10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

OR

¨    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                  to                 

Commission File Number: 000-50682

RAM Energy Resources, Inc.

(Exact name of registrant as specified in its charter)

Delaware	20-0700684
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

5100 East Skelly Drive, Suite 650 Tulsa, Oklahoma	74135
(Address of principal executive office)	(Zip Code)

(918) 663-2800

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $.0001 par value

Warrants to Purchase

Common Stock

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.    

Yes  ¨    No  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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

Large Accelerated Filer  ¨	Accelerated Filer  þ
Non-Accelerated Filer  ¨	Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes  ¨    No  þ

As of March 14, 2008, there were outstanding 60,800,105 shares of registrant’s $.0001 par value common stock; and 18,848,800 warrants, each warrant evidencing the right to purchase one share of common stock at an exercise price of $5.00 per share. Based upon the closing price for the registrant’s common stock on the NASDAQ Capital Market as of March 14, 2008, the aggregate market value of 23,597,102 shares of common stock held by non-affiliates of the registrant was approximately $114,681,916 million.

Documents incorporated by reference: The information called for by Part III is incorporated by reference to the definitive proxy statement for the Registrant’s 2008 annual meeting of stockholders, which will be filed with the Securities and Exchange Commission, or SEC, no later than 120 days after December 31, 2007.

RAM ENERGY RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2007

TABLE OF CONTENTS

Item Number		Page
	PART I
1	Business	1
1A	Risk Factors	8
1B	Unresolved Staff Comments	14
2	Business and Properties	14
3	Legal Proceedings	29
4	Submission of Matters to a Vote of Security Holders	29
	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
6	Selected Consolidated Financial Data	33
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
7A	Quantitative and Qualitative Disclosures About Market Risk	46
8	Financial Statements	47
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	73
9A	Controls and Procedures	73
9B	Other Information	79
	PART III
10	Directors, Executive Officers and Corporate Governance	80
11	Executive Compensation	80
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	80
13	Certain Relationships and Related Transactions and Director Independence	80
14	Principal Accountants Fees and Services	80
	PART IV
15	Exhibits and Financial Statement Schedules	81

PART I

Item 1. Business

Overview

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 report 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 report to “RAM Energy” refer to RAM Energy, Inc., and to “Ascent” or “Ascent Energy” refer to Ascent Energy Inc., each of which is our wholly owned subsidiary, and their respective subsidiaries. Unless the context otherwise requires, the information contained in this report 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 “RAM Energy acquisition,” and to our November 29, 2007 acquisition of Ascent Energy, which we refer to as the “Ascent acquisition.” See “Business—Recent Events” for a discussion of the merger. As used in this report, 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.

We were incorporated in Delaware on February 5, 2004. Our operations are encompassed in our wholly owned primary subsidiaries, RAM Energy and Ascent Energy and their respective subsidiaries. Our executive offices are located at 5100 East Skelly Drive, Suite 650, Tulsa, Oklahoma 74135 (918) 663-2800. We also have offices in Plano and Houston, Texas.

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, Oklahoma and West Virginia. Our producing properties are located in highly prolific basins with long histories of oil and natural gas operations. We have been active in our core producing areas of Texas, Oklahoma and Louisiana since our inception in 1987 and have grown through a balanced strategy of acquisitions, development and exploratory drilling. We have completed over 22 acquisitions of producing oil and natural gas properties and related assets for an aggregate purchase price in excess of $725 million. Through December 31, 2007, we have drilled or participated in the drilling of 642 oil and natural gas wells, 92% 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.

On November 29, 2007, we completed the acquisition of Ascent Energy Inc., a company engaged in the exploration and development of oil and natural gas properties, and the production of oil and natural gas, primarily in Oklahoma, Texas, Louisiana and West Virginia. The total consideration paid by us in connection with our acquisition of Ascent included 18,783,344 shares of our common stock and warrants to purchase 6,200,000 shares of our common stock at an exercise price of $5.00 per share, exercisable at any time on or prior to May 11, 2008, and $203 million in cash, of which $20.0 million was placed in escrow as a source of funds to adjust for Ascent’s closing date working capital and to indemnify us against, among other things, breaches of covenants, representations and warranties by Ascent. The total consideration included amounts paid to certain holders of Ascent’s outstanding indebtedness, amounts necessary to settle and close all of Ascent’s outstanding oil and natural gas hedging contracts, and payments to holders of all of Ascent’s outstanding preferred stock and common stock.

At November 29, 2007, most of Ascent’s production was from approximately 31,515 gross acres (18,938 net acres) of developed conventional oil and natural gas properties in Texas, Oklahoma and Louisiana, and its

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unconventional shale gas acreage consisted of approximate 84,207 gross acres (70,481 net acres) located in the Barnett shale in north Texas, the Woodford shale and the Caney shale in Oklahoma and the Devonian shale in West Virginia.

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:

• Electra/Burkburnett—Wichita and Wilbarger Counties, Texas;

• Pontotoc County, Oklahoma;

• South Texas—Starr, Wharton and Duval Counties, Texas; and

• Boonsville—Jack and Wise Counties, Texas.

Our unconventional reserves and prospects are primarily shale plays in the following areas:

• North Texas Barnett Shale—Jack and Wise Counties, Texas. This is our Tier 1 Barnett shale acreage where we own interests in approximately 27,700 gross (6,800 net) acres;

• Appalachian Devonian Shale—Cabell and Mason Counties, West Virginia. We own leasehold interests in approximately 46,835 gross (44,987 net) acres;

• North Texas Barnett Shale (Tier 2)—Bosque and Hamilton Counties, Texas. We own interests in approximately 26,267 gross (20,802 net) acres in this emerging Tier 2 region of the North Texas Barnett shale play; and

• Oklahoma Woodford and Caney Shales—Southeast Oklahoma. We own leasehold interests in approximately 7,257 gross (1,842 net) acres in the Woodford shale and approximately 3,848 gross (2,850 net) acres in the Caney shale in various locations in Pittsburg, Hughes and McIntosh Counties, Oklahoma.

At December 31, 2007, our estimated net proved reserves were 39.4 MMBoe, of which approximately 50% were crude oil, 39% were natural gas, and 11% were natural gas liquids, or NGLs. The PV-10 Value of our proved reserves was approximately $911.5 million based on prices we were receiving as of December 31, 2007, which were $93.90 per Bbl of oil, $54.69 per Bbl of NGLs and $7.00 per Mcf of natural gas. At December 31, 2007, our proved developed reserves comprised 63% of our total proved reserves.

At December 31, 2007, we owned interests in approximately 3,900 wells and were the operator of leases upon which approximately 2,900 of these wells are located. The PV-10 Value attributable to our interests in the properties we operate represented approximately 92% of our aggregate PV-10 Value as of December 31, 2007. 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, 2007, our reserve replacement percentage, through discoveries, extensions, revisions and acquisitions, but excluding divestitures, was 602%. Since January 1, 1997, our historical average finding cost from all sources, exclusive of divestitures, has been $6.09 per Boe. During the twelve months ended December 31, 2007, we drilled or participated in the drilling of 81 wells on our oil and natural gas properties, 63 of which were successfully completed as producing wells, seven of which were dry holes and 11 of which were either drilling or waiting to be completed at the end of that period. For the twelve months ended December 31, 2007, we generated EBITDA of $42.4 million from production averaging 3,895 Boe per day. For more information regarding our EBITDA, including a reconciliation to our net income (loss), see Item 6. “Selected Consolidated Financial Data.”

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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 in Texas, Oklahoma and Louisiana. 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 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, 2007, we have identified 278 development and extension drilling projects and 307 recompletion/workover projects on our existing properties and wells.

