		$	6,700		$	5,258		$	102,719		$	13,526		$	11,078		$	21,529
EBITDA		14,709			473			8,670			18,153			33,747			27,208			26,888

	As of December 31,															As of September 30, 2006 (1)
	2001			2002			2003			2004			2005 (1)
																(unaudited)
Balance Sheet Data
Total assets	$	98,322		$	62,192		$	45,908		$	140,324		$	143,276		$	158,157
Long-term debt, including current portion		91,400			56,267			46,057			117,344			112,846			131,696
Stockholders’ deficit		(20,347	)		(16,842	)		(19,653	)		(19,912	)		(20,769	)		(29,043	)

(1) We acquired WG Energy Holdings, Inc., in December 2004.

(2) Includes costs of acquisitions.

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Our EBITDA is determined by adding the following to net income (loss): interest expense, amortization, depreciation, accretion, income taxes, gain on early extinguishment of debt, gain on sale of oil and natural gas properties, share-based compensation, extraordinary gains (losses), the cumulative effect of changes in accounting principles and unrealized gains (losses) on derivatives. The table below reconciles EBITDA to net income (loss).

We present EBITDA because we believe that it provides useful information regarding our continuing operating results. We rely on EBITDA as a primary measure to review and assess our operating performance with corresponding periods, and as an assessment of our overall liquidity and our ability to meet our debt service obligations.

We believe that EBITDA is useful to investors to provide disclosure of our operating results on the same basis as that used by our management. We also believe that this measure can assist investors in comparing our performance to that of other companies on a consistent basis without regard to certain items that do not directly affect our ongoing operating performance or cash flows. EBITDA, which is not a financial measure under generally accepted accounting principles, or GAAP, has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for net income, cash flows from operating activities and other consolidated income or cash flows statement data prepared in accordance with GAAP. Because of these limitations, EBITDA should neither be considered as a measure of discretionary cash available to us to invest in the growth of our business, nor as a replacement for net income. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA as supplemental information.

	Year ended December 31,														Nine Months Ended September 30,
	2001			2002			2003			2004			2005		2005			2006
															(unaudited)
	(in thousands)
Reconciliation of EBITDA to net income (loss):
Net income (loss)	$	3,751		$	2,086		$	(2,007	)	$	6,076		$	543	$	(3,624	)	$	3,990
Plus: Interest expense		14,514			9,240			4,912			5,070			12,614		8,769			13,213
Plus: Amortization and depreciation expense		9,766			2,947			4,098			3,273			12,972		9,213			10,019
Plus: Accretion expense		—			—			48			78			510		217			398
Plus: Income tax expense (benefit)		2,900			7,975			228			3,733			806		(2,222	)		2,924
Less: Gain on early extinguishment of debt		—			(32,883	)		—			—			—		—			—
Less: Gain on sale of oil and natural gas properties		(17,320	)		—			—			—			—		—			—
Plus: Share-based compensation		—			—			—			—			—		—			2,218
Plus: Extraordinary (gain) loss		1,098			—			—			—			—		—			—
Plus: Loss from discontinued operations, net of tax		—			11,170			1,068			—			—		—			—
Less: Cumulative effect of change in accounting principle		—			—			448			—			—		—			—
Plus: Unrealized (gain) loss on derivatives		—			(62	)		(125	)		(77	)		6,302		14,855			(5,874	)
EBITDA	$	14,709		$	473		$	8,670		$	18,153		$	33,747	$	27,208		$	26,888

25

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

General

We are an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of oil and natural gas properties, primarily in Texas, Louisiana and Oklahoma. Through our RAM Energy subsidiary, we have been active in these core areas since 1987. Our management team has extensive technical and operating expertise in all areas of our geographic focus.

Prior to May 8, 2006, our corporate name was Tremisis Energy Acquisition Corporation. On May 8, 2006, we acquired RAM Energy through the merger of our recently formed, wholly owned subsidiary into RAM Energy. The merger was accomplished pursuant to the terms of an Agreement and Plan of Merger dated October 20, 2005, as amended, which we refer to as the merger agreement, among us, our acquisition subsidiary, RAM Energy and the stockholders of RAM Energy. Upon completion of the merger, RAM Energy became our wholly owned subsidiary and we changed our name from Tremisis Energy Acquisition Corporation to RAM Energy Resources, Inc.

Upon consummation of the merger, the stockholders of RAM Energy received an aggregate of 25,600,000 shares of our common stock and $30.0 million of cash. Prior to consummation of the merger, and as permitted by the merger agreement, on April 6, 2006, RAM Energy redeemed a portion of its outstanding stock for an aggregate consideration of $10.0 million.

The merger is accounted for as a reverse acquisition. RAM Energy has been treated as the acquiring company and the continuing reporting entity for accounting purposes. Upon completion of the merger, the assets and liabilities of Tremisis were recorded at their fair value, which is considered to approximate historical cost, and added to those of RAM Energy. Because Tremisis had no active business operations prior to consummation of the merger, the merger was accounted for as a recapitalization of RAM Energy.

In December 2004, RAM Energy acquired WG Energy Holdings, Inc. for $82.6 million, which we refer to as the WG Energy Acquisition. Upon consummation of the WG Energy Acquisition, we changed WG Energy Holdings, Inc.’s name to RWG Energy, Inc.

Critical Accounting Policies

The preparation of our financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect our reported assets, liabilities and contingencies as of the date of the financial statements and our reported revenues and expenses during the related reporting period. Our actual results could differ from those estimates.

We use the full cost method of accounting for our investment in oil and natural gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves are capitalized into a “full cost pool” as incurred, and costs included in the pool are amortized and charged to operations using the future recoverable units of production method based on the ratio of current production to total proved reserves, computed based on current prices and costs. Significant downward revisions of quantity estimates or declines in oil and natural gas prices that are not offset by other factors could result in a write-down for impairment of the carrying value of our oil and natural gas properties. Once incurred, a write-down of the value of oil and gas properties is not reversible at a later date, even if quantity estimates or oil or natural gas prices subsequently increase.

Under Statement of Financial Accounting Standards No. 109 (“SFAS No. 109”), “Accounting for Income Taxes,” deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax

26

laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable

income. We routinely assess the realizability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.

Results of Operations

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Revenues and Other Operating Income. Our revenues and other operating income increased by $22.1 million, or 68%, for the nine months ended September 30, 2006, compared to the nine months ended September 30, 2005. The following table summarizes our oil and natural gas sales, production volumes, average sales prices and period-to-period comparisons for the periods indicated (dollars in thousands, except average sales prices):

	Nine months ended September 30,				Increase (Decrease)
	2005		2006
Oil and natural gas sales:
RAM Energy	$	11,393	$	10,916	(4.2	)%
RWG (WG Energy Acquisition)		36,747		42,134	14.7	%
Total	$	48,140	$	53,050	10.2	%
Production volumes:
Oil (MBbls):
RAM Energy		69		64	(7.3	)%
RWG (WG Energy Acquisition)		525		528	0.6	%
Total		594		592	(0.3	)%
NGL (MBbls):
RAM Energy		4		3	(25.1	)%
RWG (WG Energy Acquisition)		126		100	(21.0	)%
Total		130		103	(21.1	)%
Natural gas (MMcf):
RAM Energy		1,163		993	(14.6	)%
RWG (WG Energy Acquisition)		666		769	15.4	%
Total		1,828		1,761	(3.6	)%
Average sale prices:
Oil (per Bbl)	$	53.22	$	63.80	19.9	%
NGL (per Bbl)		35.28		41.89	18.7	%
Natural gas (per Mcf)		6.52		6.22	(4.5	)%
Per Boe		46.77		53.66	14.7	%

Oil and Natural Gas Sales. Our oil and natural gas revenues increased by $4.9 million, or 10.2%, for the nine months ended September 30, 2006, as compared to the nine months ended September 30, 2005, due primarily to a 15% increase in average product prices.

27

Before giving effect to an outstanding reversionary interest in our Boonsville shallow gas area, our daily average production in the first nine months of 2006 would have been 3,803 Boe per day versus 3,770 Boe per day for the nine months ended September 30, 2005, an increase of 1%. The outstanding reversionary interest, which vested in September 2005, impacted daily production for the first three quarters of 2006 production by 5%, resulting in actual average daily production being 3,621 Boe per day versus 3,770 Boe per day for the nine months ended September 30, 2005.

For the nine months ended September 30, 2006, our oil production decreased less than 1%, NGL production decreased 21%, and natural gas production decreased 4%, compared to the first nine months of the previous year. Our average realized sales price for oil was $63.80 per Bbl for the nine months ended September 30, 2006, an increase of 20% compared to $53.22 per Bbl for the nine months ended September 30, 2005. Our average realized NGL price for the nine months ended September 30, 2006 was $41.89 per Bbl, a 19% increase compared to $35.28 per Bbl for the nine months ended September 30, 2005. Our average realized natural gas price was $6.22 per Mcf for the nine months ended September 30, 2006, a decrease of 5% compared to $6.52 per Mcf for the comparable nine months of 2005.

Other Revenues. Other revenues for the nine months ended September 30, 2006 decreased by 53% to $466,000, compared to the nine months ended September 30, 2005 other revenues and operating income of $983,000.

Realized and Unrealized Gain (Loss) from Derivatives. For the nine months ended September 30, 2006, our gain from derivatives was $1.1 million, compared to a loss of $16.6 million for the first nine months of 2005. Our gains and losses during these periods were the net result of recording actual contract settlements, the premium costs paid for various derivative contracts, and unrealized mark-to-market values of our derivative contracts as shown in the following table (in thousands):

	Nine months ended September 30,
	2005			2006
Contract settlements and premium costs:
Oil	$	(1,820	)	$	(4,328	)
Natural gas		(280	)		(438	)
Realized (losses)		(2,100	)		(4,766	)
Mark-to-market gains (losses):
Oil		(4,957	)		1,676
Natural gas		(9,556	)		4,198
Unrealized gains (losses)		(14,513	)		5,874
Realized and unrealized gains (losses)	$	(16,613	)	$	1,108

For a further discussion of our realized and unrealized loss from derivatives, please see “Quantitative and Qualitative Disclosures About Market Risks — Commodity Price Risk.”

Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes for the nine months ended September 30, 2006, were $2.5 million, an increase of $67,000, or 3%, from the first three quarters of the previous year. Production taxes are based on realized prices at the wellhead. As revenues from oil and natural gas sales increase or decrease, production taxes on these sales increase or decrease also. As a percentage of oil and natural gas sales, oil and natural gas production taxes were 4.8% for the nine months ended September 30, 2006, compared to 5.1% for the nine months ended September 30, 2005.

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Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $13.2 million for the nine months ended September 30, 2006, an increase of $1.8 million, or 15%, from the $11.4 million for the nine months ended September 30, 2005. The increase was primarily due to increased utility

costs and higher maintenance costs due to additional producing wells. For the nine months ended September 30, 2006, our oil and natural gas production expense was $13.38 per Boe compared to $11.13 per Boe for the nine months ended September 30, 2005, an increase of 20%. As a percentage of oil and natural gas sales, oil and natural gas production expense increased to 25% for the nine months ended September 30, 2006 compared to 24% for the first nine months in 2005.

Amortization and Depreciation Expense. Our amortization and depreciation expense increased $806,000, or 9%, for the nine months ended September 30, 2006, compared to the nine months ended September 30, 2005. The increase was a result of higher capitalized costs due to increased drilling. On an equivalent basis, our amortization of the full cost pool of $9.5 million was $9.63 per Boe for the nine months ended September 30, 2006, an increase per Boe of 14% compared to $8.7 million, or $8.43 per Boe, for the nine months ended September 30, 2005.

Accretion Expense. SFAS No. 143, “Accounting for Asset Retirement Obligations,” includes, among other things, the reporting of the “fair value” of asset retirement obligations. Accretion expense is a function of changes in fair value from period-to-period. We recorded $398,000 for the nine months ended September 30, 2006, compared to $217,000 for the nine months ended September 30, 2005.

Share-Based Compensation. Concurrent with our acquisition of RAM Energy, Inc. on May 8, 2006, our Board of Directors awarded grants of an aggregate 330,000 shares of our common stock to certain of our senior officers and directors under our 2006 Long-Term Incentive Plan. For the nine months ended September 30, 2006, our share-based compensation was $2.2 million, calculated at a closing price on May 8, 2006, the day the shares were granted, of $6.72 per share.

General and Administrative Expense. For the nine months ended September 30, 2006, our general and administrative expense was $6.4 million, compared to $6.3 million for the nine months ended September 30, 2005, an increase of $66,000, or 1%.

Interest Expense. Our interest expense increased by $4.4 million to $13.2 million for the nine months ended September 30, 2006, compared to the $8.8 million incurred for the nine months ended September 30, 2005. During the second quarter we charged off $1.1 million of unamortized costs associated with our previous credit facility and we paid $1.0 million in prepayment premiums. The remaining interest expense of $11.1 million represents an increase of $2.3 million, or 38%, over the $8.8 million reported for the nine months ended September 30, 2005. This increase was due to higher interest rates and higher outstanding indebtedness during the 2006 period.

Income Taxes. For the nine months ended September 30, 2006, we recorded an income tax expense of $2.9 million on pre-tax income of $6.9 million. For the nine months ended September 30, 2005, the income tax effect was a $2.2 million benefit, on a pre-tax loss of $5.8 million. The effective tax rate for the nine month period was 42% and 38% in 2006 and 2005, respectively.

Net Income. Our net income was $4.0 million for the nine months ended September 30, 2006, compared to a net loss of $3.6 million for the nine months ended September 30, 2005. The income for the first three quarters of 2006 results from increased prices and gains on derivatives, partially offset by non-cash charges to share-based compensation and the remaining unamortized costs associated with our previous credit facility.

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Revenues and Other Operating Income. Our revenues and other operating income increased by $26.0 million, or 87%, for the year ended December 31, 2005, compared to the year ended December 31, 2004.

29

The following table summarizes our oil and natural gas sales, production volumes, average sales prices and period-to-period comparisons for the periods indicated (dollars in thousands except average sales prices):

	Year Ended December 31,				Increase (Decrease)
	2004		2005
Oil and natural gas sales:
RAM Energy	$	16,540	$	16,486	(0.3	)%
RWG (WG Energy Acquisition)		1,435		49,757	3,367.4	%
Total	$	17,975	$	66,243	268.5	%
Production volumes:
Oil (Mbls):
RAM Energy		151		95	(36.9	)%
RWG (WG Energy Acquisition)		27		692	2,463.0	%
Total Oil (Mbls)		178		787	342.0	%
NGL (Mbls):
RAM Energy		7		7	0	%
RWG (WG Energy Acquisition)		5		163	3,160.0	%
Total NGL (Mbls)		12		170	1,316.7	%
Natural gas (MMcf):
RAM Energy		1,901		1,666	(12.4	)%
RWG (WG Energy Acquisition)		27		1,015	3,659.3	%
Total natural gas (MMcf)		1,928		2,681	39.0	%
Average sale prices:
Oil (per Bbl)	$	37.63	$	53.75	43.0	%
NGL (per Bbl)		26.41		36.33	37.6	%
Natural gas (per Mcf)		5.69		6.61	16.3	%

Oil and Natural Gas Sales. Our oil and natural gas revenues were higher for the year ended December 31, 2005, as compared to the year ended December 31, 2004, with a 175% increase in production due, primarily, to the properties included in the WG Energy Acquisition and a 34% increase in realized prices, both on a Boe basis.

Our average daily production was 3.8 MBoe in the year ended December 31, 2005, compared to 1.4 MBoe for the year ended December 31, 2004, an increase of 175%. For the year ended December 31, 2005, our oil production increased 342%, our NGL production increased 1,317% and our natural gas production increased 39% compared to the year ended December 31, 2004. Our average realized sales price for oil was $53.75 per Bbl for the year ended December 31, 2005, an increase of 43% compared to $37.63 per Bbl for the year ended December 31, 2004. Our average realized NGL price for the year ended December 31, 2005, was $36.33 per Bbl, a 38% increase compared to $26.41 per Bbl for the year ended December 31, 2004. Our average realized natural gas price was $6.61 per Mcf for the year ended December 31, 2005, an increase of 16% compared to $5.69 per Mcf for the year ended December 31, 2004.

30

Decreases in production shown above, excluding effects of our WG Energy Acquisition, are due primarily to the following volumes and values of our former wholly owned subsidiary, RB Operating Company, or RBOC, included through the end of April 2004:

	Year Ended December 31, 2004
Oil and natural gas sales (in thousands)	$	2,302
Production volumes:
Oil (Mbls)		47
Natural gas (MMcf)		410
Average sale prices:
Oil (per Bbl)	$	32.64
Natural gas (per Mcf)	$	5.68

Gain On Sale of Subsidiary. On April 29, 2004, we completed the sale of all of the outstanding capital stock of our subsidiary, RBOC, for gross proceeds of $22.5 million. After adjustments for closing costs, we reported a gain of $12.1 million. The assets of RBOC at the time of the sale consisted entirely of oil and natural gas properties located in New Mexico, together with cash, accounts receivable and certain liabilities.

Other Revenues and Operating Income. Our other revenues and operating income for the year ended December 31, 2005 increased $513,000, or 152%, over the year ended December 31, 2004 due, primarily, to an increase in consulting service fees of approximately $200,000, sales of oilfield supplies of approximately $100,000, and numerous other non-material items.

Realized and Unrealized Loss from Derivatives. For the year ended December 31, 2005, our loss from derivatives was $11.7 million, compared to a loss of $793,000 for the year ended December 31, 2004. Our losses during these periods were the net result of recording unrealized mark-to-market values of our contracts, the premium costs paid for various derivative contracts, and actual contract settlements.

	Year Ended December 31,
	2004			2005
Contract settlements	$	(690	)	$	(3,902	)
Premium costs		(180	)		(1,491	)
Realized losses		(870	)		(5,393	)
Mark-to-market gains (losses)		77			(6,302	)
Realized and unrealized losses	$	(793	)	$	(11,695	)

Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes for the year ended December 31, 2005, were $3.3 million, an increase of $2.0 million, or 163%, from the $1.3 million incurred for the year ended December 31, 2004. Of the increase in production taxes for the year ended December 31, 2005, $2.3 million was attributable to our WG Energy Acquisition, while our production taxes decreased $300,000. Production taxes are based on realized prices at the wellhead. As revenues from oil and natural gas sales increase or decrease, production taxes on these sales increase or decrease also. As a percentage of oil and natural gas sales, oil and natural gas production taxes were 5.0% for the year ended December 31, 2005, compared to 7.0% for the year ended December 31, 2004. The reason for this decrease in percentage is because, after our WG Energy Acquisition, our greatest revenue source is oil sales in Texas, which are taxed at a 4.6% rate.

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Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $16.1 million for the year ended December 31, 2005, an increase of $12.5 million, or 347%, from $3.6 million for the year ended December 31, 2004. The increase of $12.8 million for the year ended December 31, 2005 was due to our WG Energy Acquisition, while our oil and natural gas production expense decreased $300,000. For the year ended December 31, 2005, our oil and natural gas production expense was $11.46 per Boe compared to $7.04 per Boe for the year ended December 31, 2004, an increase of 63%. As a percentage of oil and natural gas sales, oil and natural gas production expense increased from 20% for the year ended December 31, 2004, to 24% for the year ended December 31, 2005. The reason for the increase in costs, both in absolute amount and on a per Bbl basis is that one of the major fields included in our WG Energy Acquisition is a cost intensive, shallow water-flood unit. Fixed costs of the shallow water-flood unit, such as payroll, utilities, insurance, property and ad valorem taxes, regulatory compliance, and maintenance account for approximately 85% of the total operating costs. Repairs account for the balance. Our management expects that operating costs will remain at this level for the foreseeable future.

Amortization and Depreciation Expense. Our amortization and depreciation expense increased $9.7 million, or 298%, for the year ended December 31, 2005, compared to the year ended December 31, 2004. Our WG Energy Acquisition accounted for $9.7 million of the increase, offset by a $200,000 decrease for RAM. On an equivalent basis, our amortization of the full cost pool of $12.5 million was $8.93 per Boe for the year ended December 31, 2005, an increase per Boe of 52% compared to $3.0 million, or $5.89 per Boe for the year ended December 31, 2004.

Accretion Expense. SFAS No. 143, Accounting for Asset Retirement Obligations, includes, among other things, the reporting of the ^“fair value” of asset retirement obligations. Accretion expense is a function of changes in fair value from period-to-period, and we recorded $510,000 for the year ended December 31, 2005, compared to $78,000 for the year ended December 31, 2004. The increase of $432,000 for the year ended December 31, 2005 was due to the higher amount of the asset retirement obligation attributable to our WG Energy Acquisition.

General & Administrative Expense. For the year ended December 31, 2005, our general and administrative expense was $8.6 million and increased $2.0 million, or 30%, as compared with the $6.6 million reported for the year ended December 31, 2004. This increase was due primarily to the increased costs of accounting services, higher benefits, salaries, travel and legal fees during the 2005 period.

Interest Expense. Our interest expense increased by $7.5 million to $12.6 million for the year ended December 31, 2005, compared to $5.1 million for the year ended December 31, 2004. This increase was attributable to higher outstanding balances, primarily to fund the WG Energy Acquisition, and higher interest rates during the 2005 period.

Income Taxes. For the year ended December 31, 2005, we recorded income tax expense of $806,000 an effective tax rate of 60%, on pre-tax income of $1.3 million. The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before provision for income taxes. The significant differences between pre-tax book income and taxable book income relate to non-deductible expenses, such as unrealized losses from derivatives.

For the year ended December 31, 2004, we recorded an income tax provision of $3.7 million, based on an effective tax rate of 38%, on pre-tax income of $9.8 million.

Net Income (Loss). Our net income was $543,000 for the year ended December 31, 2005, compared to net income of $6.0 million for the year ended December 31, 2004. The decrease in our net income for 2005 compared to 2004 was primarily attributable to realized losses from derivatives, increases in oil and natural gas production expenses and taxes, amortization and depreciation expenses, interest expense and general and administrative expenses.

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Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Revenue and Other Operating Income. Our operating revenues increased by $9.6 million, or 48%, for the year ended December 31, 2004, compared to the year ended December 31, 2003.

The following table summarizes our oil and natural gas sales, production, average sales prices and period-to-period comparisons for the periods indicated:

	Year Ended December 31,				% Increase (Decrease)
	2003		2004
Oil and natural gas sales (in thousands).	$	20,053	$	17,975	(10.4	)%
Production volumes:
Oil (MBbls)		277		178	(35.8	)%
Natural gas liquids (MBbls)		5		12	140.0	%
Natural gas (MMcf)		2,334		1,928	(17.4	)%
Average net sales prices:
Oil (per Bbl)	$	29.47	$	37.63	27.7	%
Natural gas liquids (per Bbl)		16.94	$	26.41	55.9	%
Natural gas (per Mcf)		5.06		5.69	12.4	%

Oil and Natural Gas Sales. Our oil and natural gas sales revenues were lower in 2004 compared to 2003 with a 24% decrease in production due, primarily, to the sale of our subsidiary, RBOC, on April 29, 2004, partially offset by an 18% increase in realized prices, on a Boe basis. Our average daily production was 1,400 Boe in 2004 compared to 1,838 Boe during 2003, a decrease of 24%. For 2004, our natural gas production decreased by 17% and oil production decreased 36% compared to 2003. The average sale price realized by us for oil for 2004 was $37.63 per Bbl, a 28% increase from the $29.47 received for 2003, and for natural gas was $5.69 per Mcf for 2004, compared to $5.06 per Mcf for 2003, an increase of 12%.

Gain On Sale of Subsidiary. On April 29, 2004, we completed the sale of all of the outstanding capital stock of our wholly owned subsidiary, RBOC, for gross proceeds of $22.5 million. After adjustments for closing costs, we reported a gain of $12.1 million. The assets of RBOC at the time of the sale consisted of oil and natural gas properties located in New Mexico, cash, accounts receivable and certain liabilities.

Realized and Unrealized Loss from Derivatives. For 2004, our loss from derivatives was $793,000. For 2003, we recorded a loss from derivatives of $203,000. These losses were the net result of contract settlements, premium costs of various derivative contracts, and mark-to-market values of those contracts at year-end (in thousands).

	2003			2004
Contract settlements	$	—		$	(690	)
Premium costs		(328	)		(180	)
Realized losses		(328	)		(870	)
Mark-to-market gains		125			77
Realized and unrealized losses	$	(203	)	$	(793	)

Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes for 2004 were $1.3 million, a decrease of $145,000, or 10%, from $1.4 million for 2003. As a percentage of wellhead prices received, these production taxes were 7% for both 2004 and 2003.

Oil and Natural Gas Production Expense. Our oil and natural gas production expense for 2004 was $3.6 million, an increase of $73,000, or 2%, from $3.5 million for 2003. Our oil and natural gas production

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expense was 20% of sales of oil and natural gas, or $7.04 per Boe for 2004, compared to 18%, or $5.26 per Boe for 2003. This increase was due primarily to $568,000 attributable to RWG production expense in the 2004 period, offset by a decrease caused by the sale of RBOC.

Accretion Expense. We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” during the first quarter of 2003. One aspect of SFAS No. 143 is the reporting of the “fair value” of asset retirement obligations. Accretion expense is a function of changes in fair value from period-to-period. We recorded $78,000 of accretion expense for 2004, compared to $48,000 for 2003.

Amortization and Depreciation Expense. Our amortization and depreciation expense for 2004 was $3.3 million, a decrease of $825,000, or 20%, compared to $4.1 million for 2003. This decrease was due primarily to lower production during 2004. On a Boe basis, the amortization of our full cost pool was $5.89 per Boe for 2004, an increase of 4% compared to $5.64 per Boe for 2003.

General & Administrative Expense. Our general and administrative expense for 2004 was $6.6 million, an increase of $270,000, or 4% over our general and administrative expense of $6.3 million recorded for 2003. The increase was due primarily to increased salaries and benefits to employees, excluding officers, during 2004.

Interest Expense. Our interest expense increased by $158,000 to $5.1 million for 2004 compared to $4.9 million for 2003. This increase for 2004 was attributable to higher average interest rates during 2004, the write-off of deferred loan costs of $309,000, and the allocation in 2003 of $609,000 to discontinued operations.

Income Taxes. Our overall effective tax rate for 2004 and 2003 was 38% and (87%), respectively.

Loss from Discontinued Operations. On July 31, 2003, we sold our 145-mile oil and natural gas pipeline system located in the Anadarko Shelf area in Oklahoma to Continental Gas, Inc., or CGI, for $15.0 million, effective August 1, 2003, subject to certain adjustments. The sale price was reduced by $3.0 million in consideration of the settlement and mutual release by our subsidiary, Great Plains Pipeline Company, or GPPC, and by CGI of all claims that were or could have been asserted by CGI and GPPC in a lawsuit filed by CGI in September 2003, relating to disputes arising under a gas service contract between the parties. We received net sale proceeds of $11.8 million after all adjustments and less expenses relating to the sale.

The results of our discontinued operations for the year ended December 31, 2003 are as follows (in thousands):

Pipeline system revenue	$	14,500
Pipeline system costs and expenses:
Purchases		12,066
Operating costs		598
Depreciation		388
Impairment		2,562
Interest		609
Total system costs and expenses		16,223
Loss from discontinued operations		(1,723	)
Income tax benefit		(655	)
Loss from discontinued operations	$	(1,068	)

Net Income. We recorded net income of $6.1 million for 2004 compared to a net loss of $2.0 million for 2003, due primarily to the sale of RBOC.

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Liquidity and Capital Resources

As of September 30, 2006, we had net working capital of $670,000, a ratio of current assets to current liabilities of 1.1 to 1, cash and cash equivalents of $7.6 million, and $37.0 million was available under our revolving credit facility. At that date, we had $131.7 million of indebtedness outstanding, including $103.0 million under our credit facility, $28.4 million principal amount ($28.3 million net of the original issue discount) of indebtedness evidenced by RAM Energy, Inc.’s 11 ¹/2% senior notes due 2008, and $356,000 in other indebtedness. On September 22, 2006, we repurchased 739,175 shares of our common stock from an unaffiliated party in a negotiated transaction, at a purchase price of $4.295 per share.

Credit Facility. On April 5, 2006, RAM Energy, Inc. entered into a Third Amended and Restated Loan Agreement with Guggenheim Corporate Funding, LLC, for itself and as Agent for a group of lenders. This facility, which we refer to as the Guggenheim facility, amended, restated and replaced a prior credit facility known as the Foothill facility. Currently, we are not a party to, or a guarantor of obligations under, the Guggenheim facility. As part of the transaction creating the Guggenheim facility, Foothill assigned the notes and liens under the Foothill facility to the Agent for the lenders under the Guggenheim facility. The Guggenheim facility includes a $150.0 million revolving credit facility of which $50.0 million was immediately available, and a $150.0 million term loan facility of which $90.0 million was advanced at closing. The remainder of the term loan facility may become available, subject to approval of each lender desiring to fund its proportionate share of the additional term loan advance, for certain of the future needs of RAM Energy, Inc., including acquisitions. The Guggenheim revolving credit facility is scheduled to mature in four years, during which time amounts may be borrowed, repaid and re-borrowed, subject to a borrowing base limitation to be determined by the lenders. The term loan facility is scheduled to mature in five years, with permitted prepayments after the first year, subject to a prepayment premium in the second and third years of the term. Advances under the revolving credit facility bear interest at LIBOR plus 2% per annum, while amounts outstanding under the term loan bear interest at LIBOR plus 5 ¹/2% to 6% per annum. Obligations under the Guggenheim facility are secured by liens on substantially all of the assets of RAM Energy, Inc. and its subsidiaries. The initial advance under the Guggenheim facility was used to refinance the Foothill facility, to pay expenses associated with establishing the Guggenheim facility, and to fund a $10.0 million redemption payment. Subsequent advances may be used to:

Ÿ repurchase all of RAM Energy, Inc.’s outstanding 11 ¹/2% senior notes due 2008 ($28.4 million principal amount); and

Ÿ fund general working capital purposes.

The Guggenheim facility contains financial covenants requiring RAM Energy, Inc. to maintain certain ratios, including a current ratio, a ratio of EBITDA to interest expense, a ratio of total indebtedness to EBITDA, and a ratio of asset value to total indebtedness. In addition, the Guggenheim facility contains other affirmative and negative covenants customary in lending transactions of this nature, including restrictions on the payment of dividends and the maintenance by RAM Energy, Inc. of derivative contracts on not less than 50% nor more than 85% of RAM Energy, Inc.’s projected oil and natural gas production from its properties on a rolling 24-month period; provided that the derivative requirements will be waived for any quarter in which RAM Energy Inc.’s leverage ratio is less than 2.0 to 1.0.

Senior Notes. On February 24, 1998, RAM Energy, Inc. issued $115.0 million principal amount of its 11 ¹/2% senior notes which mature February 15, 2008. Currently, we are not a party to, or a guarantor of, the senior notes or of any obligations under the indenture covering the senior notes. At September 30, 2006, RAM Energy, Inc. had outstanding $28.4 million aggregate principal amount of its senior notes. The notes bear interest at an annual rate of 11 ¹/2%, payable semi-annually on each February 15 and August 15. Pursuant to a Second Supplemental Indenture executed in November 2002, substantially all of the restrictive

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covenants and certain events of default contained in the original indenture were eliminated. We may redeem our outstanding senior notes prior to February 15, 2007 at 107.67% of the stated principal amount and thereafter at 103.84% until their maturity on February 15, 2008.

Cash Flow From Operating Activities. Our cash flow from operating activities is comprised of three main items: net income (loss), adjustments to reconcile net income to cash provided (used) before changes in working capital, and changes in working capital. For the nine months ended September 30, 2006, our net income was $4.0 million, as compared with net loss of $3.6 million for the nine months ended September 30, 2005. Adjustments (primarily non-cash items such as depreciation and amortization, unrealized (gain) loss on derivatives, share-based compensation and deferred income taxes) were $11.8 million for the nine months ended September 30, 2006 compared to $21.3 million for the first nine months of 2005, a decrease of $9.4 million. Unrealized gain on derivatives, partially offset by changes in deferred income taxes, was the primary reason for the decrease. Working capital changes for the nine months ended September 30, 2006 were a positive $9.5 million compared with negative changes of $7.0 million for the nine months ended September 30, 2005. For the nine months ended September 30, 2006, in total, net cash provided by operating activities was $25.3 million compared to $10.6 million of net cash provided by operations for the first three quarters of the previous year.

For the year ended December 31, 2005, our net income was $543,000, as compared with net income of $6.1 million for the year ended December 31, 2004. Net income for the 2004 period resulted primarily from gain recognized on the sale of RBOC. Adjustments (primarily non-cash items such as depreciation and amortization, unrealized loss on derivatives, gain on the sale of RBOC and deferred income taxes) were $21.8 million for the year ended December 31, 2005 compared to a negative adjustment of $11.1 million for the year ended December 31, 2004, an increase of $32.9 million. Working capital changes for the year ended December 31, 2005 were a negative $4.0 million compared with a positive $6.9 million for the year ended December 31, 2004. For the year ended December 31, 2005, in total, net cash provided by operating activities was $18.4 million compared to $1.8 million of net cash provided by operations for the year ended December 31, 2004.

For the year ended December 31, 2004, our net income was $6.1 million, compared with net loss of $2.0 million for the year ended December 31, 2003. Adjustments (primarily non-cash items such as depreciation and amortization, loss from discontinued operations, gain on early extinguishment of debt and deferred income taxes) were negative $11.1 million for the year ended December 31, 2004 compared to $2.1 million for the prior year, a decrease of $13.2 million. The $12.1 million gain on sale of subsidiary in 2004, $1.1 million loss from discontinued operations in 2003, and unrealized gain on derivatives, partially offset by changes in deferred income taxes, caused most of this decrease. Working capital changes for the year ended December 31, 2004 were a positive $6.9 million compared with changes of $5.7 million for the year ended December 31, 2003. Cash provided by discontinued operations was $898,000 in 2003. For the year ended December 31, 2004, net cash provided by operating activities was $1.8 million compared to $5.8 million of net cash provided by operations for the previous year.

Cash Flow From Investing Activities. For the nine months ended September 30, 2006, net cash used in our investing activities was $18.7 million, consisting of $21.5 million in payments for oil and natural gas properties and equipment and $726,000 in payments for other property and equipment, offset by $3.5 million of proceeds from the sale of undeveloped acreage, $366,000 in proceeds from the sale of other property and equipment, and $386,000 of net merger costs. The first nine months of 2006 reflected an 89% increase in cash used in investing activities compared to the first nine months of the previous year. For the nine months ended September 30, 2005, net cash used in our investing activities was $9.9 million, consisting of $11.1 million in payments for oil and natural gas properties and $1.1 million for other property and equipment additions, offset by $2.3 million in proceeds from the sale of oil and natural gas properties.

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For the year ended December 31, 2005, net cash used by our investing activities was $12.6 million, consisting of $13.5 million in payments for oil and natural gas properties and other property and equipment additions, offset partially by $2.5 million in proceeds from the sale of oil and natural gas properties. This compares with net cash used in our investing activities for the year ended December 31, 2004, of $64.9 million, consisting of $21.8 million in proceeds from the sale of RBOC, and $1.7 million in proceeds from short-term investments, offset by $88.7 million in net payment for property additions and the WG Energy Acquisition.

For the year ended December 31, 2004, net cash used by our investing activities was $64.9 million, which included $82.6 million net cash used for the WG Energy Acquisition, $5.9 million in payments for oil and natural gas properties and equipment, and $205,000 in payments for other property and equipment. Offsets to cash used in investing activities for 2004 included $21.8 million in proceeds from the sale of a subsidiary, $1.7 million in proceeds from short-term investments, and $358,000 in proceeds from sales of oil and natural gas properties and other equipment. For the year ended December 31, 2003, net cash provided by our investing activities was $7.4 million, consisting of $12.0 million of proceeds from the sale of pipeline system, and $202,000 of proceeds from the sale of oil, natural gas and other property, offset by $4.3 million in payments for oil and natural gas properties, $343,000 in payments for other property and equipment, and $181,000 in payments for short-term investments.

Cash Flow From Financing Activities. For the nine months ended September 30, 2006, net cash provided by our financing activities was $938,000, compared to net cash used of $161,000 for the nine months ended September 30, 2005. The cash provided in the first nine months of 2006 included an approximate $15.8 million net debt increase, partially offset by a stock redemption of $9.8 million, a stock repurchase of $3.8 million and $500,000 in dividends.

For the year ended December 31, 2005, net cash used by our financing activities was $6.9 million, compared to $62.1 million provided during the year ended December 31, 2004. The cash used in 2005 included $5.5 million in net debt reduction and $1.4 million in dividends. Cash provided in 2004 was primarily debt incurred for the WG Energy Acquisition.

For the year ended December 31, 2004, net cash provided by our financing activities was $62.1 million, compared to net cash used $12.3 million for the year ended December 31, 2003. The net cash provided in 2004 consisted of $70.4 million net borrowings on long-term debt, offset by $5.1 million used for stock repurchased and returned, $1.5 million in payments for deferred loan costs, and $1.6 million in dividends. The net cash used in 2003 included $11.9 million in payments on long-term debt and $404,000 in dividends.

Capital Commitments

We have budgeted $30.3 million for capital expenditures in 2007 related to:

Ÿ geological, geophysical and seismic costs ($2.9 million);

Ÿ developmental drilling and re-completions ($17.7 million); and

Ÿ exploratory drilling, including leasehold acquisitions ($9.7 million).

In our 2007 drilling and development budget, we have allocated $4.0 million to our north Texas Barnett Shale properties, $7.4 million to our Wolfcamp properties, $500,000 to our Woodford properties, $9.7 million to our Electra/Burkburnett properties, $1.6 million to our Boonsville properties, and $4.2 million to our other properties. Our budgeted allocations may change, depending on our drilling success, prices for oil and natural gas, general economic conditions and other factors beyond our control.

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During the nine months ended September 30, 2006, we had capital expenditures of $21.5 million relating to our oil and natural gas operations, of which $14.4 million was allocated to drilling new development wells, $1.9 million was for exploration costs, and $5.2 million was for acquisition costs. Our non-acquisition capital expenditures for the year 2006 aggregated approximately $23.4 million. The amount and timing of our capital expenditures may vary depending on the rate at which we expand and develop our oil and natural gas properties. We may require additional financing for future acquisitions and to refinance our debt before or at its final maturities.

Our capital expenditures for 2005 were $15.0 million, excluding the sale of producing properties, the majority of which was allocated to drilling new wells at proved undeveloped locations and re-completing existing wells. During the year ended December 31, 2004, we acquired WG Energy for $82.6 million and had capital expenditures related to our properties of $5.9 million. In 2003, our capital expenditures were $5.3 million, including $5.1 million in development costs and $202,000 in exploration costs.

Although we cannot provide any assurance, assuming successful implementation of our strategy, including the future development of our proved reserves and realization of our cash flows as anticipated, we believe that borrowings available under our credit facility, the balance of our unrestricted cash and cash flows from operations will be sufficient to satisfy our budgeted capital expenditures, working capital and debt service obligations for the foreseeable future. The actual amount and timing of our future capital requirements may differ materially from our estimates as a result of, among other things, changes in product pricing and regulatory, technological and competitive developments. Sources of additional financing available to us may include commercial bank borrowings, vendor financing and the sale of equity or debt securities. We cannot provide any assurance that any such financing will be available on acceptable terms or at all.

The table below sets forth our contractual cash obligations as of December 31, 2005, which are obligations during the following years:

	2006		2007-2008		2009-10		and after
	(in thousands)
Contractual Cash Obligations
Long-term debt	$	4,500	$	108,500	$	—	$	—
Operating leases		325		469		—		—
Capital leases		—		—		—		—
Purchase obligations		—		—		—		—
Total contractual cash obligations	$	4,825	$	108,969	$	—	$	—

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The carrying amounts reported in our consolidated balance sheets for cash and cash equivalents, trade receivables and payables, installment notes and variable rate long-term debt approximate their fair values.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on our borrowings, other than our 11 ¹/2% senior notes. We have not used interest rate derivative instruments to manage our exposure to interest rate changes.

Commodity Price Risk

Our revenue, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell most of our oil and natural gas production under market price contracts.

To reduce exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow, we periodically utilize various derivative strategies to manage the price received for a portion of our future oil and natural gas production. We have not established derivatives in excess of our expected production.

Our derivative positions at December 31, 2006 are shown in the following table:

	Crude Oil (Bbls)						Natural Gas (MMBtu)
	Floors			Ceilings			Floors			Ceilings
	Per day	Price		Per day	Price		Per day	Price		Per day	Price
Collars
2007	1,500	$	52.67	1,500	$	73.24	4,177	$	7.48	4,177	$	11.58
2008	950		53.69	950		86.08	4,000		6.87	4,000		13.53
Secondary Floors
2007							4,000		12.00

Crude oil and natural gas contracts cover each month of 2007 and natural gas secondary floors for 2007 are for April through October. Crude oil contracts and natural gas contracts for 2008 are for January through December. For the fourth quarter of 2006, we had a realized gain from our derivative activities of approximately $228,000.

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BUSINESS AND PROPERTIES

General

We are an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of oil and natural gas properties, primarily in Texas, Louisiana and Oklahoma. Our producing properties are located in highly prolific basins with long histories of oil and natural gas operations. We have been active in these core areas since our inception in 1987 and have grown through a balanced strategy of acquisitions and development and exploratory drilling. We have completed over 20 acquisitions of producing oil and natural gas properties and related assets for an aggregate purchase price approximating $400 million. Through December 31, 2006, we have drilled or participated in the drilling of 561 oil and natural gas wells, 93% of which were successfully completed and produced hydrocarbons in commercial quantities. Our management team has extensive technical and operating expertise in all areas of our geographic focus.

Our oil and natural gas assets are characterized by a combination of conventional and unconventional reserves and prospects. We have conventional reserves and production in four main onshore locations:

Ÿ Electra/Burkburnett, Wichita and Wilbarger Counties, Texas;

Ÿ Boonsville, Jack and Wise Counties, Texas;

Ÿ Vinegarone, Val Verde County, Texas; and

Ÿ Egan, Acadia Parish, Louisiana.

We have unconventional reserves and production in our Barnett Shale play located in Jack and Wise Counties, Texas, where we own interests in approximately 27,700 gross (6,800 net) acres.

In addition, we have positioned ourselves for participation in two emerging resource plays in southwest Texas. We have an exploratory play targeting the Barnett and Woodford Shale formations where we own interests in approximately 84,000 gross (6,600 net) acres. We also have an exploratory play targeting the Wolfcamp formation where we are actively acquiring acreage and have accumulated leases and options covering over 15,000 gross and net acres.

At December 31, 2005, our estimated net proved reserves were 18.8 MMBoe, of which approximately 60% were crude oil, 30% were natural gas, and 10% were natural gas liquids, or NGLs. The PV-10 Value of our proved reserves was approximately $345.5 million based on prices we were receiving as of December 31, 2005, which were $58.63 per Bbl of oil, $35.89 per Bbl of NGLs and $9.14 per Mcf of natural gas. At December 31, 2005, our proved developed reserves comprised 70% of our total proved reserves, and the estimated reserve life for our total proved reserves was approximately 15 years.

We own interests in approximately 2,900 wells and are the operator of leases upon which approximately 1,900 of these wells are located. The PV-10 Value attributable to our interests in the properties we operate represented approximately 86% of our aggregate PV-10 Value as of December 31, 2005. We also own a drilling rig and various gathering systems, a natural gas processing plant, service rigs and a supply company that service our producing properties.

From January 1, 1997 through December 31, 2005, our reserve replacement percentage, through discoveries, extensions, revisions and acquisitions, but excluding divestitures, was 344%. Since January 1, 1997, our historical average finding cost from all sources, exclusive of divestitures, has been $6.27 per Boe. During the year ended December 31, 2006, we drilled or participated in the drilling of 92 wells on our oil and natural gas properties, 80 of which were successfully completed as producing wells, four of which were dry holes and eight of which were either drilling or waiting to be completed at the end of that period.

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Principal Properties

The following is a description of each of our principal properties as of September 30, 2006, together with a general description of our miscellaneous and non-core properties. For information regarding our drilling activities in the fourth quarter of 2006, see “Prospectus Summary—Recent Events—Fourth Quarter Operations.”

Electra/Burkburnett Area. Our properties in the Electra/Burkburnett Area of north Texas include 26 leases covering 12,190 gross acres. As of September 30, 2006, we owned interests in approximately 1,600 wells in the Electra/Burkburnett Area, of which 503 were active producing wells and 215 were active injection wells.

We drilled more than 134 wells in the Electra/Burkburnett Area from November 1, 2004 through September 30, 2006, and, as of September 30, 2006, 152 drilling locations were booked as proved undeveloped locations. We estimate the average recoverable proved reserves attributable to each infill well remaining to be drilled in the Electra/Burkburnett Area should be approximately 22,000 Bbls of oil per well.

During the nine months ended September 30, 2006, we drilled 61 net wells in the Electra/Burkburnett Area, of which 57 were completed as producing wells and four were in various stages of completion at the end of the third quarter. We own a 100% working interest in and operate all 61 of the wells. The initial net daily production from wells drilled and completed during the nine months ended September 30, 2006 averaged 26 Bbls of oil. The average cost incurred by us to drill, complete and equip a producing well in our Electra/Burkburnett Area during the nine months ended September 30, 2006 was $126,700.

The Electra Field has produced millions of barrels of crude oil over the past 80 years. Our currently active wells in this field produce through secondary recovery (waterflood) operations. Well spacing has been decreased to two to three acre spacing in most areas to permit the recovery of bypassed oil and to improve waterflood operations.

Since January 1, 2002, a significant number of new infill and injection wells have been drilled on our Electra/Burkburnett Area leasehold, with a 99% success rate.

Approximately 30% of our wells in the Electra/Burkburnett Area are not equipped to gather casinghead gas, and this gas is vented at the wellhead. The remainder of our produced casinghead gas is processed at our 100% owned Electra Gas Plant, which is located approximately three miles northwest of Electra, Texas on lands leased by us. The term of the surface lease on which our Electra Gas Plant is located will continue for so long as the land is used for the Electra Gas Plant. We pay no rental under the terms of this lease. The plant receives approximately 850 Mcf per day of casinghead gas produced from our properties in the area. The gas is processed in a 1,400 Mcf per day capacity refrigeration unit where approximately 163 Bbls of NGLs per day, net to our interest, are extracted and sold. Approximately 250 Mcf per day of residue gas is used for compressor fuel at the plant and the remainder is flared due to a lack of pipeline facilities in the area.

The largest single operating cost in the field historically has been electricity. In an effort to substantially reduce this cost, in November 2005, we installed two natural gas powered field generators to provide electricity for lease operations. The natural gas used to operate the generators is our natural gas that was previously vented or flared, so the installation of the generators has not reduced sales volumes or lease revenues or increased operating costs. We estimate that since the generators have been in full operation, the resulting savings in field electricity costs has been approximately $38,000 per month.

On April 1, 2005, we purchased a drilling rig specifically for the purpose of facilitating our ongoing drilling program in the Electra/Burkburnett Area and have been using this rig and our own crew and equipment to drill from six to eight wells per month in the field. We also use our own personnel and equipment to perform routine maintenance on our properties and typically do not require third party vendor services. We own our own pulling units, earthmoving equipment, tank trucks and other field equipment to

41

ensure availability and facilitate operations in the field. We employ approximately 65 field employees dedicated to our Electra/Burkburnett operations, all of which work out of our field office in the town of Electra.

We sell the crude oil produced from our Electra/Burkburnett area properties to Shell Trading (US) Company at the STUSCO WTI posted price, plus $1.50. For the month of September 2006, the sale price was $62.50 per Bbl.

During the nine months ended September 30, 2006, the aggregate net production attributable to our interest in the Electra/Burkburnett properties was 483,410 Bbls of oil and 34,598 Bbls of NGLs, or 518,008 Boe, and the average daily production for the period was 1,771 Bbls of oil and 127 Bbls of NGLs, or 1,898 Boe per day.

During September 2006, the aggregate net production attributable to our interest in the Electra/ Burkburnett properties was 50,360 Bbls of oil and 4,878 Bbls of NGLs, or 55,238 Boe, and the average daily production for the period was 1,679 Bbls of oil and 163 Bbls of NGLs, or 1,842 Boe per day.

Egan Field. Our Egan Field, located in Acadia Parish, Louisiana, covers an area of approximately 4,400 acres. Over the past 60 years, more than 90 wells have been drilled in the field at depths ranging from 9,000 feet to 12,400 feet.

The Egan Field is a geologically complex domal feature that produces from a number of different formations that are dissected by extensive faulting. This type of heavily faulted geology is typical of Acadia Parish, where a number of similar fields have been productive for several decades.

Over the past five years, we have undertaken a recompletion program in the Egan Field, conducting successful operations in 12 wells, and have identified more than seven additional recompletion opportunities in existing wellbores.

We own interests in approximately 4,367 gross (2,633 net) leasehold acres and ten producing wells in the Egan Field, and are the operator of all such wells. Our average working interest in the Egan Field properties is approximately 83%, with an average net revenue interest of 71%.

For the nine months ended September 30, 2006, the aggregate net production attributable to our interest in the Egan Field properties was 12,380 Bbls of oil and 261 MMcf of natural gas, or 55,884 Boe, and average daily production for the period was 45 Bbls of oil and 956 Mcf of natural gas, or 205 Boe per day.

During September 2006, aggregate net production attributable to our interest in the Egan Field properties was 1,088 Bbls of oil and 26 MMcf of natural gas, or 5,351 Boe, and our average daily production for the period was 37 Bbls of oil and 853 Mcf of natural gas, or 178 Boe per day.

Boonsville Area. The Boonsville Area is located in the Fort Worth Basin of north central Texas in Jack and Wise Counties. Our leasehold in the area covers approximately 9,950 gross acres lying within the much larger Boonsville Field, which includes several hundred thousand acres.

Our properties in Jack and Wise Counties are comprised of two discrete subsets: the shallow gas zones and the Barnett Shale acreage. Because a considerable portion of our leasehold in the area is segregated with respect to rights above and below the Marble Falls formation, a prominent geologic marker in the area, and our substantially undeveloped Barnett Shale acreage (which lies below the Marble Falls) represents a distinct property requiring drilling, completion and production techniques quite dissimilar from the shallow gas producing zones, we treat our Barnett Shale acreage as a separate major property. We consider the Boonsville Area to include only the properties described herein as the shallow gas zones. Our Barnett Shale acreage is discussed separately below.

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Our oil and natural gas production from the Boonsville Area is derived principally from sands found at depths ranging from 3,800 feet to 6,100 feet. We own working interests in 88 wells producing from these shallow gas zones and operate all but one of such wells.

We own and operate an extensive gas gathering system in the field which gathers gas solely from our wells. The gas is compressed in the field through compression facilities also owned by us, and then is delivered into a system owned and operated by a third party for delivery to the Chico gas processing plant, where the natural gas is processed for the extraction of NGLs. We currently receive 85% of both the residue gas and the NGLs attributable to our share of delivered volumes.

During the nine months ended September 30, 2006, the aggregate net production attributable to our working interests in the Boonsville shallow gas properties (above the Marble Falls) was 12,442 Bbls of oil, 318 MMcf of natural gas and 64,400 Bbls of NGLs, or 130,446 Boe, and average daily production for the period was 46 Bbls of oil, 1,166 Mcf of natural gas and 236 Bbls of NGLs, or 476 Boe per day.

During September 2006, aggregate net production attributable to our interest in the Boonsville shallow gas properties was 984 Bbls of oil, 33,196 Mcf of natural gas and 7,126 Bbls of NGLs, or 13,643 Boe, and the average daily production for the period was 33 Bbls of oil, 1,107 Mcf of natural gas and 238 Bbls of NGLs, or 455 Boe per day.

We have drilled and successfully completed two wells since our acquisition of WG Energy in 2004. We own a 74% working interest in and operate both wells. Currently, there are 20 drilling locations identified as proved undeveloped locations. We believe that additional wells, not currently identified as proved undeveloped locations, will eventually be drilled to test the shallow gas zones underlying our Boonsville properties. We are also actively pursuing a workover program in our existing wells to maximize production and take advantage of opportunities in other potentially productive zones in existing well bores that present attractive recompletion targets.

Barnett Shale Acreage. We own leases covering approximately 27,700 gross (6,800 net) acres of Barnett Shale rights in the Fort Worth Basin of north central Texas, all of which are held by production from wells completed in the shallow gas zones. The Fort Worth Basin Barnett Shale play currently is the largest natural gas play in Texas and one of the leading natural gas plays in the United States. Our Fort Worth Basin Barnett Shale acreage lies in the Boonsville Area of Jack and Wise Counties, Texas, below the Marble Falls geologic marker at depths ranging from 6,500 feet to 8,500 feet and is, for the most part, undeveloped.

The core area of the play is in Denton, Wise and Tarrant Counties, lying just to the east-southeast of our acreage in Jack and Wise Counties. The most productive wells in the Barnett Shale play are wells that have been drilled horizontally. The average cost of drilling and completing a horizontal well to the Barnett Shale is approximately $2.6 million.

We are a party to two separate agreements covering our Barnett Shale acreage position in the Fort Worth Basin:

Ÿ Approximately 3,500 gross acres are subject to a Participation Agreement with Devon Energy Corporation in which we have the right to participate with a 36% working interest in each well proposed to be drilled on the contract area. The agreement is on a “drill-to-earn” basis, which means that Devon can earn a 50% working interest and a 40% net revenue interest in a particular lease by drilling and paying its proportionate share of the costs of a well on lands covered by the lease. This agreement includes a continuous drilling obligation, requiring Devon to commence a new well within 120 days after the filing of a completion report on the preceding well, failing which Devon’s right to earn under the agreement will terminate, and Devon’s interests in undrilled acreage will

43

revert to us. Through September 30, 2006, six horizontal wells have been drilled under the agreement and completed as commercially productive in the Barnett Shale.

Ÿ Approximately 23,500 gross acres are committed to an agreement with EOG Resources, Inc. In April 2004, we entered into a purchase and sale agreement with EOG, under which EOG purchased from us an undivided 50% working interest and a 40.6% net revenue interest in certain oil and natural gas leases comprising a portion of our Barnett Shale acreage. After giving effect to the sale to EOG, we retained a 23.9% working interest in the subject leases. Currently, our net revenue interest in our Barnett Shale acreage subject to the EOG Agreement is approximately 18%. Through September 30, 2006, EOG has drilled one well on our Barnett Shale acreage, which was completed as a commercially productive well.

During the nine months ended September 30, 2006, the aggregate net production attributable to our interest in the currently producing Barnett Shale wells was 3,441 Bbls of oil and 310 MMcf of natural gas, and average daily production for the period was 13 Bbls of oil and 1,137 Mcf of natural gas, or 202 Boe per day.

During September 2006, the aggregate net production attributable to our interest in the Barnett Shale properties was 313 Bbls of oil, 39 MMcf of natural gas and 287 Bbls of NGLs, and the average daily production for the period was 10 Bbls of oil, 1,316 Mcf of natural gas and 10 Bbls of NGLs, or 239 Boe per day.

Although our Fort Worth Basin Barnett Shale acreage has not yet made a substantial contribution to our daily production, we believe that there are more than 325 potential drilling locations on our acreage, with more than 290 of those locations on leasehold subject to the EOG agreement and more than 35 on the Devon acreage block. We currently have four proved, undeveloped drilling locations that have been established by prior drilling. In addition, our ongoing review of seismic data supports 11 additional drilling locations in the EOG block and eight additional drilling locations in the Devon block as of year end 2006.

We continue to acquire and interpret seismic data covering a portion of our Barnett Shale acreage. Currently, we own 35 square miles of 3-D seismic data and expect to acquire an additional 60 square miles of 3-D seismic data during 2007. At September 30, 2006, we owned an interest in nine (gross) Barnett Shale producing wells, two of which are operated by us, six of which are operated by Devon Energy and one of which is operated by EOG.

Vinegarone Field. The Vinegarone Field is located in Val Verde County, Texas, which is in the Big Bend region of South Texas. We own working interests in seven producing wells in the field, none of which are operated by us.

Production from Vinegarone Field is obtained primarily from three distinct horizons at depths ranging from 9,100 feet to 10,100 feet. We own interests in 6,686 gross (1,830 net) leasehold acres in the Vinegarone Field. In most instances, our working interest is 25%, with an average 21.9% net revenue interest, although in one section (Section 49), in which there are two producing wells, our working interest is 43.8% and our net revenue interest is 38.3%.

During the nine months ended September 30, 2006, we participated in the drilling of three wells in the Vinegarone Field, two of which are in the process of being completed and one of which was a dry hole. We have identified three proved undeveloped locations in the field and expect to continue our development of the field over the next two years.

For the nine months ended September 30, 2006, the aggregate net production attributable to our interest in the Vinegarone Field properties was 241 MMcf of natural gas, and the average daily production for the period was 882 Mcf of natural gas, or 147 Boe per day.

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During September 2006, the aggregate net production attributable to our interest in the Vinegarone Field was 26 MMcf of natural gas, and average daily production for the period was 860 Mcf of natural gas, or 143 Boe per day.

Other Properties

In addition to the principal fields and core operating areas, we also own interests in other properties located in Texas, Oklahoma, Mississippi, Louisiana, Kansas, New Mexico, Wyoming, Arkansas and offshore California.

We own a significant number of properties scattered throughout the principal producing basins in Oklahoma and are actively seeking exploration opportunities within these areas.

In Texas, in addition to the Electra/Burkburnett and Boonsville Area properties, we own miscellaneous operated and non-operated interests in 554 producing wells across the state, from the Panhandle down through the Permian Basin to South Texas, and eastward to Louisiana. We also own leasehold interests in approximately 84,000 gross (6,600 net) acres in an exploratory project located in southwest Texas principally targeting the Barnett and Woodford Shales and approximately 15,000 gross and net acres (including options) in another southwest Texas exploration project targeting the Wolfcamp formation.

Nearly 43,000 gross (5,700 net) acres of our leasehold in the southwest Texas Barnett/Woodford project area are subject to a farmout agreement with J. Cleo Thompson, et. al. Under this agreement, Thompson has acquired ten square miles of 3-D seismic data and drilled the Fasken Ranch 34-2H, a horizontal well recently completed in the Woodford Shale. This well is currently producing approximately 400 Mcf per day with net natural gas sales averaging between 30 and 40 Mcf per day. The remaining natural gas production is being re-injected for gas lift purposes. We will have the right to participate for one-half of our interest following the drilling of the next earning well. Our remaining acreage in this play is subject to a third-party joint operating agreement which allows us the right to participate for an approximate 2% working interest in all future drilling proposals located on this acreage.

On our southwest Texas Wolfcamp project, we drilled two 100%-owned wells during the fourth quarter of 2006. We expect to attempt completion of these wells in the first quarter of 2007. We also participated in two gross (0.2 net) exploratory wells in the Arkoma Basin during 2006.

Ownership and Control of Service and Other Supply Assets

We own and control service and supply assets, including a drilling rig, service rigs, a supply company, gathering systems and other related assets. We believe that ownership and use of these assets for our own account provides us with a significant competitive advantage with respect to availability, lead-time and cost of these services. For the 2007 calendar year, approximately 75% of our projected capital expenditures will be in areas serviced by these assets.

Development, Exploitation and Exploration Programs

Development and Exploitation Program. Our future production and performance depends to a large extent on the successful development of our existing reserves of oil and natural gas. We have identified multiple development projects on our existing properties (substantially all of which are located in our core areas), and these projects involve both the drilling of development wells (which includes 445 injection wells) and extension wells. We are lease operator of leases covering approximately 1,943 of the wells in which we own interests, and as such we are able to control expenses, capital allocation and the timing of development activities of these properties. During the nine months ended September 30, 2006, we drilled or participated in the drilling of 66 gross (63.2 net) development wells on our oil and gas properties, 65 of

45

which were either successfully completed as producing wells, were still drilling, or were awaiting completion at the end of that period. Capital expenditures in connection with these activities during this period aggregated approximately $14.4 million.

Another determinant of future performance is the exploitation of existing wells that can be re-completed or otherwise reworked to extract additional hydrocarbons. We have identified 178 projects

involving re-completions of existing wells, all of which involve reserves included in our proved reserves at December 31, 2005. During the nine months ended September 30, 2006, we conducted or participated in recompletion/workover operations on eight of our existing wells, resulting in the reestablishment or enhancement of production from each of these wells. Our capital expenditures in connection with these recompletion operations aggregated approximately $1.7 million.

Exploration Program. A principal component of our strategy to expand our reserves and production includes an exploration program focused on adding long-lived oil and natural gas reserves from our core areas and other resource plays. Since 1987, we have conducted a successful development and exploitation program resulting in the accumulation of significant long-lived oil and natural gas reserves at relatively moderate depths, located principally in our core areas. In 1998, utilizing the knowledge and expertise gained from this effort, we initiated an exploration program by adding exploration professionals to our technical staff. We intend to maintain an exploration focus in our core areas, while remaining opportunistic with respect to other exploration concepts. These additional exploration concepts include pursuing opportunities in tight gas and other unconventional natural gas plays. In our core areas, we own in excess of 131,000 gross (31,900 net) undeveloped leasehold acres (including options), which enhances our competitive exploration position and provides the foundation for future reserve additions. Included in this number are 99,000 gross (21,600 net) undeveloped leasehold acres (including options) in our Wolfcamp, Barnett, and Woodford Shale resource plays located in southwest Texas. We intend to proceed with exploration in these areas.

We have an experienced technical staff, including geologists, landmen, engineers and other technical personnel devoted to prospect generation and identification of potential drilling locations. We seek to reduce exploration risk by exploring at moderate depths that are deep enough to discover sizeable gas accumulations (generally less than 13,000 feet). Our established presence in our core areas has provided our staff with substantial expertise. Many of our exploration plays are based upon seismic data comparisons to our existing producing fields. While we will maintain this focus, we plan to broaden our exposure and be opportunistic in pursuing growth-oriented exploration plays in other basins, primarily on an operated basis. For exploration prospects we generate, we typically will own a greater interest in these projects than our drilling partners, if any, and will operate the wells. As a result, we will be able to influence the areas of exploration and the acquisition of leases, as well as the timing and drilling of each well.

During the nine months ended September 30, 2006, we participated in the drilling of four gross (2.1 net) exploratory wells at a cost of approximately $1.5 million and incurred total capital expenditures of approximately $1.9 million for all exploration activities.

Oil and Natural Gas Reserves

At December 31, 2005, our estimated net proved reserves were 18.8 million Boe, of which 60% was crude oil, 30% was natural gas, and 10% was NGLs, with a PV-10 Value of approximately $345.5 million before income taxes. Our estimated proved developed reserves comprised 70% of our total proved reserves, and our reserve life for total proved reserves was approximately 15 years.

The following table summarizes the estimates of our historical net proved reserves and the related present values of such reserves at the dates shown. The reserve and present value data for our oil and natural gas properties as of December 31, 2005 was prepared by the independent petroleum engineering firms of

46

Williamson Petroleum Consultants, Inc. and Forrest A. Garb & Associates. Our management believes that for each $1.00 per Boe increase or decrease in the price of oil and natural gas, the PV-10 Value of our proved reserves at December 31, 2005 would increase or decrease, as the case may be, by $8.7 million.

Estimated quantities of proved reserves and future net revenues therefrom are affected by oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the control of the producer. The reserve data set forth in this report represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revisions based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors, which revisions may be material. The PV-10 Value of our proved oil and natural gas reserves does not necessarily represent the current or fair market value of such proved reserves, and the 10% discount factor may not reflect current interest rates, our cost of capital or any risks associated with the development and production of our proved oil and natural gas reserves. Proved reserves include proved developed and proved undeveloped reserves.

	As of December 31,
	2003		2004		2005
Reserve Data:
Proved developed reserves:
Oil (MBbls)		2,151		6,198		7,337
Natural gas (MMcf)		26,237		31,048		26,752
Natural gas liquids (MBbls)(1)		—		1,611		1,396
Total (MBoe)		6,524		12,984		13,192
PV-10 Value (in thousands)	$	84,781	$	164,007	$	245,107
Proved reserves:
Oil (MBbls)		2,322		10,667		11,199
Natural gas (MMcf)		34,567		38,195		34,234
Natural gas liquids (MBbls)(1)		—		2,087		1,891
Total (MBoe)		8,083		19,120		18,796
PV-10 Value (in thousands)	$	104,570	$	236,201	$	345,501
Prices used in calculating PV-10 Value:
$/Bbl (Oil)		29.25		40.25		58.63
$/Mcf		6.17		6.02		9.14
$/Bbl (NGL)		—		27.56		35.89

(1) Approximately 16.3% of our estimated proved reserves of NGLs at December 31, 2005, result from our equity ownership in the Electra Gas Plant.