Ÿ Accelerate our Appalachian Basin Shale Development. We own 46,835 gross (44,987 net) acres in West Virginia as a result of the Ascent acquisition. Due to the high degree of commercial success in the Appalachian Basin by the oil and gas industry, we intend to significantly accelerate drilling on our West Virginia acreage. We (including Ascent prior to its acquisition) have drilled eight gross (eight net) wells to date on these properties. Sales of natural gas from six of these wells commenced in the first quarter of 2008 at an initial rate of 300 Mcf per day. We plan on drilling 14 gross (14 net) wells on our West Virginia properties during 2008.

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 expect to significantly accelerate drilling in our Tier 1 north Texas Barnett Shale properties. We have drilled 12 gross (5.0 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 2008.

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 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 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.

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We believe that the following strengths complement our business strategy:

Ÿ Inventory of Growth Opportunities in the Undeveloped Conventional Acreage and Undeveloped Unconventional North Texas Barnett and Appalachian Shale Acreage. We believe we have a significant inventory of growth opportunities beyond our proved reserve base in our 26,570 gross (25,546 net) undeveloped conventional acreage positions and our 98,123 gross (71,658 net) undeveloped unconventional North Texas Barnett and Appalachian Devonian Shale acreage. 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 property acquisitions.

Ÿ Management Experience and Technical Expertise. Our key management and technical staff possess an average of 27 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 2007, approximately 50% of our estimated proved reserves were oil, 39% were natural gas and 11% 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 92% of our aggregate PV-10 Value at December 31, 2007. 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, 2007, we drilled or have participated in the drilling of 642 oil and natural gas wells with a 92% 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 competitive advantage with respect to availability, lead-time and cost of these services.

Ÿ Insider Ownership. At March 14, 2008 our directors, executive officers and our three principal stockholders beneficially owned approximately 61% of our outstanding shares of common stock, providing a strong alignment of interest between management, the board of directors and our outside stockholders.

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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.

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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 report and costs in effect as of the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt 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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SAFE HARBOR STATEMENT

This report, including information included in, or incorporated by reference from future filings by us with the SEC, as well as information contained in written material, press releases and oral statements issued by us or on our behalf, contain, or may contain, certain statements that are “forward-looking statements” within the meaning of federal securities laws that are subject to a number of risks and uncertainties, many of which are beyond our control. This report modifies and supersedes documents filed by us before this report. In addition, certain information that we file with the SEC in the future will automatically update and supersede information contain in this report. All statements, other than statements of historical fact, included or incorporated by reference in this report, 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 report, 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:

• business strategy;

• reserves;

• technology;

• financial strategy;

• oil and natural gas realized prices;

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

• the amount, nature and timing of capital expenditures;

• drilling of wells;

• competition and government regulations;

• marketing of oil and natural gas;

• property acquisitions;

• costs of developing our properties and conducting other operations;

• general economic conditions;

• uncertainty regarding our future operating results; and

• plans, objectives, expectations and intentions contained in this report that are not historical.

All forward-looking statements speak only as of the date of this report, and, except as required by law, 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 report. 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 report 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 report. 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 report 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.

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Item 1A. Risk Factors

We face a variety of risks that are inherent in our business and our industry, including operational, legal and regulatory risks. The following are some of the more significant factors that could affect our business and our results of operations. We caution the reader that the list of factors may not be exhaustive. Other factors may exist that we cannot anticipate or that we do not consider to be significant based on information that is currently available.

Risks Related to Our Business

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:

• worldwide and domestic supplies of oil and natural gas;

• weather conditions;

• the level of consumer demand;

• the price and availability of alternative fuels;

• the availability of drilling rigs and completion equipment;

• the availability of pipeline capacity;

• the price and volume of foreign imports;

• domestic and foreign governmental regulations and taxes;

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

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

• 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 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

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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 a combination of cash flows from operations and borrowings. If such borrowed 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 a combination of cash flows from operations and borrowed funds. To the extent such borrowed 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.

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

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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 “Item 3. Business—Legal Proceedings” appearing elsewhere in this report.

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.

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.

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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. 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:

• future oil and natural gas prices;

• the amount of recoverable reserves;

• future operating costs;

• future development costs;

• failure of titles to properties;

• costs and timing of plugging and abandoning wells; and

• 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.

Risk Related to Our Common Stock

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

Prior to consummation of our RAM Energy acquisition, 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, and we issued 18,783,344 shares of our common stock and warrants to purchase an additional 6,200,000 shares of our common stock in conjunction with the Ascent acquisition. These shares were not registered under the Securities Act of 1933, and their resale was restricted. All of the shares issued in the RAM Energy acquisition are now eligible to be sold

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under Rule 144 promulgated under the Securities Act of 1933. In addition, the holders of such shares have certain registration rights and will be able to sell their shares in the public market without restriction prior to such times if registration is effected. The shares of our common stock and warrants issued in the Ascent acquisition have been registered for resale pursuant to a registration statement effective March 13, 2008. 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.

On May 8, 2006, we approved the grant of restricted stock awards under our 2006 Long-Term Incentive Plan for an aggregate of 330,000 shares of our common stock to three of our senior vice presidents and three directors. The grants vested on June 8, 2006. We incurred $2.2 million compensation expense in 2006 with respect to these awards.

On November 10, 2006, we approved the grant of restricted stock awards for an aggregate of 646,805 shares of our common stock to 22 of our employees, including two of our vice presidents. We will incur compensation expense of approximately $3.2 million, which will be recognized ratably through 2011, in connection with our November 10, 2006 restricted stock issuances. For the years ended December 31, 2006 and 2007, we recognized share-based compensation expense of $91,000 and $633,000, respectively with respect to these grants.

During calendar year 2007, we approved the grant of 300,262 shares of our common stock in the form of restricted stock awards under our 2006 Long-Term Incentive Plan, of which 220,000 shares were awarded to three of our executive officers, 42,262 shares were awarded to certain other employees, 30,000 were awarded to our directors and 8,000 were awarded to a consultant engaged by our board of directors. The awards are subject to vesting periods of varying duration, from eight months to five years. We will incur compensation expense of approximately $1.3 million in connection with these awards, which will be recognized ratably over the vesting periods. For 2007, we recognized share-based compensation expense of $356,000 with respect to these awards.

Effective January 1, 2008, we approved the grant of 841,000 shares of our common stock in the form of restricted stock awards to our officers and other key employees, including certain former Ascent employees who continued in their former positions following the acquisition. All of the awards provide for vesting ratably over a four-year period. We will incur compensation expense of approximately $4.2 million in connection with these awards, which will be recognized ratably through 2011.

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 42% 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. In addition, persons who beneficially own approximately 31% of our outstanding common stock are subject to a voting agreement pursuant to which such holders agree to vote for the slate of directors proposed by our board of directors through 2009. Accordingly, the parties to these agreements will be able to control the election of directors and, therefore, our policies and direction during the term of the voting agreements. 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. We are currently authorized to issue one hundred million shares of common stock and one million shares of preferred stock with such designations, preferences and rights as

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determined by our board of directors. As of the date of this report, we had outstanding 60,812,945 shares of common stock, warrants to purchase 18,848,800 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 281,933 shares for future issuance to our directors, officers and 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 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:

• 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.

• 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 entitled to vote.

• 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.

• 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.

• 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.

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• 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 shares of 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.

Item 1B. Unresolved Staff Comments

None.

BUSINESS AND PROPERTIES

Item 2. Properties

The following is a description of each of our principal properties as of December 31, 2007, together with a general description of our miscellaneous and non-core properties.