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The following is a summary of the standardized measure of discounted net cash flows using methodology provided for in Statement of Financial Accounting Standard No. 69, related to our estimated proved oil and natural gas reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves were computed using oil and natural gas prices as of the end of the period presented. Future development and production costs attributable to the proved reserves were estimated assuming that existing conditions would continue over the economic lives of the individual leases and costs were not escalated for the future. Estimated future income tax expenses were calculated by applying future statutory tax rates (based on the current tax law adjusted for permanent differences and tax credits) to the estimated future pretax net cash flows related to proved oil and natural gas reserves, less the tax basis of the properties involved. For further information regarding the standardized measure of discounted net cash flows related to our estimated proved oil and natural gas reserves for the years ended December 31, 2003, 2004 and 2005, please review note R in the notes to our year-end 2005 financial statements appearing elsewhere in this prospectus.

The standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves at December 31 is summarized as follows:

	Year ended December 31,
	2003			2004			2005
	(in thousands)
Future cash inflows	$	281,149		$	711,781		$	1,037,337
Future production costs		(70,644	)		(247,314	)		(336,048	)
Future development costs		(9,534	)		(36,495	)		(45,271	)
Future income tax expenses		(69,787	)		(136,669	)		(219,640	)
Future net cash flows		131,184			291,303			436,418
10% annual discount for estimated timing of cash flows		(63,469	)		(129,983	)		(209,758	)
Standardized measure of discounted future net cash flows	$	67,715		$	161,320		$	226,660

In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Except to the extent we acquire properties containing proved reserves or conduct successful exploration and development activities, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring additional reserves.

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Net Production, Unit Prices and Costs

The following table presents certain information with respect to our oil and natural gas production and prices and costs attributable to all oil and natural gas properties owned by us for the periods shown. Average realized prices reflect the actual realized prices received by us, before and after giving effect to the results of our derivative contracts. Our derivative contracts are financial, and our production of oil, natural gas and NGLs, and the average realized prices we receive from our production, are not affected by our derivative contracts.

	Year ended December 31,								Nine months Ended September 30, 2006
	2003		2004			2005
Production volumes:
Oil (MBbls)		277		178			787			592
Natural gas liquids (MBbls)		5		12			170			103
Natural gas (MMcf)		2,334		1,928			2,681			1,761
Total (MBoe)		671		511			1,405			989
Average realized prices (before effects of derivative contracts):
Oil (per Bbl)	$	29.47	$	37.63		$	53.75		$	63.80
Natural gas liquids (per Bbl)		16.94		26.41			36.33			41.89
Natural gas (per Mcf)		5.06		5.69			6.61			6.22
Total per Boe		29.89		35.14			47.16			53.66
Effect of settlement of derivative contracts:
Oil (per Bbl)	$	—	$	(4.48	)	$	(1.40	)	$	(6.34	)
Natural gas liquids (per Bbl)		—		—			—			—
Natural gas (per Mcf)		—		.05			(1.04	)		(0.10	)
Total per Boe		—		(1.37	)		(2.78	)		(3.98	)
Average realized prices (after effects of derivative contracts):
Oil (per Bbl)	$	29.47	$	33.15		$	52.35		$	57.46
Natural gas liquids (per Bbl)		16.94		26.41			36.33			41.89
Natural gas (Per Mcf)		5.06		5.74			5.57			6.12
Total per Boe		29.89		33.77			44.38			49.68
Expenses (per Boe):
Oil and natural gas production taxes	$	2.10	$	2.47		$	2.36		$	2.56
Oil and natural gas production expenses		5.26		7.04			11.46			13.38
Amortization of full cost pool		5.64		5.89			8.93			9.63
General and administrative		9.44		12.90			6.13			6.42

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Acquisition, Development and Exploration Capital Expenditures

The following table presents information regarding our net costs incurred in our acquisitions of proved and unproved properties, and our development and exploration activities:

	Year ended December 31,						Nine months Ended September 30, 2006
	2003		2004		2005
	(in thousands)
Proved property acquisition costs	$	—	$	96,819	$	155	$	4,483
Unproved property acquisition costs		—		—		—		757
Development costs		5,056		5,173		11,864		14,393
Exploration costs		202		727		1,507		1,896
Total costs incurred	$	5,258	$	102,719	$	13,526	$	21,529

Finding Costs

The following table sets forth the estimated proved reserves we acquired or discovered, including revisions of previous estimates, during each stated period. In calculating finding costs, we include acquisition costs related to proved and unproved property acquisitions, exploration costs and development costs that resulted in reserve additions.

	Year ended December 31,
	2003	2004	2005
Proved reserves acquired/discovered (MBoe)	319	13,704	1,323
Total cost per Boe of reserves acquired/discovered	$4.01	$5.85	$11.91

Producing Wells

The following table sets forth the number of productive wells in which we owned an interest as of September 30, 2006. Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline connections or connection to production facilities. Wells that we complete in more than one producing horizon are counted as one well.

	Gross	Net
Oil	1,927	1,349
Natural gas	268	122
Total	2,195	1,471

Acreage

The following table sets forth our developed and undeveloped gross and net leasehold acreage, including options to acquire leasehold acreage, as of September 30, 2006:

	Gross	Net
Developed	104,199	38,248
Undeveloped	131,563	31,908
Total	235,762	70,156

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Approximately 90% of our net acreage was located in our core areas as of September 30, 2006. Our undeveloped acreage includes leased acres 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 or not such acreage is held by production or contains proved reserves. A gross acre is an acre in which we own an interest. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres.

Drilling Activities

During the periods indicated, we drilled or participated in drilling the following wells:

	Year Ended December 31,						Nine Months Ended September 30, 2006 (1)
	2003		2004		2005
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive	1	0.5	23	16.3	66	58.1	59	58.5
Non-productive	—	—	1	0.3	—	—	1	0.3
Exploratory wells:
Productive	3	0.3	1	0.3	1	0.3	2	0.6
Non-productive	—	—	4	0.5	—	—	2	1.5
Total	4	0.8	29	17.3	67	58.3	64	60.9

(1) Does not include wells drilling or awaiting completion as of September 30, 2006.

Oil and Natural Gas Marketing and Derivative Activities

During the nine months ended September 30, 2006, two purchasers accounted for approximately 73% of our oil and natural gas revenue. Shell Trading-US accounted for $31.8 million, or 60%, and Dynegy (now, Targa Midstream Services, or Targa) accounted for $6.9 million, or 13%, of our oil and natural gas revenue for that period. No other purchaser accounted for 10% or more of our oil and natural gas revenue during the nine months ended September 30, 2006. Our agreement with Shell Trading-US, or STUSCO, which covers all of our north Texas oil production, through June 30, 2006 provided for payment, on a per barrel basis, of a price equal to Koch’s posted price for West Texas Intermediate Crude, plus Platt’s Trade-month P+ (a fluctuating premium based on refinery demand), minus $1.15. Effective July 1, 2006, we negotiated a new price of STUSCO WTI plus $1.50. For the month of September 2006, the sales price was $62.50 per Bbl. The agreement is on a month-to-month basis and is cancelable by either party upon 30 days’ prior written notice. Our gas purchase contract with Targa, which expires February 1, 2013, covers our predominately natural gas producing properties located in Jack and Wise Counties, Texas. Under the terms of the contract, Targa takes delivery of our gas in the field and transports the gas to the nearby Chico Plant where it is processed for the extraction of liquefiable hydrocarbons. Targa pays us 85% of the weighted average price received by Targa for the sale of natural gas and natural gas liquids attributable to the gas delivered by us. There are other purchasers in the fields where our production sold to these two purchasers is produced and marketed, and such other purchasers would be available to purchase our production should any of these two purchasers discontinue operations. We have no reason to believe that any such cessation is likely to occur. However, if the Chico Plant were to cease operations, whether for mechanical, financial or other reasons, such cessation could materially and adversely affect our cash flow

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from operations on a temporary basis, until a new purchaser could install the necessary facilities to take delivery of our natural gas production in the area. We have no reason to believe that any such cessation is likely to occur.

To reduce exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow, we periodically utilize various derivative strategies to manage the price received for a portion of our future oil and natural gas production. The notional volumes under our derivative contracts do not exceed our expected production. Our derivative strategies customarily involve the purchase of put options to provide a price floor for our production, put/call collars that establish both a floor and a ceiling price to provide price certainty within a fixed range, put/call call collars that establish a secondary floor above the put/call collar ceiling or swap arrangements that establish an index-related price above which we pay the derivative counterparty and below which we are paid by the derivative counterparty. These contracts allow us to predict with greater certainty the effective oil and natural gas prices to be received for our production and benefit us when market prices are less than the strike prices or fixed prices under our derivative contracts. However, we will not benefit from market prices that are higher than the strike or fixed prices in these contracts for our hedged production.

Our derivative positions at December 31, 2006 are shown in the following table:

	Crude Oil (Bbls)						Natural Gas (MMBtu)
	Floors			Ceilings			Floors			Ceilings
	Per Day	Price		Per Day	Price		Per Day	Price		Per Day	Price
Collars
2007	1,500	$	52.67	1,500	$	73.24	4,177	$	7.48	4,177	$	11.58
2008	950		53.69	950		86.08	4,000		6.87	4,000		13.53
Secondary Floors
2007							4,000	$	12.00

Crude oil and natural gas contracts cover each month of 2007 and natural gas secondary floors for 2007 are for April through October. Crude oil contracts and natural gas contracts for 2008 are for January through December. For the fourth quarter of 2006, we had a realized gain from our derivative activities of approximately $228,000. For the nine months ended September 30, 2006 our average daily production was 2,169 Bbls of oil, 6,452 Mcf of natural gas, and 376 Bbls of NGLs.

Competition

The oil and natural gas industry is highly competitive. We compete for the acquisition of oil and natural gas properties, primarily on the basis of the price to be paid for such properties, with numerous entities including major oil companies, other independent oil and natural gas concerns and individual producers and operators. Many of these competitors are large, well-established companies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Title to Properties

We believe that we have satisfactory title to our properties in accordance with standards generally accepted in the oil and natural gas industry. As is customary in the oil and natural gas industry, we make only a cursory review of title to farmout acreage and to undeveloped oil and natural gas leases upon execution of any contracts. Prior to the commencement of drilling operations, a title examination is conducted and curative work is performed with respect to significant defects. To the extent title opinions or

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other investigations reflect title defects, we, rather than the seller of the undeveloped property, typically are responsible to cure any such title defects at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent for us to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We have obtained title opinions or reports on substantially all of our producing properties. Prior to completing an acquisition of producing oil and natural gas leases, we perform a title review on a material portion of the leases. Our oil and natural gas properties are subject to customary royalty interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties.

Facilities

Our executive and operating offices are located at Suite 650, Meridian Tower, 5100 E. Skelly Drive, Tulsa, Oklahoma 74135 which we occupy under a lease with a remaining term ending in June 2008, at an annual rental of $288,728, subject to escalations for taxes and utilities. We also lease a small office in Houston. We believe that our facilities are adequate for our current needs.

Regulation

General. Various aspects of our oil and gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and gas industry and our individual members.

Regulation of Sales and Transportation of Natural Gas. The Federal Energy Regulatory Commission, or the FERC, regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the federal government has regulated the prices at which natural gas can be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation and proposed regulation designed to increase competition within the natural gas industry, to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers and to establish the rates interstate pipelines may charge for their services. Similarly, the Oklahoma Corporation Commission and the Texas Railroad Commission have been reviewing changes to their regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes being considered by these federal and state regulators would affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters; however, we do not believe that any actions taken will have an effect materially different than the effect on other natural gas producers with which we compete.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Oil Price Controls and Transportation Rates. Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The price we receive from the sale of these products may be affected by the cost of transporting the products to market.

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Environmental. Our oil and natural gas operations are subject to pervasive federal, state, and local laws and regulations concerning the protection and preservation of the environment (e.g., ambient air, and surface and subsurface soils and waters), human health, worker safety, natural resources and wildlife. These laws and regulations affect virtually every aspect of our oil and natural gas operations, including our exploration for, and production, storage, treatment, and transportation of, hydrocarbons and the disposal of wastes generated in connection with those activities. These laws and regulations increase our costs of planning, designing, drilling, installing, operating, and abandoning oil and natural gas wells and appurtenant properties, such as gathering systems, pipelines, and storage, treatment and salt water disposal facilities.

We have expended and will continue to expend significant financial and managerial resources to comply with applicable environmental laws and regulations, including permitting requirements. Our failure to comply with these laws and regulations can subject us to substantial civil and criminal penalties, claims for injury to persons and damage to properties and natural resources, and clean-up and other remedial obligations. Although we believe that the operation of our properties generally complies with applicable environmental laws and regulations, the risks of incurring substantial costs and liabilities are inherent in the operation of oil and natural gas wells and appurtenant properties. We could also be subject to liabilities related to the past operations conducted by others at properties now owned by us, without regard to any wrongful or negligent conduct by us.

We cannot predict what effect future environmental legislation and regulation will have upon our oil and natural gas operations. The possible legislative reclassification of certain wastes generated in connection with oil and natural gas operations as “hazardous wastes” would have a significant impact on our operating costs, as well as the oil and natural gas industry in general. The cost of compliance with more stringent environmental laws and regulations, or the more vigorous administration and enforcement of those laws and regulations, could result in material expenditures by us to remove, acquire, modify, and install equipment, store and dispose of wastes, remediate facilities, employ additional personnel, and implement systems to ensure compliance with those laws and regulations. These accumulative expenditures could have a material adverse effect upon our profitability and future capital expenditures.

Regulation of Oil and Gas Exploration and Production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells, and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties.

Legal Proceedings

From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. Other than the pending lawsuit described below, we are not involved in any legal proceedings, nor are we a party to any pending or threatened claims, that could reasonably be expected to have a material adverse effect on our financial condition or results of operations.

In the pending lawsuit, RAM Energy, together with certain of its subsidiaries and affiliates, are defendants in the litigation entitled Sacket v. Great Plains Pipeline Company, et al., in the District Court of Woods County, Oklahoma (Case No. CJ-2002-70). This is a putative class action case filed by a landowner alleging that the royalty payments to landowners for oil and natural gas produced from wells connected to a RAM Energy subsidiary’s natural gas, oil and saltwater pipeline system in Woods, Alfalfa and Major Counties, Oklahoma, were calculated on a price that was lower than the price at which the production from

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the related wells was resold by the subsidiary. RAM Energy and its subsidiaries sold their interests in the affected leases effective December 1, 2001. The plaintiff filed the lawsuit as a class action on behalf of himself and all other royalty owners under leases held by any of the defendants upon which wells were connected to the system. Plaintiff seeks unspecified damages for breach of contract, tortious breach of implied covenants and breach of fiduciary duty, together with an accounting, imposition of a constructive trust, a permanent injunction, punitive damages and recovery of litigation costs and fees. We believe that a fair and proper accounting was made to the royalty owners for production from the affected leases. We have filed a response denying the allegations made by the plaintiff. On December 20, 2006, the Court announced that it would enter an order certifying the plaintiff’s proposed class. We and the other defendants will appeal that order. Irrespective of whether the order certifying a class is affirmed on appeal, we intend to strenuously defend against any substantive claims made in the litigation.

Employees

At September 30, 2006, we had 99 employees, 11 of whom were administrative, accounting or financial personnel and 88 of whom were technical and operations personnel. Our exploration staff includes two exploration geologists and two exploration landmen. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreement and we have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.

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MANAGEMENT

Our board of directors and executive officers are:

Name	Age	Position
Larry E. Lee	58	Chairman, President and Chief Executive Officer
John M. Longmire	64	Senior Vice President and Chief Financial Officer
Larry G. Rampey	62	Senior Vice President
Drake N. Smiley	59	Senior Vice President
John L. Cox	56	Vice President, Secretary and Treasurer
Robert E. Phaneuf	60	Vice President — Corporate Development
Sean P. Lane	48	Director
Gerald R. Marshall	72	Director
John M. Reardon	64	Director

Larry E. Lee has served as our chairman, president and chief executive officer since May 2006. He is a founder of RAM Energy and has served as its president and, with the exception of the period from June 1992 to November 1997, when he served as chief operating officer, he has served as its chief executive officer since September 1987. Mr. Lee became chairman of the board of RAM Energy in October 2005. Mr. Lee has been active in the oil and gas industry since 1976. Mr. Lee worked for the private companies of Goldman Enterprises and Kerr Consolidated before developing the RAM Energy companies in 1984. He served in the public sector as Budget Director for the city of Oklahoma City from 1971 to 1976, and was a member of the staff of Governor David Boren during 1976. Mr. Lee is a Wildcatter member of the Oklahoma Independent Petroleum Association and a member of the Independent Petroleum Association of America, having previously served as director. Mr. Lee is a member of the Board of Trustees, serves as Chairman of the Finance Committee, is a member of the Executive Committee, and is Chairman Elect of the Board of Trustees for the Philbrook Museum of Art. He is also a member of the Board of Directors and Vice Chairman of the Oklahoma Heritage Association, where he serves on the Executive and Finance Committees. Mr. Lee serves as a member of the Executive Board of the Indian Nations Council of the Boy Scouts of America. He is a lifetime member of World Presidents’ Organization. Mr. Lee received his B.B.A. in finance from the University of Oklahoma.

John M. Longmire has been our chief financial officer and a senior vice president since May 2006 and has been chief financial officer of RAM Energy since August 1994 and a senior vice president since December 1997. Previously, Mr. Longmire was vice president of RAM Energy from August 1994 until December 1997 and was its controller from March 1990 until August 1994. Mr. Longmire has 30 years experience in various financial management positions in the oil and gas industry. Prior to joining RAM Energy in 1990, Mr. Longmire held various positions with Texas International Company, Amarex, Inc. and Union Oil Company of California. Mr. Longmire is a Certified Public Accountant and received his B.S. in 1973 from California State University at Los Angeles.

Larry G. Rampey has been our senior vice president since May 2006 and a senior vice president of RAM Energy since February 1998, previously serving as vice president of operations since May 1989. Mr. Rampey has 30 years of experience in the management of both domestic and international oil and gas properties. From 1972 until May 1989, Mr. Rampey was employed by Reading & Bates Petroleum Co., holding positions of vice president of international operations and vice president of domestic operations. Mr. Rampey was employed by Amoco prior to joining Reading & Bates. Mr. Rampey is a member of the Society of Petroleum Engineers and the Oklahoma Independent Petroleum Association. Mr. Rampey received his B.S. in Industrial Engineering from Oklahoma State University.

Drake N. Smiley has been our senior vice president of land and exploration since May 2006 and has held a similar position with RAM Energy since January 1998. Mr. Smiley served as vice president of land,

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legal and business development of RAM Energy from February 1997 until December 1997. Previously, Mr. Smiley was employed by Reading & Bates, serving as manager of land. Before Reading & Bates, he was employed by Cities Service Company. In June of 1994, Mr. Smiley accepted the position of vice president, land with Continental Resources, Inc. in Enid, Oklahoma. Mr. Smiley has 28 years of experience in the petroleum industry and is a member of the Oklahoma and Tulsa County Bar Associations, the Tulsa and American Associations of Petroleum Landmen and the Oklahoma Independent Petroleum Association. He is a Phi Beta Kappa graduate of the University of Missouri, where he also received his Juris Doctorate.

John L. Cox has been our vice president, secretary and treasurer since May 2006, vice president RAM Energy since June 2005 and secretary and treasurer of RAM Energy since November 2005. Prior to joining RAM Energy, Mr. Cox served as chief financial officer of Cannon Energy, Inc. from March 2003 until June 2005. Mr. Cox previously was controller for Mannix Oil and Gas, Inc. from February 2001 until March 2003 and controller/bankruptcy accountant for the bankruptcy trustee for Bristol Resources Corporation from 1997 to February 2001. Mr. Cox was also a vice president and chief financial officer for Latex Petroleum from 1994 to 1997, controller of Panada Exploration, Inc. from 1990 to 1994, and controller/ manager of financial reporting for Reading & Bates Petroleum Co. from 1976 to 1989. Mr. Cox is a Certified Public Accountant and received a B.S. in Accounting from Oklahoma City University.

Robert E. Phaneuf has been our vice president-corporate development since May 2006 and served in a similar capacity with RAM Energy since March 2006. From September 1995 until February 2006, Mr. Phaneuf served as vice president of corporate development at Vintage Petroleum Corporation. From 1994 until September 1995, he was employed in the corporate finance group at Arthur Andersen LLP. From 1972 to 1976, Mr. Phaneuf was an investment advisor with First International Investment Management Company. From 1976 to 1994, Mr. Phaneuf served as an energy analyst in the research department of several investment banking and brokerage firms, including Schneider, Bernet & Hickman from 1976 to 1978; as Vice President of Kidder, Peabody & Co. from 1978 to 1988; as Senior Vice President — Energy Research, Rauscher, Pierce, Refsnes, Inc. from 1988 to 1993; and as Senior Vice President — Head of Energy Research Group, Kemper Securities, from 1993 to 1994. Mr. Phaneuf received a B.A. in psychology and an MBA in Finance from the University of Texas at Austin.

Sean P. Lane was appointed to our board in May 2006. He has served as a Managing Member of Kinsale Advisors LLC since January 2003, providing business and risk management advisory services to companies and investors in the energy, environmental and technology industries. From May 1999 until December 2002, Mr. Lane was an executive vice president, chief administrative officer, general counsel and director of beenz.com inc. a global internet currency business. Mr. Lane served as a managing director of Liberty Power Investments, LLC, an international electric power project development, finance and acquisition firm from December 1992 until May 1999. Mr. Lane has also served as an executive of Compania Boliviana de Energia Electrica, S.A., the leading Bolivian electric utility, as well as The Henley Group, Inc., Wheelabrator Technologies, Inc. and Catalyst Energy Corporation, all publicly traded firms with significant investments in the U.S. or international independent power and environmental industries. Mr. Lane received his J.D. from Georgetown University Law Center and a Bachelor’s degree in Political Economy and History from Fordham University.

Gerald R. Marshall was appointed to our board in May 2006 and has been a director of RAM Energy since December 1997. Mr. Marshall was vice chairman of the Midland Group of Oklahoma City, Oklahoma, which includes Midland Mortgage Co., MidFirst Bank, Midland Asset Management Co. and Home Shield Insurance Co., from October 1996 to March 2003 and served as a director of MidFirst Bank from 1993 until March 2003, and served as its chief credit officer from October 1996 until March 2001. From 1990 until 1995, Mr. Marshall was chairman, chief executive officer and principal owner of RAM

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Management Associates, an asset management contractor for the Resolution Trust Corporation. From 1989 until 1990, Mr. Marshall served as a special consultant to Worthen Banking Corporation of Arkansas. From 1987 until 1989, Mr. Marshall was interim chief executive officer of an insolvent savings and loan association in Little Rock, Arkansas, pending federal resolution. From September 1984 until November 1986, Mr. Marshall served as chairman of the board and chief executive officer of Bank of Oklahoma, Oklahoma City, N.A and from August 1981 to April 1984, Mr. Marshall served as president and chief executive officer of Goldman Enterprises, a privately owned, diversified group of companies. Prior to August 1981, Mr. Marshall served as chairman and chief executive officer of Capital Bank, N.A. of Houston, Texas and was a senior vice president of its then parent company, Mercantile Texas Corporation. Prior to 1981, Mr. Marshall served as president and director of The First National Bank and Trust Company of Oklahoma City; as executive vice president of First National Bank in Dallas, and as president of Liberty National Bank and Trust Company of Oklahoma City. Mr. Marshall received a B.S. in Finance and Accounting from the University of Oklahoma.

John M. Reardon was appointed to our board in May 2006 and has served as a director of RAM Energy since October 2005. He previously was a member of the RAM Energy board from January 1998 to May 2002. Mr. Reardon has been market president of Union Bank of California, in Valencia, California, since November 2002. From August 1994 until November 2002, Mr. Reardon was president and chief executive officer of Valencia National Bank, Santa Clarita, California. From 1991 to August 1994, Mr. Reardon was executive vice president of Ramco Oil and Gas, Inc. and RAM Management Associates, Inc. Mr. Reardon was a senior vice president of Wells Fargo Bank, Los Angeles, California from 1987 to 1991. Previously, he served as chairman, president and chief executive officer of Southwestern Bank and Trust Company, Oklahoma City; executive vice president of The First National Bank and Trust Company of Oklahoma City, Oklahoma; and vice president of Liberty National Bank and Trust Company, Oklahoma City, Oklahoma. Mr. Reardon is currently president of the board of directors of the Santa Clarita Valley Boys & Girls Club Foundation. In 2000, Mr. Reardon was presented the Entrepreneur of the Year Award by Ernst & Young and he is a life member in the Entrepreneur of the Year Award Hall of Fame. Mr. Reardon has served as a director of Gene Autry Western Heritage Museum, Los Angeles, California; as a member and officer of several committees and sub-committees of the Housing and Real Estate Finance Committee of the American Bankers Association; and as a director of the Oklahoma Bankers Association. Mr. Reardon has served on the faculty of the University of Oklahoma School of Commercial Banking; Southwestern Graduate School of Banking, Southern Methodist University, Dallas, Texas; the Real Estate Finance School and the National Commercial Lending School of the American Bankers Association; and the Secured Lending School of the Oklahoma Bankers Association. He served as Chairman of the Federal Government Relations Committee of the Oklahoma Bankers Association and as a member of the board of directors of the Chair of Banking, the College of Business of the University of Oklahoma. He has also served as an advisory director of Oklahoma State University and a member of the Oklahoma State Advisory Council of the United States Small Business Administration, and President. Mr. Reardon received a B.S. in business from Oklahoma State University and is a graduate of the Southwestern Graduate School of Banking, Southern Methodist University in Dallas, Texas.

Independence of Directors

We adhere to the rules of Nasdaq in determining whether a director is independent. Our board of directors also consults with our counsel to ensure that the board’s determinations are consistent with those rules and all relevant securities and other laws and regulations regarding the independence of directors. The Nasdaq listing standards define an “independent director” generally as a person, other than an officer of a company, who does not have a relationship with the company that would interfere with the director’s

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exercise of independent judgment. Consistent with these considerations, our board of directors has affirmatively determined that Messrs. Lane, Marshall and Reardon are the independent directors. Mr. Lee is not independent.

Board Committees

Our board of directors currently has an audit committee, a compensation committee, and a nominating and governance committee. Our board may establish other committees from time to time to facilitate our management.

Audit Committee. The principal functions of the audit committee are to assist the board in monitoring the integrity of our consolidated financial statements, the independent auditor’s qualifications and independence, the performance of our independent auditors and our compliance with legal and regulatory requirements. The audit committee will have the sole authority to retain and terminate our independent auditors and to approve the compensation paid to our independent auditors. The audit committee also will be responsible for overseeing our internal audit function. The audit committee currently consists of Messrs. Lane, Marshall and Reardon, with Mr. Marshall acting as the Chairman. Messrs. Lane, Marshall and Reardon are “independent,” and Mr. Marshall is our audit committee financial expert, under the listing standards of the Nasdaq and under SEC rules and regulations.

Compensation Committee. The principal functions of the compensation committee are to determine awards to employees of stock or other equity compensation, establish performance criteria for and evaluate the performance of the chief executive officer and approve compensation of all senior executives and directors. The compensation committee is currently comprised of Messrs. Lane, Marshall and Reardon, with Mr. Reardon acting as the Chairman. None of the members of our compensation committee is one of our officers or an officer of any of our subsidiaries.

Nominating and Governance Committee. Our board of directors has established a nominating and governance committee. The members are Messrs. Marshall, Lane and Reardon, with Mr. Lane acting as Chairman. Each is independent director under Nasdaq listing standards. The nominating and governance committee is responsible for overseeing the selection of persons to be nominated to serve on our board of directors. The nominating and governance committee will consider persons identified by our members, management, stockholders, investment bankers and others. During the period ending immediately after our 2008 annual meeting, the nominees for our board of directors will be determined pursuant to the terms of a voting agreement (described below) and approved by the nominating and governance committee.

We do not have any restrictions on stockholder nominations under our certificate of incorporation or by-laws. However, any stockholder nominations must be received by us not less than sixty (60) days nor more than ninety (90) days prior to the annual meeting; provided however, that in the event that less than seventy (70) days notice or prior public disclosure of the date of the meeting is given or made to stockholders, notice by the stockholder, to be timely, must be received no later than the close of business on the tenth (10th) day following the day on which such notice of the date of the meeting was mailed or such public disclosure was made, whichever first occurs. The stockholder’s notice to our secretary shall set forth (i) as to each person whom the stockholder proposes to nominate for election or reelection as a director, (a) the name, age, business address and residence address of the person, (b) the principal occupation or employment of the person, (c) the class and number of shares of our capital stock which are beneficially owned by the person, and (d) any other information relating to the person that is required to be disclosed in solicitations for proxies for election of directors pursuant to the rules and regulations of the SEC under Section 14 of the Securities Exchange Act of 1934, as amended, and (ii) as to the stockholder giving the notice (a) the name and record address of the stockholder and (b) the class and number of shares of our capital stock which is beneficially owned by the stockholder. We may require any proposed nominee to furnish such other information as may reasonably be required by us to determine the eligibility of such proposed nominee to serve as a director.

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Election of Directors; Voting Agreement

As provided in the merger agreement, the former stockholders of RAM Energy, on the one hand, and Lawrence S. Coben and Isaac Kier (founders of Tremisis), on the other hand, entered into a voting agreement pursuant to which they have agreed to vote for the other’s designees as our directors until immediately following the election that will be held in 2008 as follows:

Ÿ in the class to stand for reelection in 2007-Larry E. Lee and Gerald R. Marshall; and

Ÿ in the class to stand for reelection in 2008-John M. Reardon and Sean P. Lane.

Pursuant to the voting agreement, the former stockholders of RAM Energy shall designate three directors and Messrs. Coben and Kier shall designate one director. Messrs. Marshall, Lee and Reardon are all designees of the former RAM Energy stockholders. Mr. Lane is a designee of Messrs. Coben and Kier.

Executive Compensation

Summary Compensation Table

The following table sets forth for the years indicated the compensation of our chief executive officer and each of our other most highly compensated executive officers as of December 31, 2005.

		Annual Compensation						Long-Term Compensation
	Year	Salary ($)		Bonus ($)		Other Annual Compensation ($)(1)		All Other Compensation ($)(2)(3)
Larry E. Lee	2005	$	450,000	$	300,000	$	10,561	$	20,922
President and Chief	2004		450,000		400,000		10,544		19,128
Executive Officer	2003		450,000		475,000		9,354		16,965
Larry G. Rampey	2005	$	192,850	$	75,000	$	10,109	$	20,922
Senior Vice President	2004		164,300		87,500		10,544		19,128
	2003		153,700		70,000		9,354		16,965
John M. Longmire	2005	$	180,650	$	75,000	$	10,561	$	20,880
Senior Vice President	2004		153,700		87,500		10,544		19,055
and Chief Financial	2003		153,700		70,000		9,354		16,898
Officer
Drake N. Smiley	2005	$	180,650	$	75,000	$	13,687	$	20,837
Senior Vice President	2004		153,700		87,500		13,471		18,983
	2003		153,700		70,000		12,004		16,831

(1) The amounts specified represent premiums paid on health insurance policies. Other personal benefits did not exceed the lesser of $50,000 or 10% of total annual salary and bonus for any executive officer. No other annual compensation was paid.

(2) The amounts specified represent matching contributions made by us to the account of the executive officer under our 401(k) Profit Sharing Plan of $18,000 for 2005, $16,000 for 2004 and $14,000 for 2003.

(3) Includes premiums paid on policies of life insurance owned by each officer as follows: $798 for 2005 and $828 for both 2003 and 2004.