Electra/Burkburnett Area. Our properties in the Electra/Burkburnett Area of north Texas include 26 leases covering 12,190 gross acres. As of December 31, 2007, we owned interests in approximately 1,658 wells in the Electra/Burkburnett Area, of which 573 were active producing wells and 227 were active injection wells.

We drilled more than 216 wells in the Electra/Burkburnett Area from November 1, 2004 through December 31, 2007, and, as of December 31, 2007, 150 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 year ended December 31, 2007, we drilled 65 wells in the Electra/Burkburnett Area, of which 53 were completed as producing wells, four were dry holes and eight were in various stages of completion at the end of the year. We own a 100% working interest in and operate all 65 of the wells. The initial net daily production from wells drilled and completed during the year ended December 31, 2007 averaged 21 Bbls of oil. The average cost incurred by us to drill, complete and equip a producing well in our Electra/Burkburnett Area during the year ended December 31, 2007 was $136,000. In 2008 we expect to drill 60 additional wells in this area.

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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 650 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 140 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, approximately the same volume is used to power recently installed field electric generators, and the remainder is flared due to a lack of pipeline facilities in the area.

We own and operate 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 five 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 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 (STUSCO). From January 1, 2007 through June 30, 2007, the price we received was the STUSCO WTI posted price plus a premium of $1.30 per Bbl. From July 1, 2007 to December 31, 2007, we received a price equal to the Valero North Texas Sweet posted price plus a premium of $1.50 per Bbl. Effective January 1, 2008 our price increased to the STUSCO North Texas Sweet posted price plus $3.25 per Bbl.

During the year ended December 31, 2007, the aggregate net production attributable to our interest in the Electra/Burkburnett properties was 575,882 Bbls of oil and 51,367 Bbls of NGLs, or 627,249 Boe, and the average daily production for the period was 1,578 Bbls of oil and 141 Bbls of NGLs, or 1,718 Boe per day.

Pontotoc County, Oklahoma. We acquired our Pontotoc County, Oklahoma properties as part of our acquisition of Ascent Energy. These properties include:

Northeast Fitts Unit. The Northeast Fitts Unit is located in southern Pontotoc County. This field produces oil primarily from two reservoirs, the McAlester Lower Pennsylvanian Sandstone at approximately 1,300 feet in depth and the Hunton Devonian Limestone at approximately 3,900 feet in depth. In 2002, Ascent initiated a waterflood recompletion on the deeper Hunton interval and began an infill drilling program to ten acre spacing in 2003. Currently, our production in the Hunton interval comes from primary depletion drive oil and natural gas reserves as a result of Ascent’s drilling program, which commenced in late 2002. We are the operator of this unit with a working interest of approximately 91%. We own interests in approximately 1,010 gross (909 net) leasehold acres and 90 producing wells in the Northeast Fitts Unit. During 2007, the aggregate net production attributable to our interest in the Northeast Fitts Unit properties was 198,510 Bbls of oil, 130 MMcf of natural gas, and 9,422 Bbls of NGLs, or 229,572 Boe, and average daily production for the period was 544 Bbls of oil, 356 Mcf of natural gas and 26 Bbl of NGLs, or 629 Boe per day. In 2008, we expect to drill nine new wells in this Unit and convert several well bores to injection wells to enhance the potential recovery rates.

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Allen Field. The Allen field is located in Pontotoc and Seminole Counties. We also hold leasehold interests in the Byng field, the Roper Beebee field and other minor fields in Pontotoc County, which are all part of the Allen Anticline trend. We operate the wells in which we have an interest within the Allen field with working interests ranging from 50% to 100%. We currently use our Pontotoc Gas Gathering System, operated by our wholly owned subsidiary, Pontotoc Gathering, L.L.C., to transport substantially all of our natural gas produced from this field. We own interests in approximately 21,877 gross (10,142 net) leasehold acres and 247 producing wells in the Allen Anticline trend. During 2007, the aggregate net production attributable to our interest in the Allen Anticline properties was 175,227 Bbls of oil and 141 MMcf of natural gas, or 198,699 Boe, and average daily production for the period was 480 Bbls of oil and 386 Mcf of natural gas, or 544 Boe per day. In 2008, we expect to drill three new wells and conduct recompletion operations on an additional four wells on our Allen Field properties.

South Texas. We acquired our South Texas properties as part of our acquisition of Ascent Energy. These properties, which are located in Starr, Wharton and Duval Counties, Texas, include leasehold interests in approximately 3,902 gross (3,010 net) acres in the Vicksburg trend and approximately 3,254 gross (3,072 net) acres in the Wilcox trend, including other producing acreage in the region. We are the operator of this acreage with working interests ranging from 50% to 100%. As of December 31, 2007, we operated 43 producing wells in this region.

• Vicksburg Trend. The La Copita field is located in the Vicksburg trend in east-central Starr County. We are the operator of this field with working interests ranging from 53% to 100%. We have 3-D seismic data over a significant portion of this field. In 2008, we expect to drill four new wells and conduct recompletion operations on an additional well.

• Wilcox Trend. The Rosita field is located in Duval County and the New Taiton field is located in Wharton County in the Wilcox trend. We are the operator of these fields with working interests ranging from 50% to 100%. We have 3-D seismic data over a significant portion of these fields. In 2008, we expect to drill three new wells in the New Taiton field.

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.

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 89 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.

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During the year ended December 31, 2007, the aggregate net production attributable to our working interests in the Boonsville shallow gas properties (above the Marble Falls) was 13,392 Bbls of oil, 369 MMcf of natural gas and 74,813 Bbls of NGLs, or 149,269 Boe, and average daily production for the period was 37 Bbls of oil, 1,010 Mcf of natural gas and 205 Bbls of NGLs, or 410 Boe per day.

In 2008, we expect to drill two wells and conduct recompletion operations on 10 existing wells on our Boonsville properties. Currently, there are 20 drilling locations identified as proved undeveloped locations. 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.

Shale Acreage. We own leasehold interests and interests in wells in the following unconventional shale plays:

Barnett Shale – Jack and Wise Counties Texas. We own leases covering approximately 27,700 gross (6,800 net) acres of Tier 1 Barnett Shale rights in Jack and Wise Counties 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. The core area of the play is in Denton, Wise and Tarrant Counties, lying just to the east-southeast of our acreage. 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 $2.9 million.

We are a party to two separate agreements covering our Tier 1 Barnett Shale acreage position:

• 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 revert to us. Through December 31, 2007, six horizontal wells have been drilled under the agreement and completed as commercially productive in the Barnett Shale. Devon recently completed two additional wells that are waiting on pipeline connections and is in the process of completing a third additional well. Devon currently is drilling a fourth well and has proposed four additional new wells on our jointly owned acreage, and we expect to participate in all four proposed wells.

• 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 December 31, 2007, EOG has drilled two wells on our Barnett Shale acreage, both of which were completed as commercially productive wells. EOG recently completed a third well and began selling production in March 2008. We expect to commence the drilling of, and operate, a well on this acreage in the second quarter of 2008.

During the year ended December 31, 2007, the aggregate net production attributable to our interest in our currently producing Tier 1 Barnett Shale wells was 5,224 Bbls of oil, 451 MMcf of natural gas, and 33,794 Bbls of NGLs, or 114,249 Boe. The average daily production for the period was 14 Bbls of oil and 1,237 Mcf of natural gas, and 93 Bbls of NGLs, or 313 Boe per day.

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We currently have 11 proved undeveloped drilling locations on this acreage that have been established by prior drilling. In addition, our ongoing review of seismic data supports 71 additional drilling locations in the EOG block and 12 additional drilling locations in the Devon block as of year end 2007.

We continue to acquire and interpret seismic data covering this portion of our Barnett Shale acreage. Currently, we own 45 square miles of 3-D seismic data and expect to acquire an additional 20 square miles of 3-D seismic data during 2008. We own an interest in 12 (gross) Barnett Shale producing wells, two of which are operated by us, seven of which are operated by Devon Energy and three of which are operated by EOG.

Barnett Shale-Bosque and Hamilton Counties, Texas. As part of our Ascent acquisition, we acquired leasehold interests in approximately 26,267 gross (20,802 net) acres in Bosque and Hamilton Counties, Texas, which is in the Tier 2 Barnett Shale development area. We also acquired approximately 40 square miles of 3-D seismic covering this leasehold acreage. At November 29, 2007, Ascent had drilled, but had not completed, two horizontal wells on this acreage. We plan to conduct completion operations on these wells in 2008 in an effort to establish commercial production.

Appalachian Devonian Shale-Mason and Cabell Counties, West Virginia. As part of our Ascent acquisition, we acquired leasehold interests and wells in approximately 46,835 gross (44,987 net) acres in Mason and Cabell Counties, West Virginia. The Devonian Shale formation in this area has an average thickness of over 1,000 feet at depths ranging form 3,400 to 4,500 feet. The Devonian Shale formation has been subject to industry activity in Ohio, Kentucky and Pennsylvania, as well as in West Virginia. Ascent drilled and completed eight wells on its Appalachian leasehold, five of which were vertical wells, one of which was a slant hole and two were short length horizontal wells. We recently initiated sales of natural gas from six of these wells at an average daily rate of approximately 300 Mcf per day. We expect to drill 14 horizontal wells in this area in 2008. Our estimated per well costs are expected to range from $1.1 million to $1.3 million plus an additional $100,000 for gathering and transportation facilities.

Woodford and Caney Shales—Southeast Oklahoma. Also as part of our Ascent acquisition, we acquired leasehold interests covering approximately 7,257 gross (1,842 net) acres in the Woodford shale and approximately 3,848 gross (2,850 net) acres in the Caney shale in various locations in Pittsburg, Hughes and McIntosh Counties, Oklahoma. We have not allocated funds for the development of this acreage in our 2008 budget but are continuing to evaluate our leases on a case by case basis as other wells targeting these shales are drilled in the area.

Other Properties

In addition to our 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 and development 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 599 producing wells across the state, from the Panhandle down through the Permian Basin to South Texas, and eastward to Louisiana.

We are continuing to produce and evaluate our two 100%-owned vertical wells in our southwest Texas Wolfcamp project. These wells currently are producing at a combined rate of approximately 100 Mcf per day. We have preliminary plans to drill a horizontal well on this leasehold in 2008.

We also participated in six gross (0.7 net) exploratory wells in the Arkoma Basin during 2007, all but one of which were successfully completed.

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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 and extension wells. We are the operator of leases covering approximately 2,900 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 on these properties. We also own interests in, and operate, 591 injection wells. During the year ended December 31, 2007, we drilled or participated in the drilling of 67 gross (65.7 net) development wells on our oil and gas properties, 63 of 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 $11.1 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 307 projects involving re-completions of existing wells, all of which involve reserves included in our proved reserves at December 31, 2007. During the year ended December 31, 2007, we conducted or participated in recompletion/workover operations on five of our existing wells, resulting in the reestablishment or enhancement of production from all five of these wells. Our capital expenditures in connection with these recompletion operations aggregated approximately $130,000.

Exploration Program. An important 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. 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 200,000 gross (75,000 net) undeveloped leasehold acres (including options), which enhances our competitive exploration position and provides the foundation for future reserve additions.

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 oil and natural 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 year ended December 31, 2007, we drilled or participated in the drilling of 14 gross (2.7 net) exploratory wells at a cost of approximately $3.9 million and incurred total capital expenditures of approximately $7.7 million for all exploration activities. At December 31, 2007, one gross (0.2 net) exploratory well was awaiting completion and three gross (0.5 net) wells were dry holes.

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Oil and Natural Gas Reserves

At December 31, 2007, our estimated net proved reserves were 39.4 million Boe, of which 50% were crude oil, 39% were natural gas, and 11% were NGLs, with a PV-10 Value of approximately $911.5 million before income taxes. Our estimated proved developed reserves comprised 63% of our total proved reserves, and our reserve life for total proved reserves was approximately 14 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, 2007 was prepared by the independent petroleum engineering firms of Williamson Petroleum Consultants, Inc. and Forrest A. Garb & Associates.

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,
	2005		2006		2007
Reserve Data:
Proved developed reserves:
Oil (MBbls)		7,337		6,954		13,552
Natural gas (MMcf)		26,752		26,888		50,990
Natural gas liquids (MBbls)		1,396		1,671		2,565
Total (MBoe)		13,192		13,106		24,615
PV-10 Value (in thousands)	$	245,107	$	192,045	$	593,300

	As of December 31,
	2005		2006		2007
Proved reserves:
Oil (MBbls)		11,199		10,796		19,544
Natural gas (MMcf)		34,234		33,199		93,358
Natural gas liquids (MBbls)		1,891		2,123		4,271
Total (MBoe)		18,796		18,452		39,375
PV-10 Value (in thousands)	$	345,501	$	269,892	$	911,549
Prices used in calculating PV-10 Value:
$/Bbl (Oil)		58.63		58.74	$	93.90
$/Mcf		9.14		5.51	$	7.00
$/Bbl (NGL)		35.89		36.51	$	54.69

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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 spot 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, 2005, 2006 and 2007, please review note P in the notes to our year-end 2007 financial statements appearing elsewhere in this report.

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,
	2005			2006			2007
	(in thousands)
Future cash inflows	$	1,037,337		$	894,626		$	2,722,099
Future production costs		(336,008	)		(356,961	)		(824,576	)
Future development costs		(45,271	)		(48,605	)		(146,734	)
Future income tax expenses		(219,640	)		(158,602	)		(574,169	)
Future net cash flows		436,418			330,458			1,176,620
10% annual discount for estimated timing of cash flows		(209,758	)		(150,717	)		(578,225	)
Standardized measure of discounted future net cash flows	$	226,660		$	179,741		$	598,395

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,
	2005			2006			2007 (1)
Production volumes:
Oil (MBbls)		787			752			774
Natural gas liquids (MBbls)		170			143			184
Natural gas (MMcf)		2,681			2,365			2,785
Total (MBoe)		1,405			1,290			1,422
Average realized prices (before effects of derivative contracts):
Oil (per Bbl)	$	53.75		$	63.82		$	71.11
Natural gas liquids (per Bbl)		36.33			40.33			49.16
Natural gas (per Mcf)		6.61			6.02			6.40
Total per Boe		47.16			52.74			57.60
Effect of settlement of derivative contracts:
Oil (per Bbl)	$	(1.40	)	$	(5.78	)	$	(4.35	)
Natural gas liquids (per Bbl)		—			—			—
Natural gas (per Mcf)		(1.04	)		(.13	)		0.25
Total per Boe		(2.78	)		(3.61	)		(1.88	)
Average realized prices (after effects of derivative contracts):
Oil (per Bbl)	$	52.35		$	58.04		$	66.77
Natural gas liquids (per Bbl)		36.33			40.33			49.16
Natural gas (Per Mcf)		5.57			5.89			6.65
Total per Boe		44.38			49.13			55.72
Expenses (per Boe):
Oil and natural gas production taxes	$	2.36		$	2.58		$	3.43
Oil and natural gas production expenses		11.46			14.16			15.18
Amortization of full cost pool		8.93			9.77			12.86
General and administrative		6.13			7.21			8.36

(1) Includes data with respect to Ascent Energy from November 29, 2007 through December 31, 2007.