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Directors’ Compensation

We pay our non-employee directors an annual fee of $75,000, of which at least $40,000 is payable in the form of restricted stock awards under our 2006 Long-Term Incentive Plan discussed below. Mr. Lee, as our president and chief executive officer, does not receive any director’s fee. We reimburse all of our directors for travel and other expenses. On May 8, 2006, we made restricted stock awards of 10,000 shares to each of Messrs. Lane, Marshall and Reardon, which fully vested on June 8, 2006.

Employment Agreement

In connection with the consummation of the merger in May 2006, we entered into an employment agreement with Larry E. Lee, under the terms of which Mr. Lee will serve as our president and chief executive officer for a term of three years. The employment agreement provides that Mr. Lee will receive an annual base salary of $450,000. In addition, we pay the annual premium on a term life insurance policy owned by Mr. Lee, the costs of his annual physical examinations, and certain country club dues and expenses. Mr. Lee also may be awarded a bonus for any fiscal year during the employment term, either pursuant to an incentive compensation plan maintained by us or as otherwise may be determined by our board of directors.

The employment agreement provides that, in the event of the termination of Mr. Lee’s employment by us without Cause (as defined in the employment agreement) or by Mr. Lee for Good Reason (as defined in the employment agreement), we will pay him a lump sum equal to two times his base salary plus a prorated bonus. In addition, we shall continue benefits to him and/or his family equal to those which would have been provided to them in accordance with the plans, programs, practices and policies if his employment had not been terminated.

If Mr. Lee’s employment is terminated by reason of his death or disability, we shall pay him a lump sum equal to his then current base salary for twelve months or such shorter period as may remain in the employment term, plus a prorated bonus.

The employment agreement contains certain restrictive covenants that prohibit Mr. Lee from disclosing information that is confidential to us and our subsidiaries and generally prohibits him, during the employment term and for one year thereafter, from soliciting or hiring our employees and those of our subsidiaries. The employment agreement does not contain any restrictive covenants that otherwise limit Mr. Lee’s ability to compete with us and our subsidiaries following his employment.

2006 Long-Term Incentive Plan

Our 2006 Long-Term Incentive Plan, or the 2006 Plan, became effective in May 2006 upon consummation of the merger.

The purposes of our 2006 Plan are to create incentives designed to motivate our employees to significantly contribute toward our growth and profitability, to provide our executives, directors and other employees, and persons who, by their position, ability and diligence, are able to make important contributions to our growth and profitability, with an incentive to assist us in achieving our long-term corporate objectives, to attract and retain executives and other employees of outstanding competence, and to provide such persons with an opportunity to acquire an equity interest in us.

We may grant incentive and non-qualified stock options, stock appreciation rights, performance units, restricted stock awards and performance bonuses, which we refer to collectively as awards, to our officers and key employees, and those of our subsidiaries. In addition, the 2006 Plan authorizes the grant of non-qualified stock options and restricted stock awards to our directors and to any independent contractors and

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consultants who by their position, ability and diligence are able to make important contributions to our future growth and profitability. Generally, all classes of our employees are eligible to participate in our 2006 Plan.

We reserved 2,400,000 shares of our authorized common stock for issuance of awards to be granted pursuant to our 2006 Plan. Each share issued under an option or under a restricted stock award will be counted against this limit. Shares to be delivered at the time a stock option is exercised or at the time a restricted stock award is made may be available from authorized but unissued shares or from stock previously issued but which we have reacquired and hold in our treasury. In accordance with the 2006 Plan, no option can be granted at an exercise price less than the fair market value of our common stock on the date of grant.

In the event of any change in our outstanding common stock by reason of any reorganization, recapitalization, stock split, stock dividend, combination of shares, merger, consolidation, issuance of rights or other similar transactions, the number of shares of our common stock which may be issued upon exercise of outstanding options, and the exercise price of options previously granted under our 2006 Plan, will be proportionally adjusted to prevent any enlargement or dilution of the rights of holders of previously granted options as may be appropriate to reflect any such transaction or event.

On May 8, 2006, we made restricted stock awards of 10,000 shares of our common stock to each of Messrs. Marshall, Reardon and Lane, our non-management directors. At the same time, we made restricted stock awards of 100,000 restricted shares of our common stock to each of Messrs. Longmire, Rampey and Smiley, each of whom is one of our senior vice presidents. In each instance, the shares were issued under our 2006 Plan and became fully vested 30 days following issuance, at which time, each of Messrs. Longmire, Rampey and Smiley sold 32,700 shares back to us to cover income and other withholding taxes. On November 10, 2006, our Compensation Committee approved the grant of restricted stock awards under our 2006 Plan to 22 of our employees, aggregating 646,805 shares of our common stock. All of the awards are effective November 10, 2006 and vest ratably over a five-year period. Two of our executive officers received awards. Mr. Robert Phaneuf, vice president — corporate development, received an award of 75,100 shares, and Mr. John L. Cox, vice president, secretary and treasurer, received an award of 69,170 shares. As a result of these awards, 1,423,195 shares of our common stock remain reserved for issuance under our 2006 Plan.

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SELLING STOCKHOLDER AND SECURITY OWNERSHIP OF

CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information regarding the beneficial ownership of our common stock as of December 31, 2006 by:

Ÿ the selling stockholder and each other person known by us to be the beneficial owner of more than 5% of our outstanding shares of common stock;

Ÿ each of our named executive officers;

Ÿ each of our directors; and

Ÿ all our current executive officers and directors as a group.

	Shares Beneficially Owned Prior to Offering					Shares Beneficially Owned After Offering
Name and Address of Beneficial Owner	Number     of Shares		Percent     of Class (1)		Shares Offered Hereby	Number of Shares	Percent of Class (1)
Larry E. Lee (2)(3)	12,555,187		38	%	—	12,555,187	30	%
Britani Talley Bowman (4)(5)	12,555,187		38	%	2,722,323	9,832,864	23	%
John M. Longmire (2)	67,300		*		—	67,300	*
Larry G. Rampey (2)	67,300		*		—	67,300	*
Drake N. Smiley (2)	67,300		*		—	67,300	*
Gerald R. Marshall (2)	15,000		*		—	15,000	*
John M. Reardon (2)	11,000		*		—	11,000	*
Sean P. Lane (6)	15,500	(7)	*		—	10,000	*
All directors and executive officers as a group (9 individuals)	12,942,857		39	%	—	12,942,857	30	%

 * Less than 1%

(1) The outstanding shares of common stock used to determine the percentage of shares beneficially owned by the designated stockholders do not include approximately 12,650,000 shares reserved for issuance upon the exercise of outstanding warrants and 825,000 shares of our common stock issuable upon the exercise of currently exercisable options to purchase 275,000 units, each unit consisting of one share of our common stock and warrants to purchase two shares of our common stock; an aggregate of 1,423,195 shares reserved for issuance upon the exercise of options that may be granted by us or awards that may be made under our 2006 Long-Term Incentive Plan, and a maximum of 1,769,510 shares issuable to the underwriters upon exercise of their over-allotment option.

(2) The business address of this person is 5100 E. Skelly Drive, Suite 650, Tulsa, Oklahoma 74135.

(3) Includes 500,000 shares owned by a family trust for the benefit of Mr. Lee’s family.

(4) Ms. Bowman’s business address is 3155 East 86th Street, Tulsa, Oklahoma 74137.

(5) These shares are held by Danish Knights, A Limited Partnership. Ms. Bowman beneficially owns 98.5% of Danish Knights and is the custodian for a 1.3% interest owned by her minor child. Dannebrog Corporation, the general partner of Danish Knights, owns the remaining 0.2% interest. Ms. Bowman is the president and sole director of Dannebrog Corporation. Accordingly, Ms. Bowman exercises voting and dispositive power over all shares held by Danish Knights.

(6) Mr. Lane’s business address is 520 Eighth Avenue, 7th Floor, New York, NY 10018.

(7) Includes warrants to purchase 5,500 shares of common stock that are currently exercisable.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Former Directors, Executive Officers and Principal Stockholders

Tremisis:

Tremisis consummated its initial public offering on May 18, 2004. Prior to its IPO, Tremisis issued an aggregate of 750,000 shares of its common stock to the stockholders as set forth below at a purchase price of approximately $0.033 per share. Subsequent to the issuance, and prior to its IPO, its board of directors authorized several forward splits of its common stock, effectively lowering the purchase price to $0.018 per share. The following share numbers have been adjusted to reflect these stock splits.

Name	Number of Shares	Relationship to Tremisis
Lawrence S. Coben	1,008,334	Chairman and Chief Executive Officer
Isaac Kier	183,334	Secretary, Treasurer and Director
David A. Preiser	91,666	Director
Jon Schotz	91,666	Director

These shares are being held in escrow with Continental Stock Transfer & Trust Company, as escrow agent, until May 2007 pursuant to an escrow agreement between Tremisis, the above stockholders and the escrow agent. These shares are not transferable except to such stockholders’ spouses, children or trusts established for their benefit, and will be released prior to May 2007 only if Tremisis liquidates or upon a subsequent transaction resulting in its stockholders having the right to exchange their shares for cash or other securities.

The holders of these shares are entitled to make up to two demands that we register these shares pursuant to a registration rights agreement dated April 27, 2004. In addition, these stockholders have certain “piggy-back” registration rights on registration statements filed either before or after the date on which these shares of common stock are released from escrow. We will bear the expenses incurred in connection with the filing of any such registration statements.

Commencing on Tremisis’ IPO through the consummation of the merger, Tremisis paid First Americas Management LLC a monthly fee of $3,500 for general and administrative services. First Americas Management was an affiliate of Isaac Kier, one of Tremisis’ directors.

During 2004, Lawrence S. Coben, a director, executive officer and principal stockholder of Tremisis, advanced $77,500 to Tremisis to cover expenses related to its IPO. This loan was repaid without interest in June 2004.

Current Directors, Executive Officers and Principal Stockholders

All ongoing and future transactions between us and any of our officers and directors or their respective affiliates will be on terms believed by us to be no less favorable than are available from unaffiliated third parties and will require prior approval in each instance by a majority of the members of our board who do not have an interest in the transaction.

In October 2004, our subsidiary, RAM Energy, agreed to purchase from KCS Energy an interest in an exploratory oil and gas prospect generated by KCS in the Arkoma Basin of Eastern Oklahoma, and to participate in the drilling of the first well to be drilled on the prospect. RAM Energy acquired a 30.0% interest in prospect, generally, and an additional 8.6% interest in the drillsite section for the initial test well. In November 2004, RAM Energy paid its 38.7% share in the estimated $1.2 million dry hole cost for the

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initial test well. In connection with its participation in the prospect, RAM Energy agreed to allow certain of its senior executive officers, managers, stockholders, an attorney and an independent geologist, to participate in the prospect for their own account by purchasing an aggregate 5% interest in the prospect at the same price paid by RAM Energy to KCS. Accepting participants included, among other officers and employees of RAM Energy, Messrs. Rampey and Smiley, both senior vice presidents of RAM Energy, Mr. Lee, president, CEO and a 50% stockholder of RAM Energy, and Dr. William W. Talley II, then Chairman of RAM Energy and principal owner of Danish Knights, a 50% stockholder of RAM Energy. Other participants included Forrest Fischer, John R. Frick, Jr., Brandon Lee, Sivad Corp., an entity in which Tully Davis is a beneficial owner, and Richard Erickson. Messrs. Fischer, Frick, Lee and Davis are non-officer employees of RAM Energy. In addition, David Stinson, an outside attorney, and an independent geologist under contract with RAM Energy, also participated. In November 2004, RAM Energy entered into a participation agreement with each of the participating parties pursuant to which such parties agreed to participate in the prospect and pay their respective shares of the costs (including dry hole costs) incurred in drilling and completing the initial well on the prospect and to subject their interests to an operating agreement for the further development of the prospect. The participation agreements provided that in order to facilitate billings, distribution of production revenues and other administrative matters, record title to the interests acquired by the participants would be held by REPCO, LLC, a limited liability company formed and owned 50% each by Mr. Lee and Danish Knights. REPCO was formed specifically for the purpose of holding title to the interests of the participating parties in the prospect and to facilitate their participation. In December 2004, RAM Energy assigned an undivided 5% interest in the prospect to REPCO, to hold as nominee for the participants, and the participants were invoiced by REPCO for their respective shares of acreage and dry hole costs on the initial test well. While REPCO is carried on the books of RAM Energy as the party liable for joint interest billings and as the party entitled to receive production revenues attributable to the interests owned by the participating parties, pursuant to the terms of the participation agreements, each participant is directly liable to RAM Energy for his proportionate share of such costs and is entitled to his proportionate share of such revenues. At December 31, 2004, the participating parties were indebted to RAM Energy in the amount of $9,169 representing their aggregate unpaid share of joint interest billings on the prospect. At December 31, 2005, the unpaid balance of joint interest billings on the prospect attributable to the participants was $141,988. An additional well was drilled on this prospect in 2006, and each of the original participants participated in that well through REPCO. At October 31, 2006, no balance was owing to us by REPCO.

In December 2004, we acquired WG Energy. Among WG Energy’s assets was a package of overriding royalty interests in various oil and gas properties. Following consummation of the WG Energy acquisition, Bridgeport Royalties, LLC (“Bridgeport”) was formed for the purpose of purchasing the overriding royalty interest package RAM Energy had acquired through its purchase of WG Energy, together with certain other overriding royalty interests on undeveloped WG Energy acreage. The managers of Bridgeport, initially, were Mr. Lee and Dr. Talley. Following Dr. Talley’s death in October 2005, Mr. Lee has continued as the sole manager of Bridgeport. Member interests in Bridgeport were offered as an employee benefit and perquisite to a number of RAM Energy’s officers and employees, and to an outside attorney. Thirteen of the offerees accepted and became members of the limited liability company, along with Mr. Lee and Dr. Talley. RAM Energy’s officers, directors and stockholders purchasing membership interests in Bridgeport, and their respective interests, include Messrs. Rampey and Smiley, 3.0% each; Mr. Cox, 2.0%; and Dr. Talley and Mr. Lee, 39.9% each. The proposed $2.3 million purchase price for the overriding royalty package was determined based on a percentage of the present value, discounted at 10% per annum, of the estimated future net revenues attributable to the overriding royalty interests included in the package and was approved by RAM Energy’s senior secured lender as a condition to such lender releasing its lien on the overriding royalties included in the sale. In June 2005, Bridgeport completed the purchase of the overriding royalty

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package from RAM Energy at the $2.3 million agreed price. The purchase price was funded with $345,000 in cash provided by the members of Bridgeport and $1.955 million of loan proceeds obtained by Bridgeport from BancFirst. RAM Energy has no continuing obligation of any nature with respect to the Bridgeport loan from BancFirst or any other Bridgeport liability.

For the years ended December 31, 2005, 2004 and 2003, we paid rent expense of $29,000, $66,000 and $54,000, respectively, related to a condominium for the benefit of Mr. Lee, a director, executive officer and one of our principal stockholders. In addition, for the years ended December 31, 2005, 2004 and 2003, our general and administrative expenses include an aggregate of approximately $499,000, $792,000 and $299,000 of expenses paid for the benefit of Larry Lee and Dr. Talley who, at the time, was a director and chairman of the board of RAM Energy, and the principal owner of Danish Knights, A Limited Partnership, which was the other of RAM Energy’s two principal stockholders. Some of the expenses paid may have been personal in nature.

In the spring of 1998, after the issuance of its publicly held senior notes, RAM Energy determined that it would be appropriate to hire an experienced attorney to serve as company’s general counsel in our Tulsa Office. However, after discussions with an outside law firm, McAfee & Taft in Oklahoma City, RAM Energy decided that if Mr. David Stinson, the McAfee & Taft lawyer who had performed extensive legal services for RAM Energy since its inception in 1987, could be made available to RAM Energy on a priority and essentially full-time, but not exclusive, basis, RAM Energy would continue to utilize McAfee & Taft and Mr. Stinson as its primary counsel and would pay McAfee & Taft a monthly retainer fee for Mr. Stinson’s services, which fee was fixed for a period of three years, with scheduled annual escalations thereafter. As an incentive for Mr. Stinson to agree to the proposed arrangement, RAM Energy agreed to grant Mr. Stinson options to acquire shares of RAM Energy common stock. Effective July 1, 1998, RAM Energy, McAfee & Taft and Mr. Stinson entered into a Special Retainer Agreement containing the terms agreed upon between the parties, and immediately thereafter the agreed stock options were granted to Mr. Stinson. Under the terms of the Special Retainer Agreement, as amended, in the event the agreement is terminated by Mr. Stinson for “good cause” or upon a “change of control,” as such terms are defined in the agreement, or by RAM Energy other than for “cause,” RAM Energy is required to pay to McAfee & Taft an amount equal to twelve times the monthly retainer amount. The amount of the monthly retainer has escalated over time both by agreement of the parties and by operation of the automatic escalation provisions of the agreement, and effective as of January 1, 2006, is set at $30,000 per month. Pursuant to the terms of the Special Retainer Agreement and subsequent issuances and adjustments, Mr. Stinson held options to acquire 83.33 shares of RAM Energy common stock at an exercise price of $2,500 per share. In April 2006, prior to consummation of the merger, Mr. Stinson exercised all of his options. This resulted in Mr. Stinson becoming one of our stockholders and being paid his pro rata portion of the merger consideration.

On May 8, 2006, we approved the issuance of and issued 10,000 restricted shares of our common stock to each of Messrs. Marshall, Reardon and Lane, our non-management directors. At the same time, we approved the issuance of and issued 100,000 restricted shares of our common stock to each of Messrs. Longmire, Rampey and Smiley, each of whom is one of our senior vice presidents. In each instance, the shares were issued under our 2006 Long-Term Incentive Plan and became fully vested 30 days following issuance, at which time, each of Messrs. Longmire, Rampey and Smiley sold 32,700 shares back to us to cover income taxes.

On November 10, 2006, our Compensation Committee approved the grant of restricted stock awards under our 2006 Long-Term Incentive Plan to a number of our employees, including an award of 75,100 shares to Mr. Robert Phaneuf, vice president — corporate development, and an award of 69,170 shares to Mr. John L. Cox, vice president, secretary and treasurer.

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On May 8, 2006, in conjunction with the consummation of the merger, we entered into a registration rights agreement with the former stockholders of RAM Energy under which we agreed to provide them with demand and “piggyback” registration rights with respect to our shares of common stock which they received in the merger.

For the year ended December 31, 2003, RAM Energy paid expenses in the amount of $260,000 on behalf of the Danish Knights, a Limited Partnership, one of RAM Energy’s principal stockholders which was beneficially owned by a former director and executive officer.

During 2004 and 2005, three of our executive officers were granted awards under RAM Energy’s Deferred Bonus Compensation Plan. Each award provides for a total cash compensation of $75,000 and vests on each anniversary date for three years beginning on July 1, 2004 and July 1, 2005, respectively. Receipt of the award is contingent on the officer being employed on the anniversary date. Should there be a change of control or involuntary termination, as defined in the award contract, each holder of an award will become fully vested in his award.

We have and will continue to reimburse our officers and directors for any reasonable out-of-pocket business expenses incurred by them in connection with certain activities on our behalf, such as identifying and investigating possible target businesses and business combinations. Since May 8, 2006, we have not, and we will not in the future, make personal loans to our officers, directors or stockholders owning five percent or more of our common stock.

Any future transactions with our officers, directors or stockholders owning five percent or more of our common stock will be on terms no less favorable to us than could be obtained from an independent third party.

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DESCRIPTION OF CAPITAL STOCK

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $.0001 per share, and 1,000,000 shares of preferred stock, par value $.0001 per share. At December 31, 2006, 33,439,530 shares of common stock and no shares of preferred stock were outstanding. Also outstanding at that date were 491,812 units, each unit consisting of one share of our common stock and two warrants, each to purchase one share of our common stock. We have reserved 12,650,000 shares of our common stock for issuance upon the exercise of outstanding warrants and 825,000 shares of our common stock issuable upon the exercise of currently exercisable options to purchase 275,000 units, each unit consisting of one share of our common stock and two warrants, each warrant to purchase one share of our common stock. We have also reserved 1,423,195 shares of our common stock for issuance under our 2006 Long-Term Incentive Plan.

The following description of certain matters relating to our capital stock is a summary and is qualified in its entirety by the provisions of our certificate of incorporation and bylaws, copies of which have been filed as exhibits to the registration statement of which this prospectus is a part.

Common Stock

The holders of our common stock are entitled to one vote per share on all matters submitted to a vote of stockholders. In addition, such holders are entitled to receive ratably such dividends, if any, as may be declared from time to time by our board of directors out of funds legally available, subject to the payment of preferential dividends with respect to any preferred stock that from time to time may be outstanding. In the event of our dissolution, liquidation or winding-up, the holders of common stock are entitled to share ratably in all assets remaining after payment of all our liabilities and subject to the prior distribution rights of the holders of any preferred stock that may be outstanding at that time. The holders of common stock do not have cumulative voting rights or preemptive or other rights to acquire or subscribe for additional, unissued or treasury shares. All outstanding shares of common stock are and, when issued, the shares of common stock offered hereby will be, fully paid and nonassessable.

In connection with the merger, we, together with the principal stockholders of RAM Energy and certain of our principal stockholders, entered into a voting agreement. Upon consummation of the merger, these stockholders beneficially owned approximately 80.5% of our common stock. The voting agreement provides that, until after the election of our board of directors in 2008, each of these persons will vote for the respective designees of the individual parties as members of our board of directors. We are obligated to maintain a board of directors comprised of at least four members during the term of this agreement.

Preferred Stock

We have an authorized class of preferred stock consisting of 1,000,000 shares, none of which are issued and outstanding. Our board of directors is authorized, subject to any limitations prescribed by law, without further stockholder approval, to issue shares of preferred stock from time to time. Our board of directors may designate one or more series of preferred stock. Each series of preferred stock shall have such number of shares, designations, preferences, voting powers, qualifications and special or relative rights or privileges as shall be determined by our board of directors, which may include, among others, dividend rights, voting rights, redemption and sinking fund provisions, liquidation preferences and conversion rights.

Anti-Takeover Provisions

Our certificate of incorporation and bylaws and the General Corporation Law of Delaware include a number of provisions that may have the effect of encouraging persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our board of directors rather than pursue non-

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negotiated takeover attempts. These provisions include a classified board of directors, authorized blank check preferred stock, restrictions on business combinations and the availability of authorized but unissued common stock.

Classified Board of Directors. Our certificate of incorporation contains provisions for a staggered board of directors with only one-third of the board standing for election each year. Our directors can only be removed for cause. A staggered board makes it more difficult for stockholders to change the majority of the directors and instead promotes a continuity of existing management.

Blank Check Preferred Stock. Our certificate of incorporation authorizes blank check preferred stock. Our board of directors can set the voting rights, redemption rights, conversion rights and other rights relating to the preferred stock and could issue preferred stock in either a private or public transaction. In some circumstances, the blank check preferred stock could be issued and have the effect of preventing a merger, tender offer or other takeover attempt which our board of directors opposes.

Delaware Takeover Statute. We are subject to Section 203 of the Delaware General Corporation Law. In general, Section 203 prevents an “interested stockholder” from engaging in a “business combination” with a Delaware corporation for three years following the date such person became an interested stockholder, unless (i) prior to the date such person became an interested stockholder, the board of directors of the corporation approved the transaction in which the interested stockholder became an interested stockholder or approves the business combination, (ii) upon consummation of the transaction that resulted in the interested stockholder becoming an interested stockholder, the interested stockholder owns at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding stock held by directors who are also officers of the corporation and stock held by certain employee stock plans, or (iii) on or subsequent to the date of the transaction in which such person became an interested stockholder, the business combination is approved by the board of directors of the corporation and authorized at a meeting of stockholders by the affirmative vote of the holders of at least two-thirds of the outstanding voting stock of the corporation not owned by the interested stockholder.

Section 203 defines a “business combination” to include (i) any merger or consolidation involving the corporation and an interested stockholder, (ii) any sale, transfer, pledge or other disposition involving an interested stockholder of 10% or more of the assets of the corporation, (iii) subject to certain exceptions, any transaction which results in the issuance or transfer by the corporation of any stock of the corporation to an interested stockholder, (iv) any transaction involving the corporation which has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder or (v) the receipt by an interested stockholder of any loans, guarantees, pledges or other financial benefits provided by or through the corporation. In addition, Section 203 defines an “interested stockholder” as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by such entity or person.

Stockholder Action

Except as otherwise required by law or our certificate of incorporation, with respect to any act or action required of or by the holders of the common stock, the affirmative vote of the holders of a majority of the issued and outstanding shares of common stock entitled to vote thereon is sufficient to authorize the act or action.

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Limitation of Liability of Directors

Our certificate of incorporation provides that no director shall be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability as follows:

Ÿ for any breach of the director’s duty of loyalty to us or our stockholders;

Ÿ for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

Ÿ for an act or omission for which the liability of a director is expressly provided by an applicable statute; and

Ÿ for any transaction from which the director derived an improper personal benefit.

In addition, we have entered into indemnity agreements with all of our directors under which we will indemnify them against loss, cost and expense incurred by them in serving as our directors so long as they are innocent of willful misconduct or gross negligence. The effect of the above provisions and the indemnity agreements is to eliminate our rights and those of our stockholders, through derivative suits on our behalf, to recover monetary damages against a director for a breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior, except in the situations described above.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable.

Transfer Agent and Registrar

The transfer agent and registrar of our common stock is Continental Stock & Transfer Company.

Warrants

We currently have outstanding 12,650,000 redeemable common stock purchase warrants. Each warrant entitles the registered holder to purchase one share of our common stock at a price of $5.00 per share, subject to adjustment as discussed below, at any time commencing on the completion of the merger. The warrants expire on May 11, 2008 at 5:00 p.m., New York City time. We may call the warrants for redemption:

Ÿ in whole and not in part;

Ÿ at a price of $.01 per warrant at any time after the warrants become exercisable;

Ÿ upon not less than 30 days’ prior written notice of redemption to each warrant holder; and

Ÿ if, and only if, the reported last sale price of our common stock equals or exceeds $8.50 per share, for any 20 trading days within a 30 trading day period ending on the third business day prior to the notice of redemption to warrant holders.

The exercise price and number of shares of common stock issuable on exercise of the warrants may be adjusted in certain circumstances, including in the event of a stock dividend, or our recapitalization, reorganization, merger or consolidation. However, the warrants will not be adjusted for issuances of common stock at a price below the exercise price.

The warrants may be exercised upon surrender of the warrant certificate on or prior to the expiration date at the offices of the warrant agent, completion of the exercise form on the reverse side of the warrant certificate and full payment of the exercise price by certified check payable to us for the number of

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warrants being exercised. The warrant holders do not have the rights or privileges of holders of common stock and any voting rights until they exercise their warrants and receive shares of common stock.

No warrants will be exercisable unless at the time of exercise a prospectus relating to common stock issuable upon exercise of the warrants is current and the common stock has been registered or qualified or deemed to be exempt under the securities laws of the state of residence of the holder of the warrants. Under the terms of a warrant agreement, we have agreed to maintain a current prospectus relating to common stock issuable upon exercise of the warrants until the expiration of the warrants. The warrants may be deprived of any value and the market for the warrants may be limited if the prospectus relating to the common stock issuable upon the exercise of the warrants is not current or if the common stock is not qualified or exempt from qualification in the jurisdictions in which the holders of the warrants reside.

We have engaged EarlyBirdCapital, Inc., the representative of the underwriters of Tremisis’ IPO, on a non-exclusive basis, as our agent for the solicitation of the exercise of the warrants. To the extent not inconsistent with the guidelines of the NASD and the rules and regulations of the SEC, we have agreed to pay a commission equal to 5% of the exercise price for each warrant exercised more than one year after the date of Tremisis’ IPO if the exercise was solicited by EarlyBirdCapital. In addition to soliciting, either orally or in writing, the exercise of the warrants, EarlyBirdCapital^’s services may also include disseminating information, either orally or in writing, to warrantholders about us or the market for our securities, and assisting in the processing of the exercise of warrants. No compensation will be paid to the representative upon the exercise of the warrants if:

Ÿ the market price of the underlying shares of common stock is lower than the exercise price;

Ÿ the holder of the warrants has not confirmed in writing that EarlyBirdCapital Inc. solicited the exercise;

Ÿ the warrants are held in a discretionary account;

Ÿ the warrants are exercised in an unsolicited transaction; or

Ÿ the arrangement to pay the commission is not disclosed in the prospectus provided to warrantholders at the time of exercise.

In conjunction with the closing of Tremisis’ IPO, we sold to EarlyBirdCapital an option to purchase up to a total of 275,000 units, each unit consisting of one share of our common stock and two warrants, each to purchase one share of our common stock. The units issuable upon exercise of this option were identical to those issued in the Tremisis IPO, except that the warrants included in EarlyBirdCapital’s option have an exercise price of $6.25 (125% of the exercise price of the warrants included in the units sold in the Tremisis IPO). The EarlyBirdCapital option is exercisable at $9.90 per unit commencing on May 8, 2006 and expiring May 12, 2009. Although the purchase option and its underlying securities were registered under the Securities Act of 1933, the holders have demand and “piggyback” rights for certain periods with respect to registration under the Securities Act of the securities directly and indirectly issuable upon exercise of the option. We will bear all fees and expenses attendant to registering the securities, other than underwriting commissions which will be paid for by the holders themselves. The exercise price and number of units issuable upon exercise of the option may be adjusted in certain circumstances, including in the event of a stock dividend, our recapitalization, reorganization, merger or consolidation. However, the option will not be adjusted for issuances of common stock at a price below its exercise price.

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PRICE RANGE OF SECURITIES AND DIVIDENDS

Our units, common stock and warrants are traded on the Nasdaq Capital Market under the symbols RAMEU, RAME and RAMEW, respectively. The following table sets forth the range of high and low closing bid prices for the units, common stock and warrants for the periods indicated since the units commenced public trading on May 13, 2004 and since the common stock and warrants commenced public trading on May 24, 2004. The over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily reflect actual transactions.

	Units				Common Stock				Warrants
	High		Low		High		Low		High		Low
2006:
First Quarter	$	8.25	$	7.00	$	5.89	$	5.46	$	1.18	$	0.78
Second Quarter		11.00		7.20		6.79		5.19		2.00		1.05
Third Quarter		8.74		6.45		5.79		4.68		1.75		0.77
Fourth Quarter		7.15		6.00		5.64		4.65		1.00		0.67
2005:
First Quarter	$	7.35	$	6.70	$	5.50	$	5.01	$	0.94	$	0.74
Second Quarter		7.05		6.36		5.56		5.12		0.82		0.57
Third Quarter		7.30		6.20		5.55		5.13		0.98		0.50
Fourth Quarter		7.35		6.65		5.56		5.31		0.95		0.65
2004:
Second Quarter (commencing May 24)	$	6.40	$	6.10	$	5.00	$	4.70	$	0.82	$	0.69
Third Quarter		6.35		5.97		5.00		4.81		0.72		0.52
Fourth Quarter		6.65		5.70		5.14		4.80		0.80		0.48

Holders

As of November 30, 2006, there were 49 holders of record of our units, 447 holders of record of our common stock and 385 holders of record of our warrants. We believe that the beneficial holders of the units, common stock and warrants are in excess of 400 persons each.

Dividends

It is the present intention of our board of directors to retain all earnings, if any, for use in our business operations and, accordingly, our board does not anticipate declaring any dividends in the foreseeable future.

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UNDERWRITING

Subject to the terms and conditions stated in the underwriting agreement dated ________, 2007, we and the selling stockholder have agreed to sell to the underwriters named below, and the underwriters have agreed to purchase, the number of shares of common stock appearing opposite the underwriters’ names below.

Name	Number of Shares
RBC Capital Markets Corporation
Jefferies & Company, Inc.
Johnson Rice & Company L.L.C.
Ferris, Baker Watts Incorporated
Sanders Morris Harris Inc.
Gilford Securities Incorporated
Total

The underwriting agreement provides that the underwriters’ obligation to purchase the shares depends on the satisfaction of the conditions contained in the underwriting agreement and that if any of our shares are purchased by the underwriters, all of our shares must be purchased. The conditions contained in the underwriting agreement include the condition that all the representations and warranties made by us to the underwriters are true, that there has been no material adverse change in our condition or in the condition of the financial markets and that we deliver to the underwriters customary closing documents.

The underwriters have advised us that they propose to offer the shares of common stock to the public at the public offering price appearing on the cover page of this prospectus and to certain dealers at that price less a concession of not more than $         per share, of which up to $         may be reallowed to other dealers. After the initial offering, the public offering price, concession and reallowance to dealers may be changed.

The following table shows the public offering price, underwriting discounts and commissions and proceeds, before expenses, to us and to the selling stockholder, both on a per share basis and in total, assuming either no exercise or full exercise by the underwriters of their over-allotment option.

		Total
	Per Share	Without Option	With Option
Public offering price	$	$	$
Underwriting discounts and commissions payable by us
Proceeds, before expenses, to us
Underwriting discounts and commissions payable by the selling stockholder
Proceeds, before expenses, to the selling stockholder

We estimate that the expenses of this offering payable by us, not including underwriting discounts and commissions, will be approximately $        . We have agreed to pay certain expenses of the selling stockholder incurred in connection with this offering, other than underwriting discounts and commissions payable in respect of the shares sold by the selling stockholder.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act or to contribute to payments that may be required to be made with respect to these liabilities.

We have granted to the underwriters an option to purchase up to an aggregate of 1,769,510 additional shares at the price to the public less the underwriting discount set forth on the cover page of this prospectus

73

exercisable solely to cover over-allotments, if any. Such option may be exercised in whole or in part at any time until 30 days after the date of this prospectus. If this option is exercised, the underwriters will be committed, subject to satisfaction of the conditions specified in the underwriting agreement, to purchase such number of additional shares, and we will be obligated, pursuant to the option, to sell these shares to the underwriters.

We, our directors and executive officers, and the selling stockholder have agreed that we will not, directly or indirectly, sell, offer or otherwise dispose of any shares or enter into any derivative transaction with similar effect as a sale of shares for a period of 90 days after the date of this prospectus without the prior written consent of RBC Capital Markets Corporation. The restrictions described in this paragraph do not apply to:

Ÿ the sale of shares to the underwriters; or

Ÿ restricted shares issued by us under the 2006 Long-Term Incentive Plan or upon the exercise of options issued under the 2006 Long-Term Incentive Plan.

The 90-day restricted period described in the preceding paragraphs will be extended if:

Ÿ during the last 17 days of the 90-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or

Ÿ prior to the expiration of the 90-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 90-day period;

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

RBC Capital Markets Corporation, in its sole discretion, may release the shares subject to lock-up agreements in whole or in part at any time with or without notice. When determining whether or not to release shares from lock-up agreements, RBC Capital Markets Corporation will consider, among other factors, the stockholders’ reasons for requesting the release (including, without limitation, a stockholder’s need to satisfy personal tax obligations), the number of shares for which the release is being requested and market conditions at the time.

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934, as amended.

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

Ÿ Over-allotment transactions involve sales by the underwriters of the shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares they may purchase in their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in the underwriters’ option to purchase additional shares. The underwriters may close out any short position by either exercising their option and/or purchasing shares in the open market.

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Ÿ Syndicate covering transactions involve purchases of the shares in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which it may purchase shares through their option. If the underwriters sell more shares than could be covered by their option to purchase additional shares, which we refer to in this prospectus as a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

Ÿ Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the shares originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the shares or preventing or retarding a decline in the market price of the shares. As a result, the price of the shares may be higher than the price that might otherwise exist in the open market.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our shares or preventing or retarding a decline in the market price of the shares. As a result, the price of the shares may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The Nasdaq Capital Market or otherwise and, if commenced, may be discontinued at any time.

Neither we nor the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the shares. In addition, neither we nor the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, if commenced, will not be discontinued without notice.

The several underwriters and their respective affiliates may in the future perform various financial advisory, investment banking and other commercial banking services in the ordinary course of business with us and our affiliates for which they will receive customary compensation.

No sales to accounts over which an underwriter exercises discretionary authority in excess of 5% of the shares offered by it may be made without the prior written approval of the customer.

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, information contained in any other web site maintained by an underwriter or selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been endorsed by us and should not be relied on by investors in deciding whether to purchase any shares. The underwriters and selling group members are not responsible for information contained in web sites that they do not maintain.

75

LEGAL MATTERS

The validity of the issuance of the shares of common stock offered by this prospectus will be passed upon for us by McAfee & Taft A Professional Corporation, Oklahoma City, Oklahoma. C. David Stinson, a stockholder of McAfee & Taft A Professional Corporation, currently beneficially owns 489,626 shares of our common stock. Certain legal matters relating to this offering will be passed on by Fulbright & Jaworski L.L.P., as counsel for the underwriters.

76

EXPERTS

The consolidated financial statements of RAM Energy, Inc. at December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, have been audited by UHY Mann Frankfort Stein & Lipp CPAs, 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.

The financial statements of RAM Energy Resources, Inc. (formerly known as Tremisis Energy Acquisition Corporation) at December 31, 2005 and 2004, the year ended December 31, 2005, the period from February 5, 2004 (inception) to December 31, 2004, and the period from February 5, 2004 (inception) to December 31, 2005, included elsewhere herein, have been audited by BDO Seidman, LLP, independent registered public accounting firm as set forth in their report appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Certain estimates of oil and natural gas reserves incorporated herein were based upon engineering studies prepared by Williamson Petroleum Consultants, Inc., independent petroleum engineers, and Forrest A. Garb & Associates, Inc., independent petroleum engineers. Each such estimate is included herein in reliance upon the authority of each of the respective firms as an expert in such matters.

77

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement on Form S-1 with the Securities and Exchange Commission in connection with this offering. We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. You may read and copy the registration statement and any other documents we have filed at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the Securities and Exchange Commission at 1-800-SEC-0330 for further information on the Public Reference Room. Our Securities and Exchange Commission filings are also available to the public at the Securities and Exchange Commission’s Internet site at “http://www.sec.gov.”

This prospectus is part of the registration statement and does not contain all of the information included in the registration statement. Whenever a reference is made in this prospectus to any of our contracts or other documents, the reference may not be complete and, for a copy of the contract or document, you should refer to the exhibits that are a part of the registration statement.

After the offering, we expect to provide annual reports to our stockholders that include financial information examined and reported on by our independent public accountant.

78

GLOSSARY OF OIL AND NATURAL GAS TERMS

The definitions set forth below apply to the indicated terms as used in this prospectus. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Boe. Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Development well. A well drilled within the proved areas 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 and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. One thousand Boe.

MMBoe. One million Boe.

Mcf. One thousand cubic feet of natural gas.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBtu. One million Btus.

MMcf. One million cubic feet of 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.

Operator. The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

PV-10 Value. When used with respect to oil and natural gas reserves, the estimated future gross revenues to be generated from the production of proved reserves, net of estimated production and future development costs, using the prices provided in this prospectus and costs in effect as of the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt

79

service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.

Proved developed reserves. Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.

Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

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.

Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

Reserve life. A ratio determined by dividing our estimated existing reserves determined as of the stated measurement date by production from such reserves for the prior twelve month period.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

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.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.

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INDEX TO FINANCIAL STATEMENTS

RAM Energy Resources, Inc.

Condensed Consolidated Balance Sheets as of September 30, 2006 (unaudited) and December 31, 2005	F-2
Condensed Consolidated Statements of Operations for the Three and Nine Months ended September 30, 2006 and 2005 (unaudited)	F-3
Condensed Consolidated Statements of Cash Flows for the Nine Months ended September 30, 2006 and 2005 (unaudited)	F-4
Notes to Condensed Consolidated Financial Statements (unaudited)	F-6
RAM Energy, Inc.
Report of Independent Registered Public Accounting Firm	F-17
Consolidated Balance Sheets as of December 31, 2005 and 2004	F-18
Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003	F-19
Consolidated Statements of Stockholders’ Deficit for the years ended December 31, 2005, 2004 and 2003	F-20

Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	F-21
Notes to Consolidated Financial Statements	F-23

Tremisis Energy Acquisition Corporation

Report of Independent Registered Public Accounting Firm	F-47
Balance Sheets as of December 31, 2005 and 2004	F-48
Statements of Operations—Period from February 5, 2004 to December 31, 2004; period from February 5, 2004 to December 31, 2005 and year ended December 31, 2005	F-49
Statements of Stockholders’ Equity for the period February 5, 2004 to December 31, 2004 and for year ended December 31, 2005	F-50
Statements of Cash Flows—Period from February 5, 2004 to December 31, 2004; period from February 5, 2004 to December 31, 2005 and year ended December 31, 2005	F-51
Summary of Significant Accounting Policies	F-52
Notes to Financial Statements	F-53

F-1

RAM ENERGY RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share amounts)

	September 30, 2006			December 31, 2005
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,592		$	70
Accounts receivable:
Oil and natural gas sales		6,501			7,422
Joint interest operations, net of allowance of $185 ($31 at December 31, 2005)		234			566
Related party		—			142
Other, net of allowance of $39 ($13 at December 31, 2005)		296			175
Derivative assets		308			—
Prepaid expenses		391			756
Other current assets		36			484
Total current assets		15,358			9,615
PROPERTIES AND EQUIPMENT, AT COST:
Oil and natural gas properties and equipment, using full cost accounting		178,668			160,704
Other property and equipment		6,110			7,276
		184,778			167,980
Less accumulated amortization and depreciation		(45,351	)		(36,848	)
Total properties and equipment		139,427			131,132
OTHER ASSETS:
Deferred loan costs, net of accumulated amortization of $4,639 ($4,905 at December 31, 2005)		2,791			1,613
Other		581			916
Total assets	$	158,157		$	143,276
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable:
Trade	$	5,386			4,343
Oil and natural gas proceeds due others		4,703			3,201
Related party		18			41
Other		32			—
Accrued liabilities:
Compensation		830			749
Interest		3,064			1,745
Income taxes		461			146
Derivative liabilities		—			3,510
Long-term debt due within one year		194			560
Total current liabilities		14,688			14,295
OIL & NATURAL GAS PROCEEDS DUE OTHERS		2,465			1,972
LONG-TERM DEBT		131,502			112,286
DEFERRED AND OTHER NON-CURRENT INCOME TAXES		27,834			25,300
ASSET RETIREMENT OBLIGATION		10,711			10,192
COMMITMENTS AND CONTINGENCIES		—			—
STOCKHOLDERS’ DEFICIT:
Common stock, $0.0001 par value, 100,000,000 and 30,000,000 shares authorized, 33,630,000 and 7,700,000 shares issued at September 30, 2006 and December 31, 2005, respectively		3			1
Additional paid-in capital		2,218			95
Treasury stock—837,275 shares at cost		(3,768	)		—
Accumulated deficit		(27,496	)		(20,865	)
Stockholders’ deficit		(29,043	)		(20,769	)
Total liabilities and stockholders’ deficit	$	158,157		$	143,276

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

F-2

RAM ENERGY RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share amounts)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
OPERATING REVENUES:
Oil and natural gas sales	$	18,267		$	17,974		$	53,050		$	48,140
Realized and unrealized gains (losses) on derivatives		3,878			(12,397	)		1,108			(16,613	)
Other		42			398			466			983
Total operating revenues		22,187			5,975			54,624			32,510
OPERATING EXPENSES:
Oil and natural gas production taxes		843			919			2,527			2,460
Oil and natural gas production expenses		4,309			3,917			13,222			11,453
Amortization and depreciation		3,495			3,397			10,019			9,213
Accretion expense		133			71			398			217
Share-based compensation		—			—			2,218			—
General and administrative, overhead and other expenses		2,304			2,367			6,351			6,285
Total operating expenses		11,084			10,671			34,735			29,628
Operating income (loss)		11,103			(4,696	)		19,889			2,882
OTHER INCOME (EXPENSE):
Interest expense		(3,906	)		(3,145	)		(13,213	)		(8,769	)
Interest income		129			19			238			41
INCOME (LOSS) BEFORE INCOME TAXES		7,326			(7,822	)		6,914			(5,846	)
INCOME TAX PROVISION (BENEFIT)		3,081			(2,972	)		2,924			(2,222	)
NET INCOME (LOSS)	$	4,245		$	(4,850	)	$	3,990		$	(3,624	)
EARNINGS (LOSS) PER SHARE:
Basic	$	0.13		$	(0.63	)	$	0.19		$	(0.47	)
Diluted	$	0.13		$	(0.63	)	$	0.18		$	(0.47	)
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		33,459,589			7,700,000			21,501,633			7,700,000
Diluted		33,692,544			7,700,000			22,105,987			7,700,000

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

F-3

RAM ENERGY RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Nine Months Ended September 30,
	2006			2005
OPERATING ACTIVITIES:
Net income (loss)	$	3,990		$	(3,624	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization and depreciation:
Oil and natural gas properties and equipment		9,524			8,894
Amortization of deferred loan costs and senior notes discount		776			629
Charge off of unamortized deferred loan costs		1,055			—
Other property and equipment		495			321
Accretion expense		398			217
Unrealized gain (loss) on derivatives		(5,874	)		14,855
Deferred income taxes		3,337			(3,648	)
Share-based compensation		2,218			—
Gain on disposal of other property and equipment		(99	)		—
Changes in operating assets and liabilities:
Accounts receivable		1,303			(1,346	)
Prepaid expenses, deposits, and other assets		816			120
Accounts payable		2,550			103
Accrued liabilities and other		4,805			(5,905	)
Total adjustments		21,304			14,240
Net cash provided by operating activities		25,294			10,616
INVESTING ACTIVITIES:
Payments for oil and natural gas properties and equipment		(21,529	)		(11,078	)
Proceeds from sales of oil and natural gas properties and equipment		3,565			2,346
Payments for other property and equipment		(726	)		(1,145	)
Proceeds from sales of other property and equipment		366			—
Payments of merger costs		(4,187	)		—
Cash acquired in merger		3,801			—
Net cash used in investing activities		(18,710	)		(9,877	)

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

F-4

RAM ENERGY RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Nine Months Ended September 30,
	2006			2005
FINANCING ACTIVITIES:
Payments on long-term debt		(87,738	)		(6,840	)
Payments of loan fees		(2,978	)		(424	)
Proceeds from borrowings on long-term debt		106,557			8,003
Stock redemption		(9,792	)		—
Repurchase of stock		(3,768	)		—
Deferred income taxes on share-based compensation		(843	)		—
Dividends paid		(500	)		(900	)
Net cash provided by (used in) financing activities		938			(161	)
Net increase in cash and cash equivalents		7,522			578
Cash and cash equivalents at beginning of period		70			1,175
Cash and cash equivalents at end of period	$	7,592		$	1,753
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	7,214		$	3,297
Cash paid for income taxes	$	124		$	20
DISCLOSURE OF NONCASH FINANCING ACTIVITIES:
Accrued interest added to principal balance of revolving credit facility	$	2,848		$	8,093

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

F-5

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

A—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, ORGANIZATION, AND BASIS OF PRESENTATION

1. Basis of Financial Statements

The accompanying unaudited condensed consolidated financial statements present the financial position at September 30, 2006 and December 31, 2005 and the consolidated results of operations for the three and nine month periods ended September 30, 2006 and 2005 and cash flows for the nine month periods ended September 30, 2006 and 2005 of RAM Energy Resources, Inc. and its subsidiaries, including RAM Energy, Inc., (collectively, the “Company”). These condensed consolidated financial statements include all adjustments, consisting of normal and recurring adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and the results of operations for the indicated periods. The results of operations for the three and nine months ended September 30, 2006 are not necessarily indicative of the results to be expected for the full year ending December 31, 2006. Reference is made to the consolidated financial statements of RAM Energy, Inc. for the year ended December 31, 2005, for an expanded discussion of the Company’s financial disclosures and accounting policies.

2. Nature of Operations and Organization

On May 8, 2006, Tremisis Energy Acquisition Corporation, or Tremisis, acquired RAM Energy, Inc. through the merger of a subsidiary of Tremisis into RAM Energy, Inc. The merger was accomplished pursuant to the terms of an Agreement and Plan of Merger dated October 20, 2005, as amended, among Tremisis, its subsidiary, RAM Energy, Inc. and the stockholders of RAM Energy, Inc. Upon completion of the merger, RAM Energy, Inc. became a wholly-owned subsidiary of Tremisis and Tremisis changed its name to RAM Energy Resources, Inc.

Tremisis was formed in February 2004 to effect a merger, capital stock exchange, asset acquisition or other similar business combination with an unidentified operating business in either the energy or the environmental industry. Prior to the consummation of the merger, Tremisis did not engage in an active trade or business.

Prior to the merger, RAM Energy, Inc. was a privately held, independent oil and natural gas company engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties and the production of oil and natural gas.

Upon consummation of the merger, the stockholders of RAM Energy, Inc. received an aggregate of 25,600,000 shares of Tremisis common stock and $30.0 million of cash. The merger agreement provided, among other things, that, prior to the consummation of the merger, RAM Energy, Inc. was entitled to either pay its stockholders a one-time extraordinary dividend or effect one or more redemptions of a portion of its outstanding stock, although the aggregate amount of such cash payments to the RAM Energy, Inc. stockholders could not exceed the difference between $40.0 million and the aggregate amount of cash they would receive from Tremisis in the merger. On April 6, 2006, RAM Energy, Inc. redeemed a portion of its outstanding stock for an aggregate consideration of $10.0 million.

The merger has been accounted for as a reverse acquisition. Because Tremisis had no active business operations prior to consummation of the merger, the merger has been accounted for as a recapitalization of

F-6

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

RAM Energy, Inc. and RAM Energy, Inc. has been treated as the acquirer and continuing reporting entity for accounting purposes. The assets and liabilities of Tremisis were recorded, as of completion of the merger, at fair value, which is considered to approximate historical cost, and added to those of RAM Energy, Inc.

The Company operates exclusively in the upstream segment of the oil and gas industry with activities including the drilling, completion, and operation of oil and gas wells. The Company conducts the majority of its operations in the states of Texas, Louisiana, Oklahoma and New Mexico.

3. Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates and assumptions that, in the opinion of management of the Company are significant include oil and natural gas reserves, amortization relating to oil and natural gas properties, asset retirement obligations and income taxes.

4. Reclassifications

Certain reclassifications of previously reported amounts for 2005 have been made to conform with the 2006 presentation format. These reclassifications had no effect on net income or loss.

5. Stockholders’ Equity, Earnings Per Share, and Share-Based Compensation

In connection with the reverse acquisition, the stockholders of RAM Energy, Inc. received an aggregate of 25,600,000 shares of Tremisis stock and $30.0 million. As of September 30, 2006, RAM Energy Resources, Inc. (formerly named Tremisis Energy Acquisition Corporation) had 100,000,000 shares of authorized common stock; 33,630,000 shares issued; and 32,792,725 shares outstanding. At December 31, 2005, the Company had 30,000,000 shares of authorized common stock, of which 7,700,000 shares were issued and outstanding.

Basic earnings or loss per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if dilutive stock options and warrants were exercised, calculated using the treasury stock method, unless such effect would be anti-dilutive. A reconciliation of earnings or loss and weighted average shares used in computing basic and diluted earnings or loss per share is as follows for the three and nine months ended September 30, 2006 and 2005 (in thousands, except share data and per share amounts):

F-7

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006		2005
Net income (loss)	$	4,245	$	(4,850	)	$	3,990	$	(3,624	)
Weighted average shares—basic		33,459,589		7,700,000			21,501,633		7,700,000
Dilutive effect of warrants		232,955		—			604,354		—
Weighted average shares—diluted		33,692,544		7,700,000			22,105,987		7,700,000
Basic earnings (loss) per share	$	0.13	$	(0.63	)	$	0.19	$	(0.47	)
Diluted earnings (loss) per share	$	0.13	$	(0.63	)	$	0.18	$	(0.47	)

The Company has outstanding 12,650,000 warrants, exercisable at $5 per share. The warrants expire May 11, 2008 and are redeemable by the Company at a price of $.01 per warrant upon 30 days’ prior written notice if the closing price of Company common stock equals or exceeds $8.50 per share for 20 trading days within any 30 trading day period.

6. New Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income tax positions. FIN 48 requires that the Company recognize in the consolidated financial statements the impact of a tax position that is more likely than not to be sustained upon examination based on the technical merits of the position. The provisions of FIN 48 will be effective for the Company as of the beginning of its 2007 year, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. The Company is currently evaluating the impact of adopting FIN 48.

In September 2006, the Securities and Exchange Commission (“SEC”) issued SAB No. 108 which provides guidance on quantifying and evaluating the materiality of unrecorded misstatements. SAB 108 is effective for annual financial statements covering the fiscal years ending on or after November 15, 2006. SAB 108 requires that a company use both the “iron curtain” and “rollover” approaches when quantifying misstatement amounts. The determination that an error is material in a current year that includes prior-year effects may result in the need to correct prior-year financial statements, even if the misstatement in the prior year or years is considered immaterial. When companies correct prior-year financial statements for immaterial errors, SAB 108 does not require previously filed reports to be amended. Such correction may be made the next time the company files the prior year financial statements. Although the Company is evaluating the impact of SAB 108, the Company does not currently believe there are any errors – material or immaterial – in the current year which would impact prior-year financial statements.

In September 2006, the Financial Accounting Standards Board issued SFAS No. 157 “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning on or after November 15, 2007. SFAS No. 157 applies under other accounting pronouncements that require or

F-8

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

permit fair value measurements, however, it does not require any new fair value measurements. In some instances, the application of SFAS No. 157 will change current accounting practices. The Company is currently evaluating the impact of adopting SFAS No. 157.

B—DERIVATIVE CONTRACTS

During 2006 and 2005, the Company entered into numerous derivative contracts. The Company did not formally designate these transactions as hedges as required by SFAS No. 133 in order to receive hedge accounting treatment. Accordingly, all gains and losses on the derivative financial instruments have been recorded in the statement of operations.

At September 30, 2006 the Company held put options on 23,000 barrels of oil through December 2006, with a price of $40.00 per barrel. The Company also had collars in place on 138,000 barrels of oil through December 2006 with a weighted average floor price of $43.33 and a weighted average ceiling price of $65.80 per barrel, 548,000 barrels of oil for 2007 with a weighted average floor price of $52.67 and a weighted average ceiling price of $73.24, and 274,000 barrels of oil for January through September, 2008 with a weighted average floor price of $53.34 and a weighted average ceiling price of $86.37. For natural gas, the Company had collars on 305,000 Mmbtu through December 2006 with a weighted average floor price of $7.00 per Mmbtu and a weighted average ceiling price of $11.95 per Mmbtu. For 2007, the Company had collars on 1,550,000 Mmbtu with a weighted average floor price of $7.43 and a weighted average ceiling price of $11.62, and 1,096,000 Mmbtu for January through September, 2008 with a weighted average floor price of $7.16 and a weighted average ceiling price of $13.25. The Company also held call options for April through October, 2007 on 856,000 Mmbtu with a weighted average floor price of $12.00.

At December 31, 2005, the Company had collars in place on 45,625 barrels per month through 2006 and 30,417 barrels per month through 2007. The 45,625 barrels per month in 2006 had a weighted average floor and ceiling of $42.51 and $60.56, respectively. The 30,417 barrels per month in 2007 had a weighted average floor and ceiling of $35.00 and $69.74, respectively. For natural gas, the Company had collars in place on 159,583 Mmbtu per month through 2006 and 150,000 Mmbtu per month for the three months ending March 2007. The 159,583 Mmbtu per month in 2006 had a weighted average floor and ceiling of $6.23 and $8.86, respectively. The 150,000 Mmbtu per month for the three months ending March 2007 had a weighted average floor and ceiling of $7.00 and $11.95. The Company also had purchased put options on 7,604 barrels per month of crude oil through 2006 at a weighted average floor price of $40.00. The Company purchased call options on 157,000 Mmbtu per month of natural gas for eight months in 2006 at a weighted average floor price of $9.94.

The Company measured the fair value of its derivatives at September 30, 2006 and December 31, 2005, based on quoted market prices. Accordingly, an asset of $308,000 and a liability of $3,510,000 were recorded in the consolidated balance sheets at September 30, 2006 and December 31, 2005, respectively.

C—SUBSIDIARY GUARANTORS

RAM Energy Resources, Inc. is not a party to, or a guarantor of obligations under, RAM Energy, Inc.’s outstanding 11.5% senior notes due 2008. RAM Energy Inc.’s senior notes are fully and unconditionally

F-9

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

guaranteed, jointly and severally, on a senior unsecured basis, by all current and future subsidiaries of RAM Energy, Inc. which are referred to as the “Subsidiary Guarantors”. The following table sets forth condensed consolidating financial information of the Subsidiary Guarantors. Currently there are no restrictions on the ability of the Subsidiary Guarantors to transfer funds to RAM Energy Inc. in the form of cash dividends, loans or advances.

The following represents the condensed consolidating balance sheets for RAM Energy Resources, Inc. (“Parent”), RAM Energy Inc. and its subsidiaries at September 30, 2006 and December 31, 2005 (in thousands):

	Parent			RAM Energy, Inc			Subsidiary Guarantors		Consolidating Adjustments			Total Consolidated Amounts
September 30, 2006
Current assets	$	1,792		$	(7,494	)	$	32,195	$	(11,135	)	$	15,358
Property and equipment, net		7			11,563			127,857		—			139,427
Investment in subsidiary		(31,610	)		41,211			—		(9,601	)		—
Other assets		1			3,236			135		—			3,372
Total assets	$	(29,810	)	$	48,516		$	160,187	$	(20,736	)	$	158,157
Current liabilities		433			17,104			8,286		(11,135	)		14,688
Long-term debt		—			48,956			82,546		—			131,502
Other non-current liabilities		—			3,305			9,871		—			13,176
Deferred income taxes		(1,200	)		10,761			18,273		—			27,834
Total liabilities		(767	)		80,126			118,976		(11,135	)		187,200
Stockholders’ equity (deficit)		(29,043	)		(31,610	)		41,211		(9,601	)		(29,043	)
Total liabilities and stockholders’ equity (deficit)	$	(29,810	)	$	48,516		$	160,187	$	(20,736	)	$	158,157
	Parent			RAM Energy, Inc			Subsidiary Guarantors		Consolidating Adjustments			Total Consolidated Amounts
December 31, 2005
Current assets	$	—		$	3,355		$	26,527	$	(20,267	)	$	9,615
Property and equipment, net		—			14,167			116,965		—			131,132
Investment in subsidiary		—			27,324			—		(27,324	)		—
Other assets		—			2,395			134		—			2,529
Total assets	$	—		$	47,241		$	143,626	$	(47,591	)	$	143,276
Current liabilities		—			28,713			5,849		(20,267	)		14,295
Long-term debt		—			29,767			82,519		—			112,286
Other non-current liabilities		—			3,038			9,126		—			12,164
Deferred income taxes		—			6,492			18,808		—			25,300
Total liabilities		—			68,010			116,302		(20,267	)		164,045
Stockholders’ equity (deficit)		—			(20,769	)		27,324		(27,324	)		(20,769	)
Total liabilities and stockholders’ equity (deficit)	$	—		$	47,241		$	143,626	$	(47,591	)	$	143,276

The following represents the condensed consolidating statements of operations for RAM Energy Resources, Inc., RAM Energy Inc. and its subsidiaries for the three months and nine months ended September 30, 2006 and 2005, and condensed consolidating statements of cash flows for the nine months ended September 30, 2006 and 2005 (in thousands):

F-10

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Parent			RAM Energy, Inc.			Subsidiary Guarantors			Consolidating Adjustments			Total Consolidated Amounts
Three Months Ended September 30, 2006
Operating revenues	$	—		$	6,064		$	16,123		$	—		$	22,187
Operating expenses		503			1,548			9,033			—			11,084
Operating income (loss)		(503	)		4,516			7,090			—			11,103
Other income		4,866			1,874			(2,180	)		(8,337	)		(3,777	)
Income (loss) before income taxes		4,363			6,390			4,910			(8,337	)		7,326
Income taxes		118			1,552			1,411			—			3,081
Net income (loss)	$	4,245		$	4,838		$	3,499		$	(8,337	)	$	4,245
	Parent			RAM Energy, Inc.			Subsidiary Guarantors			Consolidating Adjustments			Total Consolidated Amounts
Three Months Ended September 30, 2005
Operating revenues	$	—		$	(9,688	)	$	15,663		$	—		$	5,975
Operating expenses		—			3,417			7,254			—			10,671
Operating income (loss)		—			(13,105	)		8,409			—			(4,696	)
Other income		—			(1,391	)		11			(1,746	)		(3,126	)
Income (loss) before income taxes		—			(14,496	)		8,420			(1,746	)		(7,822	)
Income taxes		—			(9,646	)		6,674			—			(2,972	)
Net income (loss)	$	—		$	(4,850	)	$	1,746		$	(1,746	)	$	(4,850	)
	Parent			RAM Energy, Inc.			Subsidiary Guarantors			Consolidating Adjustments			Total Consolidated Amounts
Nine Months Ended September 30, 2006
Operating revenues	$	—		$	6,950		$	47,674		$	—		$	54,624
Operating expenses		2,954			4,533			27,248			—			34,735
Operating income		(2,954	)		2,417			20,426			—			19,889
Other income		6,136			3,738			(6,525	)		(16,324	)		(12,975	)
Income (loss) before income taxes		3,182			6,155			13,901			(16,324	)		6,914
Income taxes		(808	)		63			3,669			—			2,924
Net income (loss)	$	3,990		$	6,092		$	10,232		$	(16,324	)	$	3,990
Cash flows provided by (used in) operating activities		29			1,768			23,497			—			25,294
Cash flows provided by (used in) investing activities		(386	)		740			(19,064	)		—			(18,710	)
Cash flows provided by (used in) financing activities		2,070			(1,158	)		26			—			938
Increase (decrease) in cash and cash equivalents		1,713			1,350			4,459			—			7,522
Cash and cash equivalents at beginning of period		—			617			(547	)		—			70
Cash and cash equivalents at end of period	$	1,713		$	1,967		$	3,912		$	—		$	7,592

F-11

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Parent		RAM Energy, Inc.			Subsidiary Guarantors			Consolidating Adjustments			Total Consolidated Amounts
Nine Months Ended September 30, 2005
Operating revenues	$	—	$	(9,809	)	$	42,319		$	—		$	32,510
Operating expenses		—		9,138			20,490			—			29,628
Operating income		—		(18,947	)		21,829			—			2,882
Other income		—		2,400			26			(11,154	)		(8,728	)
Income (loss) before income taxes		—		(16,547	)		21,855			(11,154	)		(5,846	)
Income taxes		—		(12,923	)		10,701			—			(2,222	)
Net income (loss)	$	—	$	(3,624	)	$	11,154		$	(11,154	)	$	(3,624	)
Cash flows provided by (used in) operating activities		—		(913	)		11,529			—			10,616
Cash flows provided by (used in) investing activities		—		(2,574	)		(7,303	)		—			(9,877	)
Cash flows provided by (used in) financing activities		—		4,142			(4,303	)		—			(161	)
Increase (decrease) in cash and cash equivalents		—		655			(77	)		—			578
Cash and cash equivalents at beginning of period		—		1,043			132			—			1,175
Cash and cash equivalents at end of period	$	—	$	1,698		$	55		$	—		$	1,753

Due to intercompany allocations among RAM Energy, Inc. and its subsidiaries, the above condensed consolidating information is not intended to present the subsidiaries of RAM Energy, Inc. on a stand-alone basis.

D—COMMITMENTS AND CONTINGENCIES

In April 2002, a lawsuit was filed in the District Court for Woods County, Oklahoma against RAM Energy, Inc., certain of its subsidiaries and various other individuals and unrelated companies, by a lessor of certain oil and gas leases from which production was sold to a gathering system owned and operated by Magic Circle Energy Corporation (Magic Circle) or its wholly-owned subsidiary, Carmen Field Limited Partnership (CFLP). The lawsuit covers the period from 1977 to a current date. In 1998, both Magic Circle and CFLP became wholly-owned subsidiaries of RAM Energy, Inc. The lawsuit was filed as a class action on behalf of all royalty owners under leases owned by any of the defendants during the period Magic Circle or CFLP owned and operated the gathering system. The petition claims that additional royalties are due because Magic Circle and CFLP resold oil and gas purchased at the wellhead for an amount in excess of the price upon which royalty payments were based and paid no royalties on natural gas liquids extracted from the gas at plants downstream of the system. Other allegations include under-measurement of oil and gas at the wellhead by Magic Circle and CFLP, failure to pay royalties on take or pay settlement proceeds and failure to properly report deductions for post-production costs in accordance with Oklahoma’s check stub law.