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 (in thousands):

	Year ended December 31,
	2005		2006		2007
Proved property acquisition costs	$	155	$	4,476	$	299,573
Unproved property acquisition costs		—		705		24,642
Development costs		11,864		18,475		12,921
Exploration costs		1,507		4,489		7,659
Total costs incurred	$	13,526	$	28,145	$	344,795

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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 property acquisitions, development costs, and exploration costs with respect to exploratory wells drilled and completed.

	Year ended December 31,
	2005	2006	2007 (1)
Proved reserves acquired/discovered (MBoe)	1,323	946	22,364
Total cost per Boe of reserves acquired/discovered	$10.23	$27.18	$15.42

(1) Includes data with respect to Ascent properties from November 29, 2007 to December 31, 2007.

Producing Wells

The following table sets forth the number of productive wells in which we owned an interest as of December 31, 2007. 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	2,520	1,956
Natural gas	605	313
Total	3,125	2,269

Acreage

The following table sets forth our developed and undeveloped gross and net leasehold acreage, including options to acquire leasehold acreage, as of December 31, 2007:

	Gross	Net
Developed	143,981	65,161
Undeveloped	260,730	119,508
Total	404,711	184,669

Approximately 73% of our net acreage was located in our core areas as of December 31, 2007. 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.

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Drilling Activities

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

	Year Ended December 31,
	2005		2006 (1)		2007 (2)
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive	66	58.1	77	75.7	52	52.0
Non-productive	—	—	2	0.5	5	5.0
Exploratory wells:
Productive	1	0.3	3	0.7	11	2.0
Non-productive	—	—	2	1.5	2	.4
Total	67	58.4	84	78.4	70	59.4

(1) Does not include three gross (2.1 net) wells that were in the process of being completed at December 31, 2006. One gross (0.1 net) well was subsequently completed as a commercially productive well.

(2) Does not include 11 gross (9.0 net) wells that were in the process of being completed at December 31, 2007.

Ascent Acquisition

On November 29, 2007, we completed the Ascent acquisition. The total consideration paid by us in connection with our acquisition of Ascent included 18,783,344 shares of our common stock and warrants to purchase 6,200,000 shares of our common stock at an exercise price of $5.00 per share, exercisable at any time on or prior to May 11, 2008, and $203 million in cash (including $1.0 million of direct acquisition costs), of which $20.0 million was placed in escrow as a source of funds to adjust for Ascent’s closing date working capital and to indemnify us against, among other things, breaches of covenants, representations and warranties by Ascent. The total consideration included amounts paid to certain holders of Ascent’s outstanding indebtedness, amounts necessary to settle and close all of Ascent’s outstanding oil and natural gas hedging contracts, and payments to holders of all of Ascent’s outstanding preferred stock and common stock.

Ascent was an independent oil and natural gas company engaged in the acquisition, exploration and development of both conventional and unconventional oil and natural gas properties in Texas, Oklahoma, Louisiana and the Appalachian region.

As of November 29, 2007, most of Ascent’s current production was from approximately 31,515 gross acres (18,938 net acres) of developed conventional oil and natural gas properties in Texas, Oklahoma and Louisiana.

Based on reserve reports prepared by our independent reserve engineering firms, Ascent’s total proved reserves as of December 31, 2007 were approximately 18.9 MMBoe, of which 42% were proved developed producing, 8% were proved developed non-producing and 50% were proved undeveloped. As of December 31, 2007, 49% of Ascent’s total proved reserves were oil and NGLs. As of December 31, 2007, Ascent had interests in approximately 106,886 net acres, including approximately 87,280 net undeveloped acres.

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Oil and Natural Gas Marketing and Derivative Activities

During the year ended December 31, 2007, two purchasers accounted for approximately 62% of our oil and natural gas revenue. Shell Trading-US accounted for $40.9 million, or 54%, and Targa Midstream Services, or Targa (formerly, Dynegy) accounted for $5.8 million, or 8%, 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 2007. Our agreement with Shell Trading-US, or STUSCO, which covers all of our north Texas oil production through June 30, 2007 provided for payment, on a per barrel basis, of a price equal to STUSCO’s posted price for West Texas Intermediate Crude, plus Platt’s Trade-month P+ (a fluctuating premium based on refinery demand), plus $1.30. From July 1, through December 31, 2007 the price we have received, on a per barrel basis, was the Valero posted price for North Texas Sweet plus a premium of $1.50. Effective January 1, 2008, our price increased to the STUSCO North Texas Sweet crude posted price plus $3.25 per Bbl. 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. We take redelivery at the tailgate of the plant of 85% of the residue gas attributable to our production and sell the residue gas on the spot market. Targa pays us 85% of the weighted average price received by Targa for the sale of natural gas liquids attributable to the gas delivered by us. There are other purchasers in the fields and such other purchasers would be available to purchase our production should either of our current 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 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, call options that establish a secondary floor above a 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 base floor prices or swap prices under our derivative contracts. However, we will not benefit from market prices that are higher than the ceiling or swap prices in these contracts for our hedged production.

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Our derivative positions at December 31, 2007 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
2008	1,500	$	65.33	1,500	$	83.39	4,000	$	6.77	4,000	$	13.23
2009	1,248	$	58.42	1,248	$	79.03	4,000	$	7.00	4,000	$	10.98
2010	500	$	60.00	500	$	80.00	—		—	—		—
	Secondary Floors
	Per Day	Price
Year
2009	800	$	75.00
	Bare Floors
	Per Day	Price
Year
2008	1,800	$	71.15
2009	1,000	$	65.00

Crude oil floors and ceilings and natural gas floors and ceilings for 2008 cover the calendar year. Crude oil bare floors for 2008 cover the calendar year. Crude oil floors and ceilings for 2009 cover the calendar year, and natural gas floors and ceilings for 2009 cover January through September. Crude oil secondary floors for 2009 cover January through March. Crude oil bare floors for 2009 cover January through June. Crude oil floors and ceilings for 2010 cover January through March.

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 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.

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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 January 2014, at an annual rental of $288,728, subject to escalations for taxes and utilities. As a result of the Ascent Acquisition, we acquired an executive and operating office at 4965 Preston Park Blvd., Suite 800, in Plano, Texas, subject to a lease extending through 2013. Currently, rent under the lease is approximately $578,000 annually. We also lease a small office in Houston, Texas. 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.

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.

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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.

Employees

At December 31, 2007, we had 181 employees, 28 of whom were administrative, accounting or financial personnel and 153 of whom were technical and operations personnel. Our exploration staff includes three exploration geologists and six exploration landmen. We retained 67 employees of Ascent Energy following the Ascent acquisition. 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.

Available Information

Copies of our Annual Report on Form 10-K, Quarterly reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge through our website (www.ramenergy.com) as soon as reasonably practicable after we electronically file the material with, or furnish it to, the SEC. Our SEC filings are also available from the SEC’s website at: http://www.sec.gov. The references to our website address do not constitute incorporation by reference of the information contained on the website and should not be considered part of this report.

Item  3. 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.

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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 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 January 11, 2007, the Court entered an order certifying the plaintiff’s proposed class. We and the other defendants have appealed 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. In conjunction with our May 8, 2006 acquisition of RAM Energy, the former stockholders of RAM Energy deposited in escrow 3,200,000 shares of our common stock to secure their potential indemnity obligations to us, including any loss we might sustain in the Sacket litigation. These escrowed shares will remain in escrow until the Sacket litigation is resolved.

Item  4. Submission of Matters to a Vote of Security Holders

On November 29, 2007, we completed the Ascent acquisition. The total consideration paid by us in connection with the Ascent acquisition included 18,783,344 shares of our common stock and warrants to purchase 6,200,000 shares of our common stock at an exercise price of $5.00 per share, exercisable at any time or from time to time prior to May 11, 2008, and $203 million in cash (including $1.0 million of direct acquisition costs), of which $20.0 million was placed in escrow as a source of funds to adjust for Ascent’s closing date working capital deficiency, if any, and to indemnify us against, among other things, breaches of covenants, representations and warranties by Ascent. The total consideration included amounts to be paid to certain holders of Ascent’s outstanding indebtedness, amounts necessary to settle and close all of Ascent’s outstanding oil and natural gas hedging contracts, and payments to holders of all of Ascent’s outstanding preferred stock, common stock and warrants to purchase common stock.

Under Delaware law, we obtained approval of the Ascent acquisition and the related agreements by our board of directors and we were not required to obtain approval of the transaction by a vote of our stockholders. However, because our common stock is listed and traded on the NASDAQ Capital Market, and under the rules of the NASDAQ Capital Market, we were required to obtain approval of our stockholders for the issuance of the shares of our common stock in connection with the Ascent acquisition because the number of shares of our common stock issued in connection with the Ascent acquisition, on a fully diluted basis, would increase the number of our outstanding shares of common stock by more than 20%.

We received written consents in lieu of a stockholders’ meeting for approval of our issuance of a maximum of 20,500,000 shares of common stock (subject to rounding to eliminate fractional shares) and warrants to purchase an additional 6,200,000 shares of our common stock and shares of our common stock issuable upon the exercise of these warrants in connection with the Ascent acquisition from Larry E. Lee, Danish Knights, A Limited Partnership, and certain other of our stockholders who, collectively, beneficially owned shares of our common stock representing approximately 63% of the total voting power of the outstanding shares of our common stock entitled to vote on the issuance of our common stock and warrants in connection with the Ascent acquisition. No additional stockholder approval was required and appraisal rights were not available to our stockholders in connection with the Ascent acquisition.

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PART II

Item  5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for Common Stock

Our common stock and warrants are traded on the Nasdaq Capital Market under the symbols RAME and RAMEW, respectively. The following table sets forth the range of high and low closing bid prices for our common stock and warrants for the periods indicated.

	Common Stock				Warrants
	High		Low		High		Low
2008:
First Quarter (through March 14, 2008)	$	5.10	$	4.42	$	0.34	$	0.10
2007:
First Quarter	$	5.57	$	4.00	$	0.90	$	0.41
Second Quarter		5.56		4.25		0.90		0.45
Third Quarter		5.64		4.17		1.05		0.39
Fourth Quarter		5.46		4.65		0.84		0.26
2006:
First Quarter	$	5.89	$	5.46	$	1.18	$	0.78
Second Quarter		6.79		5.19		2.00		1.05
Third Quarter		5.79		4.68		1.75		0.77
Fourth Quarter		5.64		4.65		1.00		0.67
2005:
First Quarter	$	5.50	$	5.01	$	0.94	$	0.74
Second Quarter		5.56		5.12		0.82		0.57
Third Quarter		5.55		5.13		0.98		0.50
Fourth Quarter		5.56		5.31		0.95		0.65

Holders

As of March 13, 2008, there were 72 holders of record of our common stock and 11 holders of record of our warrants. We believe that at March 13, 2008, there were 1,452 beneficial holders of our common stock and 461 beneficial holders of our outstanding warrants.

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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The following table provides information for all equity compensation plans as of the fiscal year ended December 31, 2007, under which our equity securities were authorized for issuance:

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c)
Equity compensation plans approved by security holder (1)	1,121,576	(2)	$	4.28	1,122,933(4)
Equity compensation plans not approved by security holders	—			—	—
Total	1,121,576				1,122,933

(1) Shares awarded under all above plans may be newly issued, from our treasury or acquired in the open market.

(2) This number represents shares of restricted stock awards issued and outstanding under our 2006 Long Term Incentive Plan Stock Bonus Plan as of December 31, 2007.

(3) This represents the weighted average market price on the date of grant of shares of restricted stock issued under our 2006 Long Term Incentive Plan.

(4) This number reflects shares available for issuance under our 2006 Long Term Incentive Plan as of December 31, 2007.

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Stockholder Return Performance Presentation

The following graph compares the cumulative 43-month total return provided to our stockholders on our common stock beginning May 24, 2004 (the date of consummation of our initial public offering) through December 31, 2007, relative to the cumulative total returns of the Nasdaq Composite index and the Dow Jones Wilshire MicroCap Exploration & Production index. The comparison assumes an investment of $100 (with reinvestment of all dividends) was made in our common stock on May 24, 2004 and in each of the *indexes and its relative performance is tracked through December 31, 2007. The identity of the 50+ companies included in the Dow Jones Wilshire MicroCap Exploration & Production Index will be provided upon request.

	Fiscal year ending December 31,
	12/31/04		12/31/05		12/31/06		12/31/07
RAM Energy Resources, Inc.	$	108	$	117	$	117	$	107
Nasdaq Composite		113		116		129		142
Dow Jones Wilshire MicroCap Exploration & Production Index		123		164		194		133

Assumes $100 invested on May 24, 2004 in our common stock, and on April 30, 2004 in the Nasdaq Composite Index and the Dow Jones Wilshire MicroCap Exploration & Production Index.

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Item 6. Selected Consolidated Financial Data

We acquired RAM Energy effective May 8, 2006, by the merger of our wholly owned subsidiary with and into RAM Energy. 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 we had no active business operations prior to consummation of the merger. Accordingly, for accounting and financial reporting purposes, the RAM Energy acquisition was treated as the equivalent of RAM Energy issuing stock for our net monetary assets accompanied by a recapitalization. Our net monetary assets 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.

We acquired Ascent Energy Inc. on November 29, 2007, by the merger of our wholly owned subsidiary with and into Ascent. The Ascent acquisition was accounted for under the purchase method of accounting. Upon completion of the Ascent acquisition, Ascent adopted the full cost method of accounting for exploration, development and production of oil and natural gas.

The selected consolidated financial information presented below should be read in conjunction with our consolidated financial statements and the related notes, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained elsewhere in this report. Our financial position and results of operations for 2005, 2006 and 2007 may not be comparative to other periods as a result of certain divestitures and acquisitions, as more fully described in our consolidated financial statements included elsewhere in this report.

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Selected Consolidated Financial Data

(in thousands, except share data)

	Year Ended December 31,
	2003			2004			2005 (1)			2006			2007 (3)
Revenues and Other Operating Income:
Oil and natural gas sales	$	20,053		$	17,975		$	66,243		$	68,015		$	81,877
Gain on sale of subsidiary		—			12,139			—			—			—
Gain on sale assets		—			—			—			142			61
Other		170			338			851			498			427
Realized and unrealized gains (losses) from derivatives		(203	)		(793	)		(11,695	)		1,589			(12,725	)
Total revenues and other operating income		20,020			29,659			55,399			70,244			69,640
Operating Expenses:
Oil and natural gas production taxes		1,408			1,263			3,320			3,329			4,869
Oil and natural gas production expenses		3,527			3,600			16,099			18,266			21,574
Depreciation and amortization		4,098			3,273			12,972			13,252			18,948
Accretion expense		48			78			510			535			704
Share-based compensation		—			—			—			2,308			989
General and administrative, net of operator’s overhead fees		6,331			6,601			8,610			9,300			11,891
Total operating expenses		15,412			14,815			41,511			46,990			58,975
Operating income (loss)		4,608			14,844			13,888			23,254			10,665
Other Income (Expense):
Interest expense		(4,912	)		(5,070	)		(12,614	)		(17,050	)		(20,757	)
Interest income		41			35			75			309			1,047
Other expense		—			—			—			—			(57	)
Income (Loss) from Continuing Operations Before Income Taxes		(263	)		9,809			1,349			6,513			(9,102	)
Income Tax Provision (Benefit)		228			3,733			806			1,465			(7,852	)
Income (Loss) from Continuing Operations		(491	)		6,076			543			5,048			(1,250	)
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		(1,559	)		6,076			543			5,048			(1,250	)
Cumulative effect of change in accounting principle (net of tax benefit of $275)		(448	)		—			—			—			—
Net income (loss)	$	(2,007	)	$	6,076		$	543		$	5,048		$	(1,250	)