RAM Energy, Inc. and other defendants have filed answers in the lawsuit denying all material allegations set out in the petition. The Company believes that fair and proper accounting was made to the royalty owners for production from the subject leases and intends to vigorously defend the lawsuit. Plaintiffs have not specified an amount of claim, nor the time period covered. Management is unable to estimate a range of potential loss, if any, related to this lawsuit, and accordingly no amounts have been

F-12

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

recorded in the consolidated financial statements. In the event the court should find RAM Energy, Inc. and its related defendants liable for damages in the lawsuit, a former joint venture partner is contractually obligated to pay a portion of any damages assessed against the defendant lessees up to a maximum contribution of approximately $2.8 million.

The Company is also involved in legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company’s financial position or results of operations.

E—LONG-TERM DEBT

Long-term debt consists of the following:

	September 30, 2006		December 31, 2005
	(in thousands)
11.5% senior notes due 2008, net of discount	$	28,340	$	28,309
Term and revolving credit facility		103,000		83,897
Installment loan agreements		356		640
		131,696		112,846
Less amount due within one year		194		560
	$	131,502	$	112,286

1. Senior Notes

In February 1998, RAM Energy, Inc. issued $115.0 million principal amount of its unsecured 11.5% senior notes due 2008 of which $28.4 million remained outstanding at September 30, 2006 and December 31, 2005. The senior notes are redeemable at the option of RAM Energy, Inc. in whole or in part, at any time prior to their scheduled maturity in 2008 at a prices ranging from 107.7% to 103.8% of the face amount. RAM Energy Resources, Inc. is not a party to, or a guarantor of obligations under, the senior notes issued by RAM Energy, Inc.

At September 30, 2006 and December 31, 2005, the unamortized original issue discount associated with the senior notes totaled $56,000 and $87,000, respectively.

2. Revolving Credit Facility

On April 5, 2006, RAM Energy, Inc. obtained a $300.0 million senior secured credit facility, consisting of a $150.0 million, five-year term loan facility and a $150.0 million four-year revolving credit facility. RAM Energy Resources, Inc. is not a party to or a guarantor of obligations under this credit facility.

At closing, $50.0 million of the revolving credit facility was immediately available, and $90.0 million of the term loan was advanced. The remainder of the term loan facility will be available, subject to approval of the lenders, for certain future needs, including acquisitions. The revolving credit facility will mature in April, 2010, during which time amounts may be borrowed and repaid as often as needed, subject to a borrowing base limitation that is re-determined semi-annually, based on oil and gas reserves. The term loan

F-13

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

facility will mature in April, 2011, with permitted prepayments after the first year, subject to a prepayment premium in the second and third years of the term. Advances under the revolving credit facility will bear interest at LIBOR plus 2% per annum, while amounts outstanding under the term loan will bear interest at LIBOR plus 5.5% to 6.0% per annum. Obligations under the credit facility are secured by a first lien on substantially all of the assets of RAM Energy, Inc. and its subsidiaries. The initial advance under the credit facility was used to refinance the previous credit facility, and to fund the pre-merger redemption payment permitted by the merger agreement. Subsequent advances may be used to:

Ÿ repurchase all of RAM Energy, Inc.’s outstanding 11.5% senior notes ($28.4 million principal amount); and

Ÿ for general working capital purposes.

The credit facility contains financial covenants requiring RAM Energy, Inc. to maintain certain ratios, including a current ratio, a ratio of earnings before interest, taxes, depreciation and amortization, or EBITDA, to interest expense, a ratio of total indebtedness to EBITDA, and a ratio of asset value to total indebtedness. In addition, the credit facility contains other affirmative and negative covenants customary in lending transactions of this nature, including the maintenance by RAM Energy, Inc. of hedging contracts for a minimum and maximum amount of projected oil and natural gas production from its properties. The Company was in compliance with all covenants as of September 30, 2006.

F—CAPITAL STOCK

RAM Energy, Inc. paid cash dividends of $0 and $500,000 for the three and nine months ended September 30, 2006, respectively. RAM Energy, Inc. declared cash dividends of $0 and $900,000 for the three and nine months ended September 30, 2005, respectively.

On April 6, 2006, RAM Energy, Inc. redeemed a portion of the outstanding shares of its common stock for an aggregate redemption price of $10.0 million.

On May 8, 2006, the Company acquired RAM Energy, Inc. by merger in exchange for an issuance of 25,600,000 shares of common stock and $30.0 million in cash. RAM Energy, Inc. is now a wholly-owned subsidiary of the Company. As a result of the merger, RAM Energy, Inc. was recapitalized so that the historical basis of its assets and liabilities remain intact. The only operations of the parent company included in the results of operations for 2006 are those that occurred subsequent to the date of the merger.

On May 8, 2006, the shareholders of the Company approved the Company’s 2006 Long-Term Incentive Plan, effective upon the consummation of the Company’s acquisition by merger of RAM Energy, Inc. The Company reserved a maximum of 2,400,000 shares of its common stock for issuance under the plan.

On May 8, 2006, 330,000 shares of common stock were awarded to certain officers and directors of the Company under the Company’s long-term incentive plan. The value of the shares was recorded at $6.72 per share, the closing market price of the Company’s common stock as of that date (see note J). At the request of the grantees, on June 8, 2006, the Company repurchased 98,100 of these shares at $6.04 per share, the closing market price of the Company’s common stock as of that date, to satisfy the grantees’ federal and state income tax withholding requirements, as permitted by the plan. The repurchased shares are held by the Company as treasury shares.

F-14

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On September 22, 2006, the Company purchased 739,175 shares of its common stock in a privately negotiated transaction. The purchase price was $4.295 per share, and the shares are included in treasury stock at September 30, 2006.

G—DEFERRED COMPENSATION

On April 21, 2004, RAM Energy, Inc. adopted a Deferred Bonus Compensation Plan for its senior management employees. The plan provides additional compensation for significant business transactions with a portion of each bonus to be deferred to encourage retention of key employees. Determination of significant business transactions and terms of awards is made by a committee comprised of the directors of RAM Energy, Inc.

During 2004 and 2005 three members of senior management were granted awards under the bonus plan. Each award provides for a total cash compensation of $75,000 per year and vests ratably on each anniversary date for three years beginning on July 1, 2004. Receipt of the award is contingent on the members being employed on the respective anniversary date. Should there be a change of control or involuntary termination, as defined in the award contract, each member will become fully vested in his award. Compensation expense is recorded on a straight-line basis. No awards were granted for the nine months ended September 30, 2006.

H—FINANCIAL CONDITION AND MANAGEMENT PLANS

As shown in the condensed consolidated financial statements, for the three and nine months ended September 30, 2006, the Company reported net income of approximately $4.2 million and $4.0 million, respectively, as compared to net loss of approximately $4.9 million and $3.6 million for the three and nine months ended September 30, 2005, respectively. The condensed consolidated financial statements also show an accumulated deficit of approximately $27.5 million at September 30, 2006.

Management believes that borrowings currently available to RAM Energy, Inc. under its credit facility, together with the remaining balance of unrestricted cash and cash flows from operations will be sufficient to satisfy the Company’s currently expected capital expenditures, working capital and debt service obligations for the foreseeable future. The actual amount and timing of future capital requirements may differ materially from estimates as a result of, among other things, changes in product pricing and regulatory requirements, and technological and competitive developments. Sources of additional financing may include commercial bank borrowings, vendor financing and the sale of oil and natural gas properties or equity or debt securities. Management cannot provide any assurance that any such financing will be available on acceptable terms or at all.

I— RELATED PARTY TRANSACTIONS

RAM Energy, Inc., while a private company, paid rent expense of approximately $0 and $29,000 relating to a condominium for one of its shareholders for the nine months ended September 30, 2006 and 2005, respectively.

For the nine months ended September 30, 2006 and 2005, approximately $104,000 and $374,000, respectively, of expenses for the shareholders of RAM Energy, Inc., while a private company, are included

F-15

RAM ENERGY RESOURCES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

in general and administrative expenses in the consolidated statements of operations, some of which may be personal in nature.

No such expenses have been incurred by the Company since the date of the merger.

J—SHARE-BASED COMPENSATION

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. The Company adopted the provisions of SFAS No. 123R, as required, effective January 1, 2006.

On May 8, 2006, certain officers and directors of the Company were awarded an aggregate 330,000 shares of common stock under the Company’s long-term incentive plan, which shares became fully vested at June 8, 2006. Accordingly, share-based compensation expense in the amount of $2,218,000 was recognized in the second quarter of 2006, representing the fair market value of the shares awarded as of May 8, 2006.

F-16

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

RAM Energy, Inc.

We have audited the accompanying consolidated balance sheets of RAM Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ deficit, and cash flows for each of the three years in the period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of RAM Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note A, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

/s/ UHY Mann Frankfort Stein & Lipp CPAs, LLP

Houston, Texas

March 6, 2006, except for Note Q, as to which the date is April 6, 2006

F-17

RAM ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

December 31, 2005 and 2004

	2005			2004
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	70		$	1,175
Accounts receivable:
Oil and natural gas sales, net of allowance of $0 ($0 in 2004)		7,422			5,039
Joint interest operations, net of allowance of $31 ($687 in 2004)		566			630
Related party, net of allowance of $0 ($0 in 2004)		142			—
Other, net of allowance of $0 ($37 in 2004)		175			28
Prepaid expenses		756			141
Other current assets		484			565
Derivative assets		—			1,627
Total current assets		9,615			9,205
PROPERTIES AND EQUIPMENT, AT COST
Oil and natural gas properties and equipment, using full cost accounting		160,704			146,598
Other property and equipment		7,276			5,779
		167,980			152,377
Less accumulated depreciation and amortization		36,848			23,919
Net properties and equipment		131,132			128,458
OTHER ASSETS:
Deferred loan costs, net of accumulated amortization of $4,905 ($4,110 in 2004)		1,613			1,845
Other		916			816
Total assets	$	143,276		$	140,324
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable:
Trade	$	4,343		$	5,273
Oil and natural gas proceeds due others		3,201			2,528
Related party		41			—
Accrued liabilities:
Compensation		749			583
Interest		1,745			1,547
Income taxes		146			289
Derivative liabilities		3,510			—
Long-term debt due within one year		560			3,891
Total current liabilities		14,295			14,111
OIL AND NATURAL GAS PROCEEDS DUE OTHERS		1,972			1,642
LONG-TERM DEBT		112,286			113,453
DEFERRED AND OTHER NON-CURRENT INCOME TAXES		25,300			24,374
ASSET RETIREMENT OBLIGATION		10,192			6,656
COMMITMENTS AND CONTINGENCIES (Note K)		—			—
STOCKHOLDERS’ DEFICIT:
Common stock, $10 par value; authorized—5,000 shares; issued and outstanding—2,273 shares at December 31, 2005 and 2004		23			23
Additional paid-in capital		73			73
Accumulated deficit		(20,865	)		(20,008	)
Total stockholders’ deficit		(20,769	)		(19,912	)
Total liabilities and stockholders’ deficit	$	143,276		$	140,324

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

F-18

RAM ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share and per share amounts)

Years Ended December 31, 2005, 2004, and 2003

	2005			2004			2003
REVENUES AND OTHER OPERATING INCOME:
Oil and natural gas sales	$	66,243		$	17,975		$	20,053
Gain on sale of subsidiary		—			12,139			—
Other		851			338			170
Realized and unrealized losses from derivatives		(11,695	)		(793	)		(203	)
Total revenues and other operating income		55,399			29,659			20,020
OPERATING EXPENSES:
Oil and natural gas production taxes		3,320			1,263			1,408
Oil and natural gas production expenses		16,099			3,600			3,527
Depreciation and amortization		12,972			3,273			4,098
Accretion expense		510			78			48
General and administrative, overhead and other expenses, net of operator’s overhead fees		8,610			6,601			6,331
Total operating expenses		41,511			14,815			15,412
Operating income		13,888			14,844			4,608
OTHER INCOME (EXPENSE):
Interest expense		(12,614	)		(5,070	)		(4,912	)
Interest income		75			35			41
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		1,349			9,809			(263	)
INCOME TAX PROVISION		806			3,733			228
INCOME (LOSS) FROM CONTINUING OPERATIONS		543			6,076			(491	)
DISCONTINUED OPERATIONS:
Loss from discontinued operations		—			—			(1,723	)
Income tax benefit		—			—			(655	)
LOSS FROM DISCONTINUED OPERATIONS		—			—			(1,068	)
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		543			6,076			(1,559	)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
(Net of tax benefit of $0, $0, and $275 in 2005, 2004, and 2003, respectively)		—			—			(448	)
Net income (loss)	$	543		$	6,076		$	(2,007	)
BASIC EARNINGS (LOSS) PER SHARE:
Income (loss) from continuing operations	$	238.94		$	2,383.67		$	(180.05	)
Loss from discontinued operations		—			—			(391.64	)
Cumulative effect of change in accounting principle		—			—			(164.28	)
Net income (loss)	$	238.94		$	2,383.67		$	(735.97	)
BASIC WEIGHTED AVERAGE SHARES OUTSTANDING		2,273			2,549			2,727
DILUTED EARNINGS (LOSS) PER SHARE:
Income (loss) from continuing operations	$	230.72		$	2,299.77		$	(180.05	)
Loss from discontinued operations		—			—			(391.64	)
Cumulative effect of change in accounting principle		—			—			(164.28	)
Net income (loss)	$	230.72		$	2,299.77		$	(735.97	)
DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING		2,354			2,642			2,727

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

F-19

RAM ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT

(In thousands, except share amounts)

Years Ended December 31, 2005, 2004, and 2003

	Common Stock					Additional Paid-In Capital			Accumulated Deficit			Total Stockholders Deficit
	Shares		Amount
BALANCE, January 1, 2003	2,727		$	27		$	88		$	(16,957	)	$	(16,842	)
Net loss	—			—			—			(2,007	)		(2,007	)
Dividends declared	—			—			—			(804	)		(804	)
BALANCE, December 31, 2003	2,727			27			88			(19,768	)		(19,653	)
Net income	—			—			—			6,076			6,076
Dividends declared	—			—			—			(1,200	)		(1,200	)
Purchase and cancellation of common shares and outstanding options	(454	)		(4	)		(15	)		(5,116	)		(5,135	)
BALANCE, December 31, 2004	2,273			23			73			(20,008	)		(19,912	)
Net income	—			—			—			543			543
Dividends declared	—			—			—			(1,400	)		(1,400	)
BALANCE, December 31, 2005	2,273		$	23		$	73		$	(20,865	)	$	(20,769	)

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

F-20

RAM ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

Years Ended December 31, 2005, 2004, and 2003

	2005			2004			2003
OPERATING ACTIVITIES:
Net income (loss)	$	543		$	6,076		$	(2,007	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities -
Depreciation and amortization		12,972			3,273			4,098
Amortization of deferred loan costs and Senior Notes discount		839			492			445
Accretion expense		510			78			48
Gain on sale of subsidiary		—			(12,139	)		—
Loss from discontinued operations, net of tax		—			—			1,068
Cumulative effect of change in accounting principle, net of tax		—			—			448
Provision for doubtful accounts		—			385			17
Unrealized (gain) loss on derivatives		6,302			(77	)		(125	)
Loss (gain) on sale of other property and equipment		—			(1	)		13
Deferred income taxes		1,199			(3,159	)		(3,962	)
Changes in operating assets and liabilities, net of acquisitions
Accounts receivable		(2,608	)		(18	)		94
Prepaid expenses and other assets		(143	)		342			126
Accounts payable		(165	)		(67	)		(664	)
Accrued liabilities		(697	)		109			1,876
Income taxes payable		(393	)		6,892			4,190
Gas balancing liability		—			(393	)		109
Total adjustments		17,816			(4,283	)		7,781
Net cash provided by operating activities		18,359			1,793			5,774
INVESTING ACTIVITIES:
Payments for oil and natural gas properties and equipment		(13,528	)		(5,900	)		(4,282	)
Proceeds from sales of oil and natural gas properties		2,471			320			187
Payments for other property and equipment		(1,497	)		(205	)		(343	)
Proceeds from sales of other property and equipment		—			38			15
RWG acquisition, net of cash acquired		—			(82,577	)		—
Proceeds from the sale of subsidiary		—			21,791			—
Proceeds from sale of pipeline system		—			—			12,026
Proceeds from (payments for) short-term investments		—			1,681			(181	)
Net cash (used in) provided by investing activities		(12,554	)		(64,852	)		7,422

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

F-21

RAM ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

Years Ended December 31, 2005, 2004, and 2003

	2005			2004			2003
FINANCING ACTIVITIES:
Payments on long-term debt		(15,615	)		(18,234	)		(11,929	)
Proceeds from borrowings on long-term debt		10,670			88,585			—
Payments for deferred loan costs		(565	)		(1,500	)		—
Stock repurchased and retired		—			(5,135	)		—
Dividends paid		(1,400	)		(1,600	)		(404	)
Net cash provided by (used in) financing activities		(6,910	)		62,116			(12,333	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,105	)		(943	)		863
CASH AND CASH EQUIVALENTS, beginning of year		1,175			2,118			1,255
CASH AND CASH EQUIVALENTS, end of year	$	70		$	1,175		$	2,118
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for income taxes	$	20		$	300		$	—
Cash paid for interest	$	3,297		$	4,285		$	3,292
DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Accrued interest added to principal balance of credit facility	$	8,093		$	554		$	1,699

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

F-22

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2005 and 2004

A—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, ORGANIZATION AND BASIS OF PRESENTATION

1. Nature of Operations and Organization

RAM Energy, Inc. (the “Company”) operates exclusively in the upstream segment of the oil and natural gas industry with activities including drilling, completion and operation of onshore oil and natural gas wells. The Company conducts the majority of its operations in the states of Texas, Louisiana, Oklahoma and New Mexico. On December 17, 2004, the Company completed its acquisition of WG Energy Holdings, Inc. (“WG”), a Delaware corporation, in which a wholly owned subsidiary of the Company created specifically for such purpose merged with and into WG and WG was the surviving corporation in the merger (the “WG Acquisition”). At the time of the merger, the name of WG was changed to RWG Energy, Inc., or RWG. RWG, with its subsidiaries, are now first and second tier subsidiaries of the Company. On August 1, 2003, the Company sold its oil and natural gas pipeline system and saltwater disposal operation in north central Oklahoma (the pipeline system). The pipeline system purchased, transported and marketed oil and natural gas production and disposed of saltwater from properties owned by the Company and other oil and natural gas companies (see Note J).

2. Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated.

3. Properties and Equipment

The Company follows the full cost method of accounting for oil and natural gas operations. Under this method all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. No gains or losses are recognized upon the sale or other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves.

Under the full cost method the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% (the ceiling limitation). In arriving at estimated future net revenues, estimated lease operating expenses, development costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on a quarterly and yearly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. Reserve estimates used in determining estimated future net revenues have been prepared by an independent petroleum engineer.

The Company has capitalized internal costs of approximately $1,778,000, $596,000, and $434,000 for the years ended December 31, 2005, 2004, and 2003, respectively. Such capitalized costs include salaries and related benefits of individuals directly involved in the Company’s acquisition, exploration and development activities based on the percentage of their time devoted to such activities.

F-23

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

Other property and equipment consists principally of furniture and equipment and leasehold improvements. Other property and equipment and related accumulated amortization and depreciation are relieved upon retirement or sale and the gain or loss is included in operations. Renewals and replacements that extend the useful life of property and equipment are treated as capital additions. Accumulated depreciation of other property and equipment at December 31, 2005 and 2004 is approximately $4,246,000 and $3,845,000, respectively.

In accordance with the impairment provisions of Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company assesses the recoverability of the carrying value of its non-oil and gas long-lived assets when events occur that indicate an impairment in value may exist. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If this occurs, an impairment loss is recognized for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset. No impairments were recorded in 2005, 2004, or 2003.

4. Depreciation and Amortization

All capitalized costs of oil and natural gas properties and equipment, including the estimated future costs to develop proved reserves, are amortized using the unit-of-production method based on total proved reserves. Depreciation of other equipment is computed on the straight line method over the estimated useful lives of the assets, which range from three to ten years. Amortization of leasehold improvements is computed based on the straight-line method over the term of the associated lease or estimated useful life, whichever is shorter.

5. Natural Gas Sales and Gas Imbalances

Natural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage.

The Company follows the entitlement method of accounting for natural gas sales, recognizing as revenues only its net interest share of all production sold. Any amount attributable to the sale of production in excess of or less than the Company’s net interest is recorded as a gas balancing asset or liability. At December 31, 2005, the Company’s net underproduced position was approximately 162,000 Mcf with an associated asset of approximately $237,000, which is recorded in other assets on the consolidated balance sheet. At December 31, 2004, the Company’s net underproduced position was approximately 153,000 Mcf with an associated asset of approximately $230,000.

6. Cash Equivalents

All highly liquid unrestricted investments with a maturity of three months or less when purchased are considered to be cash equivalents.

7. Credit and Market Risk

The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these operations are generally unsecured. In 2005, approximately 73% of total

F-24

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

revenues were to two customers (52% to four customers in 2004 and 68% to four customers in 2003), with sales to each comprising 55% and 18% (23%, 11%, 10% and 8% in 2004 and 27%, 20%, 12% and 9% in 2003) of total revenues.

In 2005 and 2004 the Company had cash deposits in certain banks that at times exceeded the maximum insured by the Federal Deposit Insurance Corporation. The Company monitors the financial condition of the banks and has experienced no losses on these accounts.

8. Deferred Loan Costs

Deferred loan costs are stated at cost net of amortization computed using the straight-line method over the term of the related loan agreement, which approximates the interest method.

The estimated future amortization expense is as follows:

2006	$	990,000
2007		614,000
2008		9,000

9. General and Administrative Expense

The Company receives fees for the operation of jointly owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $228,000, $212,000, and $406,000 for the years ended December 31, 2005, 2004, and 2003, respectively.

10. Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates and assumptions that, in the opinion of management of the Company are significant include oil and natural gas reserves, amortization relating to oil and natural gas properties, asset retirement obligations, and income taxes.

11. Fair Value of Financial Instruments

Cash and cash equivalents, trade receivables and payables, and installment notes: The carrying amounts reported on the consolidated balance sheets approximate fair value due to the short-term nature of these instruments.

Credit Facility: The carrying amount reported on the consolidated balance sheets approximates fair value because this debt instrument carries a variable interest rate based on market interest rates.

Senior Notes: The carrying amount reported on the consolidated balance sheets is approximately $1.1 million below fair value at December 31, 2005 and exceeds fair value at December 31, 2004 by approximately $1.4 million based upon management’s estimates. Management bases its estimate on information from the bond underwriters on current bids for the Company’s senior notes.

F-25

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

Derivative contracts: The carrying amount reported on the consolidated balance sheets is the fair value of the contracts based upon commodity futures prices for similar contracts.

12. Reclassifications

Certain reclassifications of previously reported amounts for 2004 and 2003 have been made to conform to the 2005 presentation. These reclassifications had no effect on net income or loss.

13. Derivatives

The Company applies the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires companies to recognize all derivative instruments as either assets or liabilities in the statement of financial position at fair value.

The Company entered into numerous derivative contracts to reduce the impact of oil and natural gas price fluctuations and as required by the terms of its credit facility (see Note L). The Company did not designate these transactions as hedges as required by SFAS No. 133 in order to receive hedge accounting treatment. Accordingly, all gains and losses on the derivative instruments during 2005, 2004 and 2003 have been recorded in the statements of operations.

14. Earnings per Common Share

Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. A reconciliation of net income (loss) and weighted average shares used in computing basic and diluted net income (loss) per share is as follows for the years ended December 31 (in thousands, except share and per share amounts):

	2005		2004		2003
BASIC INCOME (LOSS) PER SHARE:
Net income (loss)	$	543	$	6,076	$	(2,007	)
Weighted average shares		2,273		2,549		2,727
Basic net income (loss) per share	$	238.94	$	2,383.67	$	(735.97	)
DILUTED INCOME (LOSS) PER SHARE:
Net income (loss)	$	543	$	6,076	$	(2,007	)
Weighted average shares—basic		2,273		2,549		2,727
Dilutive effect of stock options		81		93		—
Weighted average shares assuming dilutive effect of stock options		2,354		2,642		2,727
Diluted net income (loss) per share	$	230.72	$	2,299.77	$	(735.97	)

During 2003 the Company executed a 1,000-to-1 reverse stock split. Prior period amounts have been restated to reflect the reverse stock split.

F-26

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

15. Asset Retirement Obligations

In June 2001 the Financial Accounting Standards Board (FASB) issued SFAS No. 143 Accounting for Asset Retirement Obligations. SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and amends FASB Statement No. 19 Financial Accounting and Reporting by Oil and Gas Producing Companies. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Company adopted this standard as of January 1, 2003. The effect of this standard on the Company’s results of operations and financial position at adoption included an increase in long-term liabilities for plugging and abandonment costs of oil and natural gas properties of $1,304,000, net increase in oil and natural gas properties and equipment of $530,000, and a non-cash loss as a result of the cumulative effect of change in accounting principle, net of tax, of $448,000 (using a 6.25% discount factor). The Company recorded accretion expense of approximately $510,000, $78,000, and $48,000 in 2005, 2004, and 2003, respectively.

The Company recorded the following activity related to the asset retirement obligation for the years ended December 31, 2005 and 2004 (in thousands):

	2005			2004
Liability for asset retirement obligations, beginning of year	$	6,656		$	1,952
Obligations for wells sold with RB Operating Company		—			(238	)
Accretion expense		510			78
Obligations for new wells drilled or new estimates		3,177			275
Obligations for wells purchased in WG Acquisition		—			4,660
Obligations for wells sold or retired		(151	)		(71	)
Liability for asset retirement obligations, end of year	$	10,192		$	6,656

16. Recently Issued Accounting Pronouncements

In December 2004 the FASB issued SFAS No. 123R Share-Based Payments. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values and is effective for the first annual reporting period beginning after June 30, 2005. No share-based payment to employees or grants of employee stock options have ever been made. Management has not yet determined the impact of SFAS 123R on the Company’s future financial position or results of operations.

17. Income Taxes

The Company accounts for income taxes under the liability method as prescribed by SFAS 109. Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted rates expected to be in effect during the year in which the bases differences reverse.

F-27

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

B—WG ACQUISITION

The Company completed the WG Acquisition on December 17, 2004. The final adjusted purchase price was $82.6 million, including the assumption and payment of WG’s long-term debt of $24.5 million, the settlement of all outstanding derivative instruments of $14.4 million, and the balance (excluding the escrow) of $32.7 million was paid in cash. $11.0 million of the purchase price was deposited in two separate escrow accounts to provide funds against which the Company may make claims for any subsequently determined breach by WG of representations and warranties in the merger agreement and for potential losses that may arise in connection with certain existing litigation against WG (see Note K). The acquisition was financed with a credit facility provided by Wells Fargo Foothill, Inc. (Foothill) (see Note D). WG’s principal assets are producing oil properties located in north Texas, a gas plant and a significant block of undeveloped deep rights in held-by-production leases.

The WG acquisition was accounted for using the purchase method of accounting in accordance with SFAS No. 141, Business Combinations, and the purchase price has been allocated based on the estimated fair value of the individual assets acquired and liabilities assumed at the date of acquisition.

The assets acquired and purchase price allocation of the WG acquisition is as follows (in thousands):

Current assets	$	5,437
Oil and natural gas properties		97,243
Current liabilities		(4,233	)
Debt		(340	)
Asset retirement obligations		(4,661	)
Deferred taxes		(10,869	)
	$	82,577

The results of operations for the acquisition have been included in the consolidated statements of operations from the date of acquisition. The following unaudited pro forma information is presented as if the acquisition had occurred at the beginning of the periods presented (in thousands, except per share amounts):

	Year ended December 31, 2004			Year ended December 31, 2003
Revenues and other operating income	$	49,792		$	40,526
Loss before cumulative effect of change in accounting principle		(5,040	)		(4,909	)
Net loss	$	(5,040	)	$	5,357
Basic and diluted loss per share	$	(1,977.25	)	$	(1,964.43	)

C—SALE OF SUBSIDIARY

On April 23, 2004 the Company entered into a stock sale agreement with Range Energy I, Inc. to sell all of the issued and outstanding shares of common capital stock of RB Operating Company (RBOC), a wholly-owned subsidiary of the Company. The transaction closed on April 29, 2004 for a purchase price of

F-28

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

$22.5 million, subject to customary post-closing adjustments. The Company received proceeds of $21.8 million, net of transaction costs of $363,000 and cash paid of $814,000, from the sale, of which $17.9 million was used to pay the remaining balance on the Foothill loan and security agreement.

With this sale the Company sold approximately 27% of its proved oil and natural gas reserves. As this significantly altered the relationship between the Company’s capitalized costs and proved reserves, the Company recognized a gain on the sale of $12.1 million.

Although the Company sold a wholly-owned subsidiary, the subsidiary was formed solely to effect this transaction and the assets included in the subsidiary consisted solely of oil and gas properties located in New Mexico that were carved out of another RAM Energy entity. That RAM Energy entity continues to hold and operate significant other oil and gas properties, including oil and gas properties located in New Mexico, which have similar quality hydrocarbons and similar economic characteristics as those properties sold. Because the net assets of RBOC were part of a larger cash-flow-generating product group and, in the aggregate, did not represent a group that on their own would be a component of the Company, the conditions in Statement of Financial Accounting Standard No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets for reporting the gain associated with the sale of RBOC in discontinued operations were not met.

D—LONG-TERM DEBT

Long-term debt at December 31 consists of the following (in thousands):

	2005		2004
11.5% Senior Notes due 2008, net of discount	$	28,309	$	28,268
Credit facility		83,897		88,663
Installment loan agreements		640		413
		112,846		117,344
Less amount due within one year		560		3,891
	$	112,286	$	113,453

The amount of required principal payments for the next five years and thereafter, as of December 31, 2005, is as follows: 2006-$560,000; 2007-$58,000; 2008-$28,418,000; 2009 - none, and 2010 - $83,897,000.

1.    Senior Notes

In February 1998 the Company completed the sale of $115.0 million of 11.5% Senior Notes due 2008 in a public offering of which $28.2 million remained outstanding at December 31, 2005 and 2004. The Senior Notes are senior unsecured obligations of the Company and are redeemable at the option of the Company in whole or in part, at any time on or after February 15, 2005, at prices ranging from 111.5% to 103.8% of face amount to their scheduled maturity in 2008.

The indenture under which the Senior Notes were issued contained certain covenants, including covenants that limited (i) incurrence of additional indebtedness and issuances of disqualified capital stock, (ii) restricted payments, (iii) dividends and other payments affecting subsidiaries, (iv) transactions with affiliates and outside directors’ fees, (v) asset sales, (vi) liens, (vii) lines of business, (viii) merger, sale or consolidation and (ix) non-refundable acquisition deposits.

F-29

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

In November 2002 the Company recognized a gain (net of unamortized deferred offering and original issue discount costs and transaction fees) of $32.9 million as a result of the purchase of $63.475 million face amount of the Senior Notes. The Senior Notes, plus accrued interest of $1.988 million, were purchased at 46% of face amount and were canceled by the Company. The Company utilized borrowings under its revolving credit agreement and available cash to purchase the Senior Notes.

In connection with the Company’s November 2002 purchase of the Senior Notes, the indenture was amended to eliminate the covenant limitations described above.

At December 31, 2005 and 2004 the unamortized original issue discount associated with the Notes totaled approximately $87,000 and $128,000, respectively.

2.    Credit Facility

In November 2002 the Company entered into a two-part revolving credit facility with Foothill. It provided for a three year, $30 million revolving commitment. In December 2004 the Company entered into an amended and restated $90.0 million senior secured credit facility provided by Foothill. The facility included a $30.0 million term loan and a $60.0 million revolving credit facility. The Company and Foothill amended the credit facility on March 7, 2005. This amendment decreased the minimum EBITDA threshold and decreased the limit on the annual maximum amount of capital expenditures. On May 24, 2005 the credit facility was amended and restated in its entirety to accommodate Ableco Finance LLC as a participating lender. Significant changes in the amended and restated facility included increasing the interest rate on the term loan to Foothill’s base rate plus 5%, or 10.5%, whichever is greater, or LIBOR plus 7%, or 9.5%, whichever is greater, at the Company’s option. (12.25% at December 31, 2005).