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Selected Consolidated Financial Data (continued)

(in thousands, except share data)

	Year Ended December 31,
	2003			2004			2005 (1)			2006			2007 (3)
Net income (loss) per share attributable to common stockholders—basic
Income (loss) from continuing operations	$	(0.02	)	$	0.20		$	0.02		$	0.16		$	(0.03	)
Loss from discontinued operations		(0.03	)		—			—			—			—
Cumulative effect of change in accounting principle		(0.01	)		—			—			—			—
Net income (loss) per share	$	(0.06	)	$	0.20		$	0.02		$	0.16		$	(0.03	)
Cash dividends per share	$	0.03		$	0.04		$	0.05		$	0.02		$	—
Earnings (loss) per share:
Basic	$	(0.06	)	$	0.20		$	0.02		$	0.16		$	(0.03	)
Diluted		(0.06	)		0.20			0.02			0.16			(0.03	)
Weighted average shares outstanding:
Basic		31,790,743			29,706,104			26,492,286			30,808,065			41,240,021
Diluted		31,790,743			29,706,104			26,492,286			32,105,885			41,240,021
Statement of Cash Flow Data
Cash provided by (used in):
Operating activities	$	5,774		$	1,793		$	18,359		$	30,537		$	17,042
Investing activities		7,422			(64,852	)		(12,554	)		(25,317	)		(241,192	)
Financing activities		(12,333	)		62,116			(6,910	)		1,431			224,302
Other Data
Capital expenditures (2)	$	5,258		$	102,719		$	13,528		$	28,145		$	344,795
EBITDA		8,670			18,153			33,747			33,419		$	42,352
	As of December 31,
	2003			2004			2005 (1)			2006			2007 (3)
Balance Sheet Data
Total assets	$	45,908		$	140,324		$	143,276		$	161,725		$	580,242
Long-term debt, including current portion		46,057			117,344			112,846			132,237			335,747
Stockholders’ equity (deficit)		(19,653	)		(19,912	)		(20,769	)		(27,895	)		98,698

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

(2) Includes costs of acquisitions.

(3) We acquired Ascent Energy Inc. in November 2007.

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 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.

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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,
	2003			2004			2005		2006			2007
	(in thousands)
Reconciliation of EBITDA to net income (loss):
Net income (loss)	$	(2,007	)	$	6,076		$	543	$	5,048		$	(1,250	)
Plus: Interest expense		4,912			5,070			12,614		17,050			20,757
Plus: Amortization and depreciation expense		4,098			3,273			12,972		13,252			18,948
Plus: Accretion expense		48			78			510		535			704
Plus: Income tax expense (benefit)		228			3,733			806		1,465			(7,852	)
Plus: Share-based compensation		—			—			—		2,308			989
Plus: Loss from discontinued operations, net of tax		1,068			—			—		—			—
Less: Cumulative effect of change in accounting principle		448			—			—		—			—
Plus: Unrealized (gain) loss on derivatives		(125	)		(77	)		6,302		(6,239	)		10,056
EBITDA	$	8,670		$	18,153		$	33,747	$	33,419		$	42,352

Item 7. 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, Oklahoma and West Virginia. Through our RAM Energy subsidiary, we have been active in our core producing areas of Texas, Oklahoma and Louisiana 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 wholly owned subsidiary into RAM Energy. The RAM Energy acquisition 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 RAM Energy acquisition, 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 RAM Energy acquisition, 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 RAM Energy acquisition, 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 RAM Energy acquisition was 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

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merger, our assets and liabilities were recorded at their fair value, which is considered to approximate historical cost, and added to those of RAM Energy. Because we had no active business operations prior to consummation of the merger, the merger was accounted for as a recapitalization of RAM Energy.

On February 13, 2007, we consummated a public offering of 7,500,000 shares of our common stock and received net proceeds of $28.1 million.

On November 29, 2007, we consummated our Ascent acquisition for a total consideration that included 18,783,444 shares of our common stock and warrants to purchase 6,200,000 shares of our common stock at an exercise price of $5.00 per share at any time prior to May 11, 2008, and $203 million in cash (including $1.0 million of direct acquisition costs), of which $20.0 million was deposited in escrow. The total consideration included amounts paid to certain holders of Ascent’s outstanding indebtedness, amounts necessary to settle and close all of Ascent’s outstanding oil and natural gas hedging contracts, and payments to holders of Ascent’s outstanding preferred stock and common stock.

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 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.

The Company accounts for its derivative arrangements under SFAS No. 133, “Accounting for Derivative Instrument and Hedging Activities” (“SFAS 133”). SFAS 133 requires the accounting recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (a “fair value hedge”) or against exposure to variability in expected future cash flows (a “cash flow hedge”). The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge by the Company. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value

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hedge, to the extent the hedge is effective, have no effect on the statement of operations due to the fact that changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in the fair value are recognized as earnings. The Company has not elected to designate its derivative instruments as hedges as required by SFAS 133 in order to receive hedge accounting treatment. Accordingly, all gains and losses on the derivative instrument have been recorded in earnings.

The Company accounts for share-based payments under SFAS No. 123R, “Share-Based Payments” (“SFAS 123R”). 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.

Effective January 1, 2007, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (“FIN 48”). The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.

Results of Operations

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Revenues and Other Operating Income. Our revenues and other operating income decreased by $604,000, or less than 1%, for the year ended December 31, 2007, compared to the year ended December 31, 2006. The decrease was primarily a result of unrealized losses on derivatives, offset by increased oil and natural gas sales, discussed below. The following table summarizes our oil and natural gas production volumes, average sales prices and period to period comparisons, including the effect on our oil and natural gas sales, for the periods indicated:

	Year ended December 31,				Increase (Decrease)
	2006		2007
Oil and natural gas sales (in thousands):	$	68,015	$	81,877	20.4	%
Production volumes:
Oil (MBbls)		752		774	2.8	%
NGL (MBbls)		143		184	28.6	%
Natural gas (MMcf)		2,365		2,785	17.8	%
Total Mboe		1,290		1,422	10.2	%
Average sale prices:
Oil (per Bbl)	$	63.82	$	71.11	11.4	%
NGL (per Bbl)	$	40.33	$	49.16	21.9	%
Natural gas (per Mcf)	$	6.02	$	6.40	6.4	%
Per Boe	$	52.74	$	57.60	9.2	%

Oil and Natural Gas Sales. Our oil and natural gas sales increased by $13.9 million, or 20%, for the year ended December 31, 2007, as compared to the year ended December 31, 2006. The increase was due to a 9% increase in product prices, and a 10% increase in production. Much of the increase was due to the acquisition of Ascent, which reported $5.9 million in oil and natural gas sales for the last month of 2007.

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For the year ended December 31, 2007, our oil production increased by 3%, our NGL production increased by 29%, and our natural gas production increased by 18%, compared to the previous year. Our average realized sales price for oil was $71.11 per barrel for the year ended December 31, 2007, an increase of 11% compared to $63.82 per barrel for the previous year. Our average realized NGL price for the year ended December 31, 2007 was $49.16 per barrel, an increase of 22% compared to $40.33 for the year ended December 31, 2006. Our average realized natural gas price was $6.40 per Mcf for the 2007 reporting period, an increase of 6% compared to $6.02 per Mcf for the year ended December 31, 2006.

Other Revenues. Other revenues for the year ended December 31, 2007 decreased by $71,000 to $427,000, or 14%, compared to other revenues of $498,000 in the year ended December 31, 2006.

Realized and Unrealized Gain (Loss) from Derivatives. For the year ended December 31, 2007, our loss from derivatives was $12.7 million, compared to a gain of $1.6 million for the previous year. 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 RAM Energy, Inc.’s derivative contracts as of each year end.

	Year ended December 31,
	2006			2007
Contract settlements and premium costs:
Oil	$	(4,349	)	$	(3,362	)
Natural gas		(301	)		693
Realized (losses)		(4,650	)		(2,669	)
Mark-to-market gains (losses):
Oil		1,686			(9,689	)
Natural gas		4,553			(367	)
Unrealized gains (losses)		6,239			(10,056	)
Realized and unrealized gains (losses)	$	1,589		$	(12,725	)

Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes were $4.9 million for the year ended December 31, 2007, compared to $3.3 million for the year ended December 31, 2006. Production taxes are based on realized prices at the wellhead or volumes of production. As revenues or production volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. As a percentage of oil and natural gas sales, oil and natural gas production taxes were 6.0% for the year ended December 31, 2007, compared to 4.9% for the year ended December 31, 2006.

Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $21.6 million for the year ended December 31, 2007, an increase of $3.3 million, or 18%, from the $18.3 million for the previous year. Ascent reported $1.4 million of production expense for the last month of 2007. For the year ended December 31, 2007, our oil and natural gas production expense was $15.18 per Boe compared to $14.16 per Boe for the year ended December 31, 2006, an increase of 7%. As a percentage of oil and natural gas sales, oil and natural gas production expense decreased slightly to 26% for the year ended December 31, 2007, down from 27% in the year ended December 31, 2006.

Amortization and Depreciation Expense. Our amortization and depreciation expense increased $5.7 million, or 43%, for the year ended December 31, 2007, compared to the year ended December 31, 2006. The increase was primarily a result of our Ascent acquisition in late November 2007, which represented $2.8 million amortization and depreciation expense for the last month of the year. Also contributing to the increase was higher capitalized costs due to increased drilling in the last half of 2007. On an equivalent basis, our amortization of the

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full-cost pool of $18.3 million was $12.86 per Boe for the year ended December 31, 2007, an increase per Boe of 32% compared to $12.6 million, or $9.77 per Boe for the year ended December 31, 2006.

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 $704,000 for the year ended December 31, 2007, compared to $535,000 for the year 2006.

Share-Based Compensation. Our Board of Directors awarded grants in accordance with our 2006 Long-Term Incentive Plan. The share-based compensation on these grants was calculated using the closing price per share on each of the grant dates. The total share-based compensation on all these grants will be recognized over vesting periods ranging from one month to five years. For the year ended December 31, 2007, we recognized a total of $989,000 share-based compensation on these grants, compared to $2.3 million recognized in 2006.

General and Administrative Expense. For the year ended December 31, 2007, our general and administrative expense was $11.9 million, compared to $9.3 million for the year ended December 31, 2006, an increase of $2.6 million, or 28%. The acquisition of Ascent in late November 2007 represented $510,000 of this increase. The remainder of the increase was due to higher salaries resulting from a larger employee base and increased salaries.

Interest Income. Interest income was $1.0 million for the year ended December 31, 2007 compared to $309,000 for the year ended December 31, 2006. The increase was due to higher cash balances resulting from proceeds held from the common stock offering which closed in February of 2007. Cash balances remained high through November 2007, when we utilized the cash in the Ascent acquisition.

Interest Expense. Our interest expense increased by $3.7 million, to $20.8 million for the year ended December 31, 2007, compared to $17.1 million incurred for the previous year. As a result of refinancing, the write-off of unamortized loan costs made up $2.4 million interest expense in 2007 compared to $2.1 million of unamortized loan costs and prepayment premiums written off in 2006. The overall increased expense is due to additional borrowings on the revolving credit facility during the 2007 period.

Income Taxes. For the year ended December 31, 2007, we recorded an income tax benefit of $3.3 million on a pre-tax loss of $9.1 million. We also reduced income tax expense by $4.6 million in the third quarter of 2007 to reverse an uncertain tax position and related accrued interest as a result of the expiration of the applicable statute of limitations period. For the year ended December 31, 2006, our income tax expense was $1.5 million, on a pre-tax income of $6.5 million. Excluding the reversal of the uncertain tax positions, the effective tax rate was 36% for the year ended December 31, 2007 and 22% for 2006.

Net Income. Our net loss was $1.3 million for the year ended December 31, 2007, compared to a net income of $5.0 million for the year ended December 31, 2006. The decrease in our net income for the year ended December 31, 2007 resulted from increased unrealized losses from derivatives and increased amortization and depreciation expense, offset by increased oil and natural gas sales and an uncertain tax position reversal.

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Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Revenues and Other Operating Income. Our revenues and other operating income increased by $14.8 million, or 27%, for the year ended December 31, 2006, compared to the year ended December 31, 2005. The increase was primarily a result of unrealized gains on derivatives, discussed below. The following table summarizes our oil and natural gas production volumes, average sales prices and period to period comparisons, including the effect on our oil and natural gas sales, for the periods indicated:

	Year ended December 31,				Increase (Decrease)
	2005		2006
Oil and natural gas sales (in thousands)	$	66,243	$	68,015	2.7	%
Production volumes:
Oil (MBbls)		787		752	(4.5	)%
NGL (MBbls)		170		143	(16.1	)%
Natural gas (MMcf)		2,681		2,365	(11.8	)%
Total MBoe		1,405		1,290	(8.2	)%
Average sale prices:
Oil (per Bbl)	$	53.75	$	63.82	18.7	%
NGL (per Bbl)	$	36.33	$	40.33	11.0	%
Natural gas (per Mcf)	$	6.61	$	6.02	(9.0	)%
Per Boe	$	47.16	$	52.74	11.8	%

Oil and Natural Gas Sales. Our oil and natural gas revenues increased by $1.8 million, or 3%, for the year ended December 31, 2006, as compared to the year ended December 31, 2005, due to a 12% increase in product prices, offset by an 8% decrease in production.

For the year ended December 31, 2006, our average daily production was 3,533 Boe, a decrease of 8% compared with average daily production during calendar year 2005 of 3,848 Boe. A reversionary interest burdening our properties in our Boonsville shallow gas area vested in September 2005 and, accordingly, reduced our interest in the related properties. This interest represented 136 Boe per day in 2005, or 4% of average daily production in 2006. The vesting of this reversionary interest caused a 4% decrease in average daily production in 2006. The remaining 4% decrease in average daily production resulted from weather-related downtime, and natural declines in production.

For the year ended December 31, 2006, our oil production decreased by 5%, our NGL production decreased by 16%, and natural gas production decreased by 12%, compared to the year ended December 31, 2005. Our average realized sales price for oil was $63.82 per barrel for the year ended December 31, 2006, an increase of 19% compared to $53.75 per barrel for the year ended December 31, 2005. Our average realized NGL price for the year ended December 31, 2006 was $40.33 per barrel, an 11% increase compared to $36.33 per barrel for the year ended December 31, 2005. Our average realized natural gas price was $6.02 per Mcf