In August and September 2005 the Company paid $6,400,000 in margin calls related to the derivative contracts required under the amended and restated facility. Principally due to these margin call requirements, the amended and restated credit facility was amended once again on October 11, 2005 with an effective date of September 30, 2005. That amendment increased the amount of the facility to $100.0 million and created a new special revolving facility in the amount of $10.0 million specifically to fund margin calls under the Company’s hedging contracts. The special revolving credit facility was funded in the amount of $6.9 million, including a $500,000 closing fee, and the revolving credit facility was reduced by that amount. The facility also included a conditional deferred fee in the amount of $375,000. On November 4, 2005 the counterparty to the Company’s hedging contracts refunded $4,600,000 of the margin deposits and on February 17, 2006 refunded $1,800,000 of the margin deposits. These amounts were applied to reduce the special revolving facility. The conditional deferred fee of $375,000 was paid during January, 2006, and accrued at December 31, 2005.

The amount of credit available under the credit facility at December 31, 2005 and 2004 was $3.4 million and $1.3 million, respectively.

On April 3, 2006, the Company and an institutional lender executed a new senior secured credit facility to replace the above mentioned credit facility. The outstanding amounts at December 31, 2005 were repaid in April, 2006 at the closing of this new credit facility. (See Note Q)

F-30

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

E—SUBSIDIARY GUARANTORS

The Company’s Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of the Company’s current and future subsidiaries (the “Subsidiary Guarantors”). The following table sets forth condensed consolidating financial information of the Subsidiary Guarantors. There are currently no restrictions on the ability of the Subsidiary Guarantors to transfer funds to the Company in the form of cash dividends, loans or advances.

F-31

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

The following represents the condensed consolidating balance sheets for the Company and its subsidiaries as of December 31, 2005 and 2004 (in thousands):

	Parent			Subsidiary Guarantors		Consolidating Adjustments			Total Consolidated Amounts
December 31, 2005
Current assets	$	3,355		$	26,527	$	(20,267	)	$	9,615
Property and equipment, net		14,167			116,965		—			131,132
Investment in subsidiaries		27,324			—		(27,324	)		—
Other assets		2,395			134		—			2,529
Total assets	$	47,241		$	143,626	$	(47,591	)	$	143,276
Current liabilities	$	28,713		$	5,849	$	(20,267	)	$	14,295
Long-term debt		29,767			82,519		—			112,286
Other non-current liabilities		3,038			9,126		—			12,164
Deferred income taxes		6,492			18,808		—			25,300
Total liabilities		68,010			116,302		(20,267	)		164,045
Stockholders’ equity (deficit)		(20,769	)		27,324		(27,324	)		(20,769	)
Total liabilities and stockholders’ equity (deficit)	$	47,241		$	143,626	$	(47,591	)	$	143,276

	Parent			Subsidiary Guarantors		Consolidating Adjustments			Total Consolidated Amounts
December 31, 2004
Current assets	$	1,203		$	8,002	$	—		$	9,205
Property and equipment, net		10,563			117,895		—			128,458
Investment in subsidiaries		11,882			—		(11,882	)		—
Other assets		2,661			—		—			2,661
Total assets	$	26,309		$	125,897	$	(11,882	)	$	140,324
Current liabilities	$	6,086		$	8,025	$	—		$	14,111
Long-term debt		34,489			78,964		—			113,453
Other non-current liabilities		3,104			5,194		—			8,298
Deferred income taxes		2,542			21,832		—			24,374
Total liabilities		46,221			114,015		—			160,236
Stockholders’ equity (deficit)		(19,912	)		11,882		(11,882	)		(19,912	)
Total liabilities and stockholders’ equity (deficit)	$	26,309		$	125,897	$	(11,882	)	$	140,324

F-32

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

The following represents the condensed consolidating statements of operations and statements of cash flows for the Company and its subsidiaries for the years ended December 31, 2005, 2004 and 2003 (in thousands):

	Parent			Subsidiary Guarantors			Consolidating Adjustments			Total Consolidated Amounts
Year ended December 31, 2005
Operating revenues	$	(2,064	)	$	57,463		$	—		$	55,399
Operating expenses		6,948			34,563			—			41,511
Operating income (loss)		(9,012	)		22,900			—			13,888
Other expense		2,477			(7,171	)		(7,845	)		(12,539	)
Income (loss) before income taxes		(6,535	)		15,729			(7,845	)		1,349
Income taxes		(7,078	)		7,884			—			806
Net income (loss)	$	543		$	7,845		$	(7,845	)	$	543
Cash flows provided by (used in) operating activities	$	9,592		$	8,767		$	—		$	18,359
Cash flows (used in) provided by investing activities		(3,108	)		(9,446	)		—			(12,554	)
Cash flows (used in) provided by financing activities		(6,910	)		—			—			(6,910	)
Increase (decrease) in cash and cash equivalents		(426	)		(679	)		—			(1,105	)
Cash and cash equivalents, beginning of year		1,043			132			—			1,175
Cash and cash equivalents, end of year	$	617		$	(547	)	$	—		$	70
Year ended December 31, 2004
Operating revenues	$	20,370		$	9,369		$	(80	)	$	29,659
Operating expenses		11,553			3,342			(80	)		14,815
Operating income		8,817			6,027			—			14,844
Other income		359			25			(5,419	)		(5,035	)
Income before income taxes		9,176			6,052			(5,419	)		9,809
Income taxes		3,100			633			—			3,733
Net income	$	6,076		$	5,419		$	(5,419	)	$	6,076
Cash flows provided by (used in) operating activities	$	85,784		$	(83,991	)	$	—		$	1,793
Cash flows (used in) provided by investing activities		(66,556	)		1,704			—			(64,852	)
Cash flows (used in) provided by financing activities		(20,109	)		82,225			—			62,116
Decrease in cash and cash equivalents		(881	)		(62	)		—			(943	)
Cash and cash equivalents, beginning of year		1,924			194			—			2,118
Cash and cash equivalents, end of year	$	1,043		$	132		$	—		$	1,175
Year ended December 31, 2003
Operating revenues	$	14,612		$	5,408		$	—		$	20,020
Operating expenses		14,320			1,092			—			15,412
Operating income		292			4,316			—			4,608
Other expense		(3,257	)		—			(1,614	)		(4,871	)
Income (loss) from continuing operations before income taxes		(2,965	)		4,316			(1,614	)		(263	)
Income taxes		(1,406	)		1,634			—			228
Income (loss) from continuing operations		(1,559	)		2,682			(1,614	)		(491	)
Loss from discontinued operations, net of tax		—			(1,068	)		—			(1,068	)
Net income (loss) before cumulative effect of change in accounting principle		(1,559	)		1,614			(1,614	)		(1,559	)
Cumulative effect of change in accounting principle, net of tax		(448	)		—			—			(448	)
Net income (loss)	$	(2,007	)	$	1,614		$	(1,614	)	$	(2,007	)
Cash flows provided by (used in) operating activities	$	17,756		$	(11,982	)	$	—		$	5,774
Cash flows (used in) provided by investing activities		(4,423	)		11,845			—			7,422
Cash flows (used in) provided by financing activities		(12,333	)		—			—			(12,333	)
Increase (decrease) in cash and cash equivalents		1,000			(137	)		—			863
Cash and cash equivalents, beginning of year		924			331			—			1,255
Cash and cash equivalents, end of year	$	1,924		$	194		$	—		$	2,118

F-33

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

Due to intercompany allocations among RAM Energy, Inc. and its subsidiaries, the above condensed consolidating information is not intended to present the Company’s subsidiaries on a stand-alone basis.

F—LEASES

The Company leases office space and certain equipment under non-cancelable operating lease agreements that expire on various dates through 2009. Approximate future minimum lease payments for operating leases at December 31, 2005 are as follows:

Year Ending December 31
2006	$	325,000
2007	$	316,000
2008	$	153,000
2009	$	3,000

Rent expense of approximately $519,000, $288,000, and $254,000 was incurred under operating leases in the years ended December 31, 2005, 2004, and 2003, respectively.

In conjunction with the WG Acquisition in 2004, the Company assumed capital leases for operating equipment. Future minimum lease payments for capital leases are approximately $59,000 in 2006.

G—DEFINED CONTRIBUTION PLAN

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all of its employees. The plan allows eligible employees to contribute up to 100% of their annual compensation, not to exceed the maximum amount permitted by IRS regulations. Employer contributions to the plan are discretionary. The Company paid contributions to the plan in 2005, 2004, and 2003 of $210,000, $190,000, and $163,000, respectively.

H—CAPITAL STOCK

Pursuant to a Special Retainer Agreement effective July 1, 1998, as amended, the Board of Directors granted an outside counsel an option to purchase 50 shares of the Company’s common stock, which became fully vested during 2000, and was exercisable through June 30, 2008. On April 4, 2002 the Board of Directors granted fully-vested options to purchase an additional 50 shares of the Company’s common stock and set the exercise price on all options at $2,500 per share, an amount which management believes approximated the per common share value of the Company at that date. Expense of approximately $72,000 related to the stock options was recognized in the 2002 statement of operations based on the estimated fair value of the stock options. As of December 31, 2005 after the redemption of one-sixth of the outstanding stock options in August 2004 described below, options to purchase 83.33 shares remained outstanding.

The fair value of each option grant was estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions: risk-free interest rate of 5.0%, no expected dividends, expected life of 6.7 years and no volatility.

In January 1998 the Company adopted its 1998 Stock Incentive Plan and reserved 550 shares of common stock for issuance under the plan. No awards have been granted under the Plan as of December 31, 2005.

F-34

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

In April 2002 the Company amended its Certificate of Incorporation to eliminate its authorized preferred stock and reduce its authorized common stock to 5,000,000 shares. Prior to the amendment, the Company’s authorized capital consisted of 5,000,000 shares of preferred stock, none of which were issued and outstanding, and 15,000,000 shares of common stock.

In December 2003 the Company effected a 1,000-to-1 reverse stock split and amended its Certificate of Incorporation to reduce its authorized common stock to 5,000 shares, with a par value of $10.00 per share. Prior period amounts have been restated to reflect the reverse stock split.

In August 2004 the Company repurchased and retired one-sixth of its outstanding common shares and vested stock options for $5.0 million and $135,000, respectively. The cash paid to repurchase the common shares and stock options was equal to their respective estimated fair values on the date of settlement and, therefore, is recorded as a reduction of equity. Absent a market price for or comparable to the untraded securities, management estimated the fair value of the common stock by dividing the estimated net asset value per share by the total number of shares outstanding. Management believes the estimation method and assumptions utilized represent the best available evidence of the value of the equity securities at the settlement date.

The Company declared cash dividends of $804,000 for the year ended December 31, 2003, $294.68 per share. The unpaid dividends at December 31, 2003 are recorded as other accrued liabilities on the balance sheet and were paid in January 2004. The Company declared cash dividends of $1,200,000 for the year ended December 31, 2004, $146.68 per share for $800,000 declared prior to the stock repurchase, and $176.02 per share for the $400,000 declared subsequent to the stock repurchase. The Company declared cash dividends of $1,400,000 for the year ended December 31, 2005, $615.93 per share. All dividends declared in 2005 and 2004 were paid by the respective year ends.

I—INCOME TAXES

The (provision) benefit for income taxes is comprised of (in thousands):

	Year Ended December 31,
	2005			2004			2003
Current	$	393		$	(6,892	)	$	(4,190	)
Deferred		(1,199	)		3,159			3,962
Provision for income tax expense	$	(806	)	$	(3,733	)	$	(228	)

The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before provision for income taxes. The significant differences between pre-tax book income and taxable book income relate to non-deductible personal expenses, meals and entertainment expenses and state income taxes.

F-35

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

The sources and tax effects of the differences are as follows (in thousands):

	Year Ended December 31,
	2005			2004			2003
Income tax provision at the federal statutory rate (34%)	$	(459	)	$	(3,088	)	$	(73	)
State income (tax) benefit, net of federal benefit		12			(361	)		(6	)
Meals and entertainment expense		(34	)		0			0
Non-deductible dues		(15	)		0			0
Non-deductible related party expenses		(302	)		(284	)		(149	)
Other		(8	)		0			0
Income tax provision	$	(806	)	$	(3,733	)	$	(228	)

The Company’s income tax provision was computed based on the federal statutory rate and the average state statutory rates, net of the related federal benefit.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

F-36

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):

	December 31,
	2005			2004
Deferred tax assets:
Current:
Hedge termination payment	$	0		$	4,894
Accrued expenses and other		163			85
	$	163		$	4,979
Valuation allowance		0			0
Net current deferred tax assets	$	163		$	4,979
Noncurrent deferred tax assets:
Net operating loss carryforward	$	1,510		$	1,887
Accrued liabilities and other		3,059			1,855
	$	4,569		$	3,742
Valuation allowance		0			0
Net noncurrent deferred tax assets	$	4,569		$	3,742
Deferred tax liabilities:
Current:
Prepaid expenses and other	$	(230	)		0
	$	(230	)	$	0
Noncurrent:
Depreciable/depletable property, plant and equipment	$	(20,236	)	$	(23,257	)
Other		(0	)		(0	)
Total noncurrent deferred tax liabilities	$	(20,236	)	$	(23,257	)
Net noncurrent deferred tax liability	$	(20,466	)	$	(19,515	)
Net deferred tax liability	$	(15,734	)	$	(14,536	)

As of December 31, 2005, the Company has federal net operating loss carryforwards of approximately $4.02 million for tax purposes, which were an inherited attribute from the WG Energy Holdings, Inc. acquisition during 2004. These net operating loss carryforwards are subject to the ownership change limitation provisions of Section 382 of the Internal Revenue Code. However, based upon the value of WG Energy Holdings, Inc. at the time of the acquisition, the amount of these net operating losses that may be used annually should be sufficient to allow the losses to be utilized prior to their expiration. Accordingly, the Company believes that it will more likely than not be able to utilize these losses and that no valuation allowance for the deferred tax asset associated therewith is required. If not used, these carryforwards will generally expire between 2021 and 2023. In addition, the Company has generated net operating loss carryforwards for state income tax purposes, which the Company believes will more likely than not be realized during the relevant carryforward periods; however, such amounts have not been separately

F-37

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

disclosed in the financial statements as the Company does not believe that these net operating losses are material to the amounts presented herein.

The Company has reported the recovery of tax basis amounts in certain assets in prior years that generated net operating losses for tax return filing purposes; however, the Company has not recorded a tax benefit for such amounts due to certain factual and technical issues related thereto. The Company will record the benefit for such tax basis amounts in future periods when it can appropriately conclude that the realization of such benefit is more likely than not assured.

J—SALE OF PIPELINE SYSTEM

On July 18, 2003 the Company entered into an agreement to sell its oil and natural gas pipeline system in north central Oklahoma to Continental Gas, Inc. (CGI) for $15.0 million, effective August 1, 2003, and subject to certain adjustments. $3.0 million in settlement of the claim by CGI reduced the sale price. (see Note K). The sale of the pipeline closed July 31, 2003 and approximately $11.8 million net proceeds were used to reduce the Company’s credit facility.

The results of operations and cash flows related to the pipeline system are reflected in the accompanying financial statements as discontinued operations. For the year ended December 31, 2003, revenues for discontinued operations were $14,500,000. Interest expense of $609,000 for the year ended December 31, 2003 has been allocated to discontinued operations in the statements of operations.

No gain or loss on disposal was recorded because impairment provisions had written the pipeline system down to its realizable value.

K—COMMITMENTS AND CONTINGENCIES

In November 2004 Ted Collins, Jr. filed a lawsuit against WG Energy Holdings, Inc. and Michael G. Grella, the former president of that company. Mr. Collins alleged that WG and Mr. Grella failed to timely apply a $1.5 million advance toward developing the shallow formations underlying certain leases, and failed to deliver assignments of certain interests in those leases, both as allegedly required by the participation agreement between them. Mr. Collins further claimed that WG failed to account to him for revenues allegedly accruing to him under the terms of the participation agreement. Mr. Collins sought an accounting and to have the partial assignment and/or participation agreement reformed based on allegations of mutual mistake, and further pled claims of fraud and negligent misrepresentation. He did not specify the amount of damages claimed. As this lawsuit existed at the time of the Company’s acquisition of WG, a $5 million escrow was established as a reserve for this lawsuit (see Note B). A settlement agreement was reached on September 14, 2005, whereby Ted Collins Jr. and the defendants settled and released all claims that had been asserted and those that might have been asserted in the lawsuit. On October 19, 2005, RWG received $250,000 from the escrow account as a result of this settlement.

In June 2003 a lawsuit was filed by CGI against Great Plains Pipeline Company (GPPC), a wholly owned subsidiary of the Company, in the District Court of Garfield County, Oklahoma. GPPC and CGI were parties to a Gas Service Contract (the Contract) dated November 22, 1996; pursuant to which GPPC delivered to CGI all of the gas that flowed through GPPC’s pipeline system. CGI compressed and processed the gas and then redelivered thermally equivalent volumes to GPPC at the tailgate of the CGI processing plant in Woods County. The term of the Contract was for the life of the leases from which GPPC purchased gas in a specified service area.

F-38

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

In the lawsuit CGI alleged that over several years GPPC delivered gas under the Contract that was produced from wells and leases lying outside the specified service area and that such gas was not covered by and should not have been delivered under the Contract. CGI alleged that only gas produced from wells and leases lying inside the service area should be counted for purposes of determining whether or not a compression and processing fee was due, that when outside volumes were excluded, compressing and processing fees were due CGI, and with respect to the outside volumes GPPC delivered under the Contract, GPPC owed CGI a market rate for compressing and processing services performed with respect to such gas.

As a part of the agreement for the sale of the pipeline system by GPPC to CGI, the parties agreed to $3.0 million as consideration for a contemporaneous mutual release by CGI and GPPC of all claims of every nature arising out of the Contract. A provision for litigation settlements in the amount of $3.0 million was recorded at December 31, 2002 as a current liability and netted from the proceeds received from the sale of the pipeline (see Note J).

In April 2002 a lawsuit was filed in the District Court for Woods County, Oklahoma against the Company, certain of its subsidiaries and various other individuals and unrelated companies, by lessors and royalty owners of certain tracts of land, which were sold to a subsidiary of Chesapeake Energy Corporation in 2001. The petition claims that additional royalties are due, because Carmen Field Limited Partnership (CFLP), a wholly-owned subsidiary of the Company, resold oil and gas purchased at the wellhead for an amount in excess of the price upon which royalty payments were based and paid no royalties on natural gas liquids extracted from the gas at plants downstream of the system. Other allegations include under-measurement of oil and gas at the wellhead by CFLP, failure to pay royalties on take-or-pay settlement proceeds and failure to properly report deductions for post-production costs in accordance with Oklahoma’s check stub law.

Company defendants have filed answers in the lawsuit denying all material allegations set out in the petition. The Company believes that fair and proper accounting was made to the royalty owners for production from the subject leases and intends to vigorously defend the lawsuit. Management is unable to estimate a range of potential loss, if any, related to this lawsuit, and accordingly no amounts have been recorded in the consolidated financial statements. In the event the court should find Company defendants liable for damages in the lawsuit, a former joint venture partner is contractually obligated to pay a portion of any damages assessed against the Company defendants up to a maximum contribution of approximately $2.8 million.

In a suit filed in mid-2001 by a large independent oil and gas exploration and production company, claims arising from gas balancing on seven wells located in western Oklahoma, then operated by the Company, were made. In December 2002, a provision for settlement of this claim was made in the amount of $140,000, which was paid in May 2003.

The Company is also involved in other legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company’s financial position or results of operations.

The Company has established a severance agreement for the president and CEO of the Company. This agreement provides for severance benefits to be paid upon involuntary separation as a result of actions taken by the Company or its successors. At December 31, 2005 and 2004, the severance benefits under this

F-39

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

agreement were approximately $1,650,000 and $1,750,000, respectively. A provision for these benefits will not be made until an involuntary termination is probable.

Pursuant to a Special Retainer Agreement effective July 1, 1998, as amended, the Company is obligated to pay an outside counsel law firm approximately $360,000 in the event that the agreement is terminated by reason of expiration of term, by counsel for good reason, by reason of change in control, or by the Company at will. A provision for the payment will not be made until termination of the agreement is probable.

L—HEDGING ACTIVITIES

The Company utilizes a hedging program to reduce its exposure to unfavorable changes in oil and natural gas prices that are subject to significant and often volatile fluctuation. This program customarily involves the purchase of put options to provide a price floor for its production, put/call collars that establish both a floor and a ceiling price to provide price certainty within a fixed range, put/call/call collars that establish a secondary floor above the put/call collar ceiling, forward sale contracts for specified monthly volumes at prices determined with reference to the natural gas futures market and swap arrangements that establish an index-related price above which the Company pays the hedging partner and below which the Company is paid by the hedging partner. When market prices for oil and natural gas decline, the decline in the value of the cash flows from the Company’s forecasted natural gas production designated as being hedged is substantially offset by gains in the value of the hedging contracts. Conversely, when market prices increase, the increase in the value of the cash flows from the Company’s forecasted natural gas production designated as being hedged is substantially offset by losses in the value of the hedging contracts.

In 2002 the Board of Directors approved risk management policies and procedures to utilize these hedging contracts for the reduction of defined commodity price risks in alignment with the terms of the Company’s revolving credit facility with Foothill. These policies prohibit speculation with derivatives, limit the amount of production hedged and limit hedge agreements to counterparties with appropriate credit standings.

During 2005, 2004, and 2003 the Company entered into numerous derivative contracts. The Company did not formally designate these transactions as hedges as required by SFAS No. 133 in order to receive hedge accounting treatment. Accordingly, all gains and losses on the derivative financial instruments during 2005, 2004, and 2003 have been recorded in the statements of operations.

At December 31, 2005 the Company had collars in place on 45,625 barrels/month through 2006 and 30,417 barrels/month through 2007. The 45,625 barrels/month in 2006 had a weighted average floor and ceiling of $42.51 and $60.56, respectively. The 30,417 barrels/month in 2007 had a weighted average floor and ceiling of $35.00 and $69.74, respectively. For natural gas, the Company had collars in place on 159,583 Mmbtu/month through 2006 and 150,000 Mmbtu/month for the three months ending March 2007. The 159,583 Mmbtu/month in 2006 had a weighted average floor and ceiling of $6.23 and $8.86, respectively. The 150,000 Mmbtu/month for the three months ending March 2007 had a weighted average floor and ceiling of $7.00 and $11.95. The Company also had purchased put options on 7,604 barrels/month of crude oil through 2006 at a weighted average floor price of $40.00. The Company purchased call options on 157,000 Mmbtu/month of natural gas for eight months in 2006 at a weighted average floor price of $9.94.

F-40

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

At December 31, 2004 the Company had purchased put options on 37,958 barrels/month of crude oil through December 2005 with a floor price of $40.00 per barrel. For natural gas the Company had purchased collars on 152,000 Mmbtu/month through October 2005; the weighted average floor price was $5.65 per Mmbtu, and the weighted average ceiling price was $7.84 per MMbtu. An asset of approximately $1,627,000 was recorded in the consolidated balance sheets.

The primary market risk related to the Company’s derivative contracts are the volatility in commodity prices. However, this market risk is offset by the gain or loss recognized upon the related sale or purchase of the commodity that is hedged. Credit risk relates to the risk of loss as a result of nonperformance by the Company’s counterparties. The counterparties are primarily major trading companies which management believes present minimal credit risks.

M—LIQUIDITY

As of December 31, 2005, the Company has an accumulated deficit of $20,865,000 and a working capital deficit of $4,680,000. Management believes that borrowings currently available to the Company under the Company’s new credit facilities ($42 million available at April 6, 2006), the balance of unrestricted cash, and anticipated cash flows from operations will be sufficient to satisfy its currently expected capital expenditures, working capital, and debt service obligations for the foreseeable future. The actual amount and timing of future capital requirements may differ materially from estimates as a result of, among other things, changes in product pricing and regulatory, technological and competitive developments. Sources of additional financing may include commercial bank borrowings, vendor financing and the sale of oil and natural gas properties or equity or debt securities. Management cannot assure that any such financing will be available on acceptable terms or at all.

N—RELATED PARTY TRANSACTIONS

For the years ended December 31, 2005, 2004, and 2003 the Company paid expenses in the amount of $0, $0, and $260,000, respectively, for expenses on behalf of the Danish Knights, a Limited Partnership, which is owned by one of the shareholders of the Company.

The Company paid rent expense of approximately $29,000, $66,000, and $54,000 relating to a condominium for one of the shareholders of the Company for the years ended December 31, 2005, 2004, and 2003, respectively.

For the years ended December 31, 2005, 2004, and 2003 approximately $499,000, $792,000, and $299,000, respectively, of expenses (excluding the rent payments discussed above) for the shareholders of the Company are included in general and administrative expenses in the consolidated statements of operations, some of which may be personal in nature.

In June 2005 the Company sold overriding royalty interests in certain properties located in Jack and Wise Counties, Texas for $2.3 million to Bridgeport Royalties, LLC. Bridgeport Royalties, LLC is a related party of the Company, owned and operated by the owners and several officers and employees of the Company, in addition to outside counsel. No gain on the sale was recognized and the proceeds were applied to reduce the outstanding balance under the Company’s revolving credit facility.

F-41

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

O—DEFERRED COMPENSATION

On April 21, 2004 the Company adopted a Deferred Bonus Compensation Plan (the Plan) for senior management employees of the Company. The Plan is to provide additional compensation for significant business transactions with a portion of each bonus to be deferred to encourage retention of key employees. Determination of significant business transactions and terms of awards is made by a committee comprised of the shareholders of the Company.

During 2004 and 2005 three members of senior management were granted awards. Each award provides for a total cash compensation of $75,000 and vests on each anniversary date for three years beginning on July 1, 2004 and July 1, 2005, respectively. Receipt of the award is contingent on the members being employed on the anniversary date. Should there be a change of control or involuntary termination, as defined in the award contract, each member will become fully vested in his award. Compensation expense is recorded on a straight-line basis. For the years ended December 31, 2005 and 2004, $150,000 and $112,500, respectively, has been recorded as compensation expense in the consolidated statements of operations.

P—MERGER AGREEMENT

In October 2005 the Company entered into a definitive merger agreement with Tremisis Energy Acquisition Corporation pursuant to which the Company will become a wholly-owned subsidiary of Tremisis.

Q—SUBSEQUENT EVENTS

On April 3, 2006, the Company entered into and closed a new secured credit facility with a financial institution, consisting of a $150.0 million, five-year term loan facility and a $150.0 million, four-year revolving credit facility.

At closing, $90 million of the term loan was advanced and $42 million remained available under the revolving credit facility. The remainder of the term loan facility will be available, subject to approval of the lenders, for certain future needs, including acquisitions. The new revolving credit facility is scheduled to mature in April 2010, until which time amounts may be borrowed and repaid as often as needed, subject to a borrowing base limitation that is re-determined semi-annually, based on oil and gas reserves. The term loan facility is scheduled to mature in April 2011, with permitted prepayments after the first year, subject to a prepayment premium in the second and third years of the term. Advances under the revolving credit facility will bear interest at LIBOR plus 2% per annum, while amounts outstanding under the term loan will bear interest at LIBOR plus 5.5% to 6.0% per annum. Obligations under the new credit facility are secured by a first lien on substantially all assets of the Company and its subsidiaries. The initial advance under the new credit facility was used to refinance the Company’s existing credit facility, to pay expenses associated with establishing the new facility, and to fund $10.0 million of the pre-closing dividend/redemption payments permitted by the merger agreement (See Note P). Subsequent advances may be used to:

Ÿ repurchase all of the Company’s outstanding 11 ¹/2% Senior Notes due 2008 ($28.4 million principal amount), and

Ÿ for general working capital purposes.

F-42

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

The new credit facility contains financial covenants requiring the Company to maintain certain ratios, including a current ratio, a ratio of earnings before interest, taxes, depreciation and amortization, or EBITDA, to interest expense, a ratio of total indebtedness to EBITDA, and a ratio of asset value to total indebtedness. In addition, the new credit facility contains other affirmative and negative covenants customary in lending transactions of this nature, including the maintenance by the Company of hedging contracts for a minimum and maximum amount of projected oil and natural gas production from its properties. Amounts advanced under the new credit facility prior to the closing of the merger will not cause the Company to exceed the total indebtedness limitation at closing as provided in the merger agreement (See Note P).

As a result of the refinancing, the current portion of long-term debt under the Company’s previous credit facility as of December 31, 2005 has been reclassified to long-term debt.

On April 6, 2006, the Company effected a redemption of a portion of the outstanding shares of its common stock for an aggregate redemption payment of $10.0 million.

R—SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION (UNAUDITED)

The Company has interests in oil and natural gas properties that are principally located in Texas, Louisiana, Oklahoma, and New Mexico. The Company does not own or lease any oil and natural gas properties outside the United States of America.

The Company retains independent engineering firms to provide year-end estimates of the Company’s future net recoverable oil, natural gas and natural gas liquids reserves. Estimated proved net recoverable reserves as shown below include only those quantities that can be expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods.

Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure is required for re-completion.

Capitalized costs relating to oil and natural gas producing activities and related accumulated depreciation and amortization at December 31 are summarized as follows (in thousands):

	2005			2004			2003
Proved oil and natural gas properties	$	160,704		$	146,598		$	60,760
Accumulated depreciation and amortization		(32,602	)		(20,074	)		(24,006	)
	$	128,102		$	126,524		$	36,754

F-43

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

Costs incurred in oil and natural gas producing activities for the years ended December 31 are as follows (in thousands, except per equivalent oil barrel):

	2005			2004			2003
Acquisition of proved properties	$	155		$	96,819		$	—
Development costs		11,864			5,173			5,056
Exploration costs		1,507			727			202
Sale of producing properties		(2,471	)		(16,881	)		(187	)
Additional asset retirement obligation		3,051			—			—
	$	14,106		$	85,838		$	5,071
Amortization rate per equivalent oil barrel	$	8.93		$	5.89		$	5.64

Net quantities of proved and proved developed reserves of oil and natural gas, including condensate and natural gas liquids, are summarized as follows:

	Crude Oil (Thousand Barrels)		Natural Gas (Million Cubic Feet)		Natural Gas Liquids (Thousand Barrels)
December 31, 2002	2,451		35,920		—
Extensions and discoveries	258		1,152		—
Sales of reserves in place	—		(16	)	—
Purchases of reserves in place	—		1,114		—
Revisions of previous estimates	(110	)	(1,269	)	5
Production	(277	)	(2,334	)	(5	)
December 31, 2003	2,322		34,567		—
Extensions and discoveries	17		3,015		—
Sales of reserves in place	(1,319	)	(4,890	)	—
Purchases of reserves in place	9,482		10,013		2,092
Revisions of previous estimates	343		(2,582	)	7
Production	(178	)	(1,928	)	(12	)
December 31, 2004	10,667		38,195		2,087
Extensions and discoveries	5		1,297		—
Sales of reserves in place	(25	)	(1,305	)	—
Purchases of reserves in place	—		—		—
Revisions of previous estimates	1,339		(1,272	)	(26	)
Production	(787	)	(2,681	)	(170	)
December 31, 2005	11,199		34,234		1,891
Proved developed reserves:
December 31, 2002	2,234		28,379		—
December 31, 2003	2,151		26,237		—
December 31, 2004	6,198		31,048		1,611
December 31, 2005	7,337		26,752		1,396

F-44

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

The following is a summary of a standardized measure of discounted net cash flows related to the Company’s proved oil and natural gas reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves were computed using oil and natural gas prices as of the end of the period presented. Future development and production costs attributable to the proved reserves were estimated assuming that existing conditions would continue over the economic lives of the individual leases and costs were not escalated for the future. Estimated future income tax expenses were calculated by applying future statutory tax rates (based on the current tax law adjusted for permanent differences and tax credits) to the estimated future pretax net cash flows related to proved oil and natural gas reserves, less the tax basis of the properties involved.

The Company cautions against using this data to determine the fair value of its oil and natural gas properties. To obtain the best estimate of fair value of the oil and natural gas properties, forecasts of future economic conditions, varying discount rates, and consideration of other than proved reserves would have to be incorporated into the calculation. In addition, there are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production that impair the usefulness of the data.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves at December 31 are summarized as follows (in thousands):

	2005			2004			2003
Future cash inflows	$	1,037,337		$	711,781		$	281,149
Future production costs Future development costs		(336,008 (45,271	) )		(247,314 (36,495	) )		(70,644 (9,534	) )
Future income tax expenses		(219,640	)		(136,669	)		(69,787	)
Future net cash flows		436,418			291,303			131,184
10% annual discount for estimated timing of cash flows		(209,758	)		(129,983	)		(63,469	)
Standardized measure of discounted future net cash flows	$	226,660		$	161,320		$	67,715

F-45

RAM ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and 2004

The following are the principal sources of change in the standardized measure of discounted future net cash flows of the Company for each of the three years in the period ended December 31 (in thousands):

	2005			2004			2003
Standardized measure of discounted future net cash flows at beginning of year	$	161,320		$	67,715		$	53,369
Changes during the year:
Sales and transfers of oil and natural gas produced, net of production costs		(46,823	)		(13,112	)		(15,118	)
Net changes in prices and production costs		133,301			(5,758	)		23,634
Extensions and discoveries, less related costs		2,311			9,337			5,153
Development costs incurred and revisions		(8,771	)		4,691			(2	)
Sales of reserves in place		(2,551	)		(21,507	)		(26	)
Purchases of reserves in place		—			152,083			1,643
Revisions of previous quantity estimates		8,219			(4,560	)		459
Net change in income taxes		(43,960	)		(38,026	)		(9,472	)
Accretion of discount		23,620			10,457			8,075
Net change		65,340			93,605			14,346
Standardized measure of discounted future net cash flows at end of year	$	226,660		$	161,320		$	67,715

Prices used in computing these calculations of future cash flows from estimated future production of proved reserves were $58.63, $40.25, and $29.25 per barrel of oil at December 31, 2005, 2004, and 2003, respectively, $9.14, $6.02, and $6.17 per thousand cubic feet of natural gas at December 31, 2005, 2004, and 2003, respectively, and $35.89 and $27.56 per barrel of natural gas liquids at December 31, 2005 and 2004, respectively.

F-46

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Tremisis Energy Acquisition Corporation

New York, NY

We have audited the accompanying balance sheets of Tremisis Energy Acquisition Corporation (a corporation in the development stage) as of December 31, 2005 and 2004 and the related statements of operations, stockholders’ equity and cash flows for the year ended December 31, 2005, the period from February 5, 2004 (inception) to December 31, 2004 and the period from February 5, 2004 (inception) to December 31, 2005. 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. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1, the Company’s Certificate of Incorporation provides for mandatory liquidation of the Company, in the event that the Company does not consummate a business combination by May 18, 2006. As discussed in Note 3, the Company plans to merge with RAM Energy, Inc. subject to stockholder approval prior to May 18, 2006; and thus avoid such mandatory liquidation.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Tremisis Energy Acquisition Corporation as December 31, 2005 and 2004 and the related statements of operations and cash flows for the year ended December 31, 2005, the period from February 5, 2004 (inception) to December 31, 2004 and the period from February 5, 2004 (inception) to December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company is required to consummate a business combination by May 18, 2006. The possibility of such merger not being consummated raises substantial doubt about its ability to continue as a going concern, and the financial statements do not included any adjustments that might result from the outcome of this uncertainty.

/s/ BDO Seidman, LLP

New York, NY

February 10, 2006

F-47

TREMISIS ENERGY ACQUISITION CORPORATION

(A CORPORATION IN THE DEVELOPMENT STAGE)

BALANCE SHEETS

	December 31, 2005		December 31, 2004
Assets
Current assets:
Cash and cash equivalents	$	290,751	$	834,094
U.S. Government Securities held in Trust Account (Note 1)		34,256,092		33,351,358
Accrued interest receivable, Trust Account (Note 1)		167,172		91,170
Prepaid expenses		25,314		22,125
Total current assets		34,739,329		34,298,747
Deferred acquisition costs (Note 3)		540,907		—
Furniture and equipment (net of accumulated depreciation of $4,919 and $1,418)		8,954		6,558
Total assets	$	35,289,190	$	34,305,305
Liabilities and Stockholders’ Equity
Current liabilities:
Accrued expenses	$	37,373	$	26,680
Accrued acquisition costs (Note 3)		423,304		—
Taxes payable		224,887		26,000
Total current liabilities		685,564		52,680
Common stock, subject to possible conversion 1,264,368 shares at conversion value (Note 1)		6,881,213		6,685,164
Commitment (Note 5)
Stockholders’ equity (Notes 2, 3, 4, 6 and 7)
Preferred stock, $.0001 par value, authorized 1,000,000 shares; none issued		—		—
Common stock, $.0001 par value
Authorized 30,000,000 shares; Issued and outstanding 7,700,000 shares (which includes 1,264,368 subject to possible conversion)		770		770
Additional paid-in capital		27,306,117		27,502,166
Earnings accumulated during the development stage		415,526		64,525
Total stockholders’ equity		27,722,413		27,567,461
Total liabilities and stockholders’ equity	$	35,289,190	$	34,305,305

See accompanying summary of significant accounting policies and notes to financial statements.

F-48

TREMISIS ENERGY ACQUISITION CORPORATION

(A CORPORATION IN THE DEVELOPMENT STAGE)

STATEMENTS OF OPERATIONS

	Year Ended December 31, 2005			Period from February 5, 2004 (inception) to December 31, 2004			Period from February 5, 2004 (inception) to December 31, 2005
Expenses:
General and administrative expenses (Note 5)	$	324,786		$	164,392		$	489,178
Operating loss		(324,786	)		(164,392	)		(489,178	)
Interest income		989,337			308,032			1,297,369
Income before provision for taxes		664,551			143,640			808,191
Provision for taxes (Note 8)		(313,550	)		(79,115	)		(392,665	)
Net Income	$	351,001		$	64,525		$	415,526
Accretion of Trust Account relating to common stock subject to possible conversion		(196,049	)		(59,875	)		(255,924	)
Net income attributable to common stockholders	$	154,952		$	4,650		$	159,602
Basic and fully diluted income per share	$	0.02		$	0.00
Weighted average common shares outstanding		7,700,000			5,739,057

See accompanying summary of significant accounting policies and notes to financial statements.

F-49

TREMISIS ENERGY ACQUISITION CORPORATION

(A CORPORATION IN THE DEVELOPMENT STAGE)

STATEMENTS OF STOCKHOLDER’S EQUITY

	Common Stock			Additional Paid-In Capital			Earnings accumulated during the development stage		Total
	Shares	Amount
Balance, February 5, 2004 (inception)	—	$	—	$	—		$	—	$	—
Issuance of common stock to initial stockholders	1,375,000		137		24,863			—		25,000
Sale of 6,325,000 units and underwriters’ option, net of underwriters’ discount and offering expenses (includes 1,264,368 share subject to Possible conversion)	6,325,000		633		27,537,178			—		27,537,811
Accretion of Trust Account relating to common stock subject to conversion	—		—		(59,875	)		—		(59,875	)
Net income for the period	—		—		—			64,525		64,525
Balance, December 31, 2004	7,700,000		770		27,502,166			64,525		27,567,461
Accretion of Trust Account relating to common stock subject to possible conversion	—		—		(196,049	)		—		(196,049	)
Net income for the year ended December 31, 2005	—		—		—			351,001		351,001
Balance, December 31, 2005	7,700,000	$	770	$	27,306,117		$	415,526		27,722,413

See accompanying summary of significant accounting policies and notes to financial statements.

F-50

TREMISIS ENERGY ACQUISITION CORPORATION

(A CORPORATION IN THE DEVELOPMENT STAGE)

STATEMENTS OF CASH FLOWS

	Year ended December 31, 2005			February 5, 2004 (inception) to December 31, 2004			February 5, 2004 (inception) to December 31, 2005
Cash Flows From Operating Activities
Net income for the period	$	351,001		$	64,525		$	415,526
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation		3,501			1,418			4,919
Gain on maturities of U.S. Government Securities held in Trust Account		(904,576	)		(208,605	)		(1,113,181	)
Changes in operating assets and liabilities:
Increase in prepaid expenses		(3,189	)		(22,125	)		(25,314	)
Increase in accrued interest receivable		(76,002	)		(91,170	)		(167,172	)
Increase in accrued expenses		10,693			26,680			37,373
Increase in income tax payable		198,887			26,000			224,887
Net cash used in operating activities		(419,685	)		(203,277	)		(622,962	)
Cash Flows from Investing Activities
Purchases of U.S. Government Securities held in Trust Account		(237,102,158	)		(66,493,753	)		(303,595,911	)
Maturity of U.S. Government Securities held in Trust Account		237,102,000			33,351,000			270,453,000
Deferred acquisition costs		(117,603	)		—			(117,603	)
Purchase of furniture and equipment		(5,897	)		(7,976	)		(13,873	)
Net cash used in investing activities		(123,658	)		(33,150,729	)		(33,274,387	)
Cash Flows from Financing Activities
Proceeds from public offering of 6,325,000 units and underwriter option, net		—			34,163,100			34,163,100
Proceeds from issuance of common stock to initial stockholders		—			25,000			25,000
Proceeds from note payable, stockholder		—			77,500			77,500
Repayment of note payable, stockholder		—			(77,500	)		(77,500	)
Net cash provided by financing activities		—			34,188,100			34,188,100
Net (decrease) increase in cash and cash equivalents		(543,343	)		834,094			290,751
Cash and cash equivalents at beginning of the period		834,094			—			—
Cash and cash equivalents end of the period	$	290,751		$	834,094		$	290,751
Supplemental disclosure of cash flow information:
Cash paid during the period for income taxes	$	114,663		$	53,115		$	147,028
Supplemental disclosure of non cash activity:
Accrued acquisition costs	$	423,304		$	—		$	423,304
Accretion of Trust Account relating to common stock subject to possible conversion	$	196,049		$	59,875		$	255,924

See accompanying summary of significant accounting policies and notes to financial statements.

F-51

TREMISIS ENERGY ACQUISITION CORPORATION

(A CORPORATION IN THE DEVELOPMENT STAGE)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Furniture and Equipment	Furniture and equipment is stated at cost, net of accumulated depreciation. Depreciation if computed on a straight-line basis over the estimated lives commencing upon the date the asset is placed in service.
Cash and Cash Equivalents	The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
Securities Held in Trust Account	The Company carries its investment in US Government Securities at cost which approximates fair value.
Income Taxes	The Company follows Statement of Financial Accounting Standards No. 109 (“SFAS No. 109”), “Accounting for Income Taxes” which is an asset and liability approach that requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns.
Net Income Per Share	Net income per share is computed on the basis of the weighted average number of common shares outstanding during the period. Basic earnings per share excludes dilution and is computed by dividing net income after accretion attributable to common stockholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the entity. Since the effect of outstanding warrants to purchase common stock is antidilutive, they have been excluded from the Company’s computation of net income per share.
Use of Estimates	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of expenses during the reporting period. Actual results could differ from those estimates.
Reclassification	Certain items have been reclassified from prior periods to conform with the current period presentation.

F-52

TREMISIS ENERGY ACQUISITION CORPORATION

(A CORPORATION IN THE DEVELOPMENT STAGE)

NOTES TO FINANCIAL STATEMENTS

1. Organization and Business Operations The Company was incorporated in February 5, 2004 as a blank check company whose objective is to acquire an operating business in either the energy or the environmental industry and their related infrastructures.

The registration statement for the Company’s initial public offering (“Offering”) was declared effective May 13, 2004. The Company consummated the offering on May 18, 2004 and received net proceeds of $34,163,100 (Note 2). The Company’s management has broad discretion with respect to the specific application of the net proceeds of this Offering, although substantially all of the net proceeds of this Offering are intended to be generally applied toward consummating a business combination with an operating business in the energy and environmental industry and their related infrastructures (“Business Combination”). An amount of $34,423,264 and $33,442,528 (which includes accrued interest of $167,172 and $91,170) as of December 31, 2005 and 2004, respectively, is being held in an interest-bearing trust account (“Trust Account”) until the earlier of (i) the consummation of its first Business Combination or (ii) liquidation of the Company. Under the agreement governing the Trust Account, funds will only be invested in United States government securities (Treasury Bills) with a maturity of 180 days or less. The remaining net proceeds may be used to pay for business, legal and accounting due diligence on prospective acquisitions and continuing general and administrative expenses.

The Company has signed a definitive agreement for the acquisition of a target business (see Note 3), and will submit such transaction for stockholder approval. In the event that stockholders owning 20% or more of the shares sold in the Offering, vote against the Business Combination and exercise the conversion rights described below, the Business Combination will not be consummated. All of the Company’s stockholders prior to the Offering, including all of the officers and directors of the Company (“Initial Stockholders”), have agreed to vote their 1,375,000 founding shares of common stock in accordance with the vote of the majority in interest of all other stockholders of the Company (“Public Stockholders”) with respect to the Business Combination. After consummation of the Business Combination, all of these voting safeguards will no longer be applicable.

With respect to a Business Combination which is approved and consummated, any Public Stockholder who voted against the Business Combination may demand that the Company convert his or her shares. The per share conversion price will equal the amount in the Trust Account as of the record date for determination of stockholders entitled to vote on the Business Combination divided by the number of shares of common stock held by Public Stockholders at the consummation of the Offering. Accordingly, Public Stockholders holding 19.99% of the aggregate number of shares owned by all Public Stockholders may seek conversion of their shares in the event of a Business Combination. Such Public Stockholders are entitled to receive their per share interest in the Trust Account computed without regard to the shares held by Initial Stockholders. In this respect, $6,881,213 and $6,685,164 (which includes accretion of Trust Account) has been classified as common stock subject to possible conversion at December 31, 2005 and 2004, respectively.

The Company’s Certificate of Incorporation provides for mandatory liquidation of the Company in the event that the Company does not consummate a Business Combination within 18 months from the date of the consummation of the Offering (such date was November 18, 2005), or 24 months from the consummation of the Offering (such date would be May 18, 2006) if certain extension criteria have been satisfied. In the event of liquidation, it is likely that the per share value of the residual assets remaining available for distribution (including Trust Fund assets) will be less than the initial public offering price per share in the Offering (assuming no value is attributed to the Warrants contained in the Units sold in the

F-53

TREMISIS ENERGY ACQUISITION CORPORATION

(A CORPORATION IN THE DEVELOPMENT STAGE)

NOTES TO FINANCIAL STATEMENTS — (Continued)

Offering discussed in Note 2). The Company has satisfied the extension criteria by entering into an Agreement and Plan of merger with RAM Energy, Inc as described in Note 3.

2. Offering On May 18, 2004, the Company sold 6,325,000 units (“Units”) in the Offering including an additional 825,000 Units pursuant to the underwriters’ over-allotment option. Each Unit consists of one share of the Company’s common stock, $.0001 par value, and two Redeemable Common Stock Purchase Warrants (“Warrants”). Each Warrant will entitle the holder to purchase from the Company one share of common stock at an exercise price of $5.00 commencing the later of the completion of a Business Combination with a target business or one year from the effective date of the Offering and expiring five years from the date of the prospectus. The Warrants will be redeemable at a price of $.01 per Warrant upon 30 days’ notice after the Warrants become exercisable, only in the event that the last sale price of the common stock is at least $8.50 per share for any 20 trading days within a 30 trading day period ending on the third day prior to the date on which notice of redemption is given. In connection with this Offering, the Company issued, for $100, an option (“UPO”) to the representative of the underwriters to purchase 275,000 Units at an exercise price of $9.90 per Unit. The Units underlying the UPO are identical to the Units sold in the Offering except that the Warrants underlying the UPO have an exercise price of $6.25 per share. The Company accounted for the fair value of the UPO, inclusive of the receipt of the $100 cash payment, as an expense of the Offering resulting in a charge directly to stockholders’ equity. The UPO may be exercised for cash or on a “cashless” basis, at the holder’s option, such that the holder may use the appreciated value of the UPO (the difference between the exercise prices of the UPO and the underlying Warrants and the market price of the Units and underlying securities) to exercise the UPO without the payment of any cash.

3. Proposed Merger On October 20, 2005, the Company entered into an Agreement and Plan of Merger (“Merger Agreement”) with RAM Energy, Inc. (“RAM Energy”) and all of its stockholders (“Stockholders”), which was amended on November 11, 2005. Pursuant to the Merger Agreement, a wholly owned subsidiary of the Company will merge (“Merger”) with and into RAM Energy. RAM Energy will be the surviving corporation in the Merger, becoming a wholly owned subsidiary of the Company. RAM Energy is a privately-owned, independent, oil and gas company headquartered in Tulsa, Oklahoma. RAM Energy’s business strategy is to acquire, explore, develop, exploit, produce and manage oil and gas properties, primarily in Texas, Louisiana and Oklahoma. RAM Energy has been active in these core areas since its inception in 1987. RAM Energy’s management team has extensive technical and operating expertise in all areas of RAM Energy’s operations and geographic focus.

Pursuant to the Merger Agreement, the Stockholders, in exchange for all of the securities of RAM Energy outstanding immediately prior to the Merger, will receive from the Company $30 million in cash and 25,600,000 shares of the Company’s common stock. A portion of the shares of the Company’s common stock being issued to the Stockholders in the Merger will be placed into escrow to secure the indemnity rights of the Company under the Merger Agreement and will be governed by the terms of an Escrow Agreement.

The financial statements have been prepared assuming the Company will continue as a going concern. In the event the Merger Agreement is not consummated before May 18, 2006, the Company will be forced to liquidate. Under such circumstances, an agreement with the Company’s Chairman/CEO would be implemented, whereby he would become personally liable for settlement of accrued expenses, taxes payable and acquisition costs incurred.

F-54

TREMISIS ENERGY ACQUISITION CORPORATION

(A CORPORATION IN THE DEVELOPMENT STAGE)

NOTES TO FINANCIAL STATEMENTS — (Continued)

In connection with this business combination, the Company incurred $540,907 of costs related to this proposed acquisition which have been deferred as of December 31, 2005.

4. Note Payable, Stockholder The Company issued a $70,000 unsecured non-interest bearing promissory note to a stockholder on February 17, 2004. The stockholder advanced additional amounts aggregating $7,500 through May 2004. The note and advances were paid in full in June 2004 from the net proceeds of the Offering.

5. Commitment The Company presently occupies office space provided by and affiliate of an initial stockholder. Such affiliate has agreed that, until the acquisition of a target business by the Company, it will make such office space, as well as certain office and secretarial services available to the Company, as may be required by the Company from time to time. The Company pays such affiliate $3,500 per month for such services commencing on May 18, 2004, the effective date of the Offering. Included in general and administrative such services are $42,000 for the year ended December 31, 2005, $28,000 for the period from February 5, 2004 (inception) to December 31, 2004 and $70,000 for the period from February 5, 2004 (inception) to December 31, 2005.

6. Preferred Stock The Company is authorized to issue 1,000,000 shares of preferred stock with such designations, voting and other rights and preferences as may be determined from time to time by the Board of Directors.

7. Common Stock The Company’s Board of Directors authorized a 1.666666 to one forward stock split of its common stock on March 10, 2004, a 1.1428571 to one forward stock split of its common stock on April 16, 2004 and a 1.375 to one forward stock split of its common stock on April 23, 2004. All references in the accompanying financial statements to the numbers of shares have been retroactively restated to reflect the transactions.

As of December 31, 2005, 13,475,000 shares of common stock were reserved for issuance upon exercise of Warrants and the UPO.

8. Provision for Taxes Provision for taxes consists of:

	Year Ended December 31, 2005		For the Period from February 5, 2004 (inception) to December 31, 2004		For the Period from February 5, 2004 (inception) to December 31, 2005
Current:
Federal	$	190,859	$	33,000	$	223,859
State and local		122,691		46,115		168,806
Deferred:		—		—		—
	$	313,550	$	79,115	$	392,665

The effective rate exceeds statutory rates primarily due to state and local taxes which are calculated as a percentage of capital.

F-55

11,796,734 Shares

RAM Energy Resources, Inc.

Common Stock

PRICE $         PER SHARE

RBC CAPITAL MARKETS

JEFFERIES & COMPANY

JOHNSON RICE & COMPANY L.L.C.

SANDERS MORRIS HARRIS

FERRIS, BAKER WATTS

INCORPORATED

GILFORD SECURITIES INCORPORATED

P R O S P E C T U S

                    , 2007

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.    Other Expenses of Issuance and Distribution.

Set forth below is an itemization of the costs expected to be incurred in connection with the offer and sale of the securities registered hereby. With the exception of the Securities Act and NASD fees, all amounts are estimates.

Securities Act Registration Fee	$	7,999
NASD Filing Fee		7,955
Printing and Engraving Expenses		200,000
Legal Fees and Expenses		300,000
Accounting Fees and Expenses		130,000
Independent Petroleum Engineer Fees		2,000
Transfer Agent Fees		5,000
Miscellaneous		97,046
Total	$	750,000

Item 14.    Indemnification of Directors and Officers.

Section 145 of the General Corporation Law of Delaware, under which the Registrant is incorporated, permits indemnification against judgments, fines and amounts paid in settlements, expenses, including attorneys’ fees, actually and reasonably incurred by such persons in connection with any action, suit or proceeding in which such a person is a party by reason of his being or having been a director, employee or agent of the Registrant, or of any corporation, partnership, joint venture, trust or other enterprise in which he served as such at the request of the Registrant, provided that he acted in good faith and in a manner he 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 his conduct was unlawful, and provided further (if the threatened, pending or completed action or suit is by or in the right of the corporation) that he shall not have been adjudged to be liable for negligence or misconduct in the performance of his duty to the corporation (unless the court determines that indemnity would nevertheless be proper under the circumstances). Article VIII of the Registrant’s Amended and Restated Certificate of Incorporation provides for indemnification of the Registrant’s directors and officers. The Delaware General Corporation Law also permits the Registrant to purchase and maintain insurance on behalf of the Registrant’s directors and officers against any liability arising out of their status as such, whether or not Registrant would have the power to indemnify them against such liability. These provisions may be sufficiently broad to indemnify such persons for liabilities arising under the Securities Act of 1933 (the “Securities Act”).

The Registrant has entered into indemnity agreements with each of its directors and executive officers. Under each indemnity agreement, the Registrant will pay on behalf of the indemnitee, and his executors, administrators and heirs, any amount which he is or becomes legally obligated to pay because of (i) any claim or claims from time to time threatened or made against him by any person because of any act or omission or neglect or breach of duty, including any actual or alleged error or misstatement or misleading statement, which he commits or suffers while acting in his capacity as a director and/or officer of the Registrant or an affiliate or (ii) being a party, or being threatened to be made a party, to any threatened, pending or contemplated action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he is or was an officer, director, employee or agent of the Registrant or an affiliate

II-1

or is or was serving at the request of the Registrant as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise. The payments which the Registrant will be obligated to make hereunder shall include, inter alia, damages, charges, judgments, fines, penalties, settlements and costs, cost of investigation and cost of defense of legal, equitable or criminal actions, claims or proceedings and appeals therefrom, and costs of attachment, supersedeas, bail, surety or other bonds. The Registrant also provides liability insurance for each of its directors and executive officers.

Item 15.    Recent Sales of Unregistered Securities.

In February 2004, the Registrant issued an aggregate of 750,000 shares of its common stock to the stockholders as set forth below at a purchase price of approximately $0.033 per share. Subsequent to the issuance, and prior to the Registrant’s IPO, the Registrant’s board of directors authorized several forward splits of our common stock, effectively lowering the purchase price to $0.018 per share. The following share numbers have been adjusted to reflect these stock splits.

Name	Number of Shares	Relationship to Us
Lawrence S. Coben	1,008,334	Former Chairman and Chief Executive Officer
Isaac Kier	183,334	Former Secretary, Treasurer and Director
David A. Preiser	91,666	Former Director
Jon Schotz	91,666	Former Director

Upon closing of the merger, the stockholders of RAM Energy were issued 25,600,000 shares of our common stock.

In conjunction with the closing of the Registrant’s IPO, the Registrant issued an option to EarlyBirdCapital, Inc. to purchase up to a total of 275,000 units, each unit consisting of one share of the Registrant’s common stock and two warrants, each to purchase one share of the Registrant’s common stock. The units issuable upon exercise of this option were identical to those issued in the Registrant’s IPO, except for the warrants included in the EarlyBirdCapital’s option have an exercise price of $6.25 per share.

On May 8, 2006, the Registrant issued 10,000 restricted shares of common stock to each of the Registrant’s three, non-management directors. At the same time, the Registrant issued 100,000 restricted shares of the Registrant’s common stock to each of the Registrant’s three senior vice presidents. In each instance, the shares were issued under the Registrant’s 2006 Long-Term Incentive Plan and became fully vested 30 days following issuance.

In each of the instances above, the shares of common stock were not registered under the Securities Act of 1933, and were issued in reliance upon the exemption from the registration requirements of the Securities Act as provided in Section 4(2) of the Securities Act.

Item 16.    Exhibits and Financial Statement Schedules.

(a) Exhibits

Exhibit	Description	Method of Filing
1.1	Form of Underwriting Agreement	**
3.1	Amended and Restated Certificate of Incorporation of the Registrant.	(1) [3.1]
3.2	Amended and Restated Bylaws of the Registrant.	(1) [3.2]
4.1	Specimen Unit Certificate.	(1) [4.1]

II-2

Exhibit	Description	Method of Filing
4.2	Specimen Common Stock Certificate.	(1) [4.2]
4.3	Amended Specimen Warrant Certificate.	**
4.4	Form of Unit Purchase Option granted to EarlyBirdCapital, Inc.	(2) [4.4]
4.5	Amended Form of Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant.	**
4.6	Indenture dated as of February 24, 1998 among RAM Energy, Inc., the Subsidiary Guarantors named therein, and United States Trust Company of New York, Trustee.	(7) [4.1]
4.6.1	Supplemental Indenture dated February 24, 1998 among RAM Energy, Inc., the Subsidiary Guarantors named therein, and United States Trust Company of New York, Trustee.	(8) [4.6.1]
4.6.2	Second Supplemental Indenture dated as of November 22, 2002 among RAM Energy, Inc., the Subsidiary Guarantors and The Bank of New York, Successor to United States Trust Company of New York, as trustee.	(8) [4.6.2]
4.6.3	Third Supplemental Indenture dated as of April 29, 2004 among RAM Energy, Inc., the Subsidiary Guarantors and The Bank of New York, Successor to United States Trust Company of New York, as trustee.	(8) [4.6.3]
4.6.4	Fourth Supplemental Indenture dated as of December 17, 2004 among RAM Energy, Inc., The Bank of New York, Successor to United States Trust Company of New York, as trustee, RWG Energy, Inc., WG Operating, Inc., WG Royalty Company, Wise County Construction Company, LLC, and WG Pipeline LLC, as Additional Subsidiary Guarantors.	(8) [4.6.4]
5.1	Opinion of McAfee & Taft A Professional Corporation	***
10.1	Form of Stock Escrow Agreement between the Registrant, Continental Stock Transfer & Trust Company and the Initial Stockholders.	(2) [10.6]
10.2	Form of Registration Rights Agreement among the Registrant and the Initial Stockholders.	(2) [10.9]
10.2.1	Amendment to Registration Rights Agreement among this Registrant and the Founders dated May 8, 2006.	(1) [10.9.1]

II-3

Exhibit	Description	Method of Filing
10.3	Agreement and Plan of Merger dated October 20, 2005 among Registrant, RAM Acquisition, Inc., RAM Energy, Inc. and the Stockholders of RAM Energy, Inc.	(3) [10.1]
10.3.1	Amendment No. 1, dated November 11, 2005, to Agreement and Plan of Merger dated October 20, 2005 among the Registrant, RAM Acquisition, Inc., RAM Energy, Inc. and the Stockholders of RAM Energy, Inc.	(4) [10.11]
10.3.2	Amendment No. 2, dated February 15, 2006, to Agreement and Plan of Merger dated October 20, 2005 among the Registrant, RAM Acquisition, Inc., RAM Energy, Inc. and the Stockholders of RAM Energy, Inc.	(6) [10.12]
10.4	Voting Agreement dated October 20, 2005 among the Registrant, the stockholders of RAM Energy, Inc. and certain security holders of the Registrant.	(3) [10.2]
10.4.1	Second Amended and Restated Voting Agreement included as Annex D of the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006 and incorporated by reference herein.	(5) [Annex D]
10.5	Lock-Up Agreement dated October 20, 2005 executed by the stockholders of RAM Energy, Inc.	(3) [10.4]
10.6	Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006.*	(1) [10.15]
10.6.1	First Amendment to Employment Agreement between Registrant and Larry E. Lee dated October 18, 2006, *	(9) [10.1]
10.7	Escrow Agreement by and among the Registrant, Larry E. Lee and Continental Stock Transfer & Trust Company dated May 8, 2006.	(1) [10.16]
10.8	Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.*	(1) [10.17]
10.9	Form of Registration Rights Agreement among the Registrant and the Investors party thereto.	(3) [10.7]
10.10	Agreement between RAM and Shell Trading-US dated February 1, 2006.	(1) [10.22]

II-4

Exhibit	Description	Method of Filing
10.11	Agreement between RAM Energy and Targa dated January 30, 1998.	(1) [10.23]
10.11.1	Amendment to Agreement between RAM Energy and Targa dated effective as of April 1, 2006, filed as an exhibit to Registrant’s Form 8-K dated June 5, 2006 and incorporated by reference herein.	(10) [10.23.1]
10.12	Long-Term Incentive Plan of the Registrant. Included as Annex C of the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006 and incorporated by reference herein.*	(5) [Annex C]
10.13	Third Amended and Restated Loan Agreement dated as of April 3, 2006, between RAM Energy, Inc., the lenders described therein, Guggenheim Corporate Funding, LLC as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent, and WESTLB AG, New York Branch, as the Syndication Agent.	(11) [10.14]
21.1	Subsidiaries of the Registrant	(12) [21.1]
23.1	Consent of UHY Mann Frankfort Stein & Lipp CPAs, LLP	**
23.2	Consent of BDO Seidman, LLP	**
23.3	Consent of Forest A. Garb & Associates, Inc.	**
23.4	Consent of Williamson Petroleum Consultants, Inc.	**
23.5	Consent of McAfee & Taft A Professional Corporation (included in Exhibit 5.1)	***
24.1	Power of Attorney	(12) [24.1]

  * Management contract or compensatory plan or arrangement.

  ** Filed herewith.

*** To be filed by amendment.

  (1) Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on May 12, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

  (2) Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-113583) as the exhibit number indicated in brackets and incorporated by reference herein.

  (3) Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on October 26, 2005, as the exhibit number indicated in brackets and incorporated by reference herein.

II-5

  (4) Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on November 14, 2005, as the exhibit number indicated in brackets and incorporated by reference herein.

  (5) Included as an annex to the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006, as the annex letter indicated in brackets and incorporated by reference herein.

  (6) Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on February 21, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

  (7) Filed as an exhibit to the Registration Statement on Form S-1 (SEC File No. 333-42641) of RAM Energy, Inc., as the exhibit number indicated in brackets and incorporated by reference herein.

  (8) Filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q filed on August 14, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

  (9) Filed as an exhibit to the Registrant’s Current Report on Form 8-K on October 20, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(10) Filed as an exhibit to the Registrant’s Current Report on Form 8-K on June 5, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(11) Filed as an exhibit to Registrant’s amended Quarterly Report on Form 10-Q/A filed on December 20, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(12) Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-138922) as the exhibit number indicated in brackets and incorporated by reference herein.

Item 17.    Undertakings.

The undersigned Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of the registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act of 1933 shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described under Item 14, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 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 the 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, the 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 Act and will be governed by the final adjudication of such issue.

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 Tulsa, State of Oklahoma, on January 3, 2007.

RAM ENERGY RESOURCES, INC.
By	/s/ Larry E. Lee
	Larry E. Lee, Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated.

Signature	Title	Date
/s/ Larry E. Lee Larry E. Lee	Chairman of the Board, President and Chief Executive Officer and Director (Principal Executive Officer)	January 3, 2007
/s/ John M. Longmire John M. Longmire	Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	January 3, 2007
/s/ Larry E. Lee* Sean P. Lane	Director	January 3, 2007
/s/ Larry E. Lee* Gerald R. Marshall	Director	January 3, 2007
/s/ Larry E. Lee* John M. Reardon	Director	January 3, 2007

* Executed by Larry E. Lee as power of attorney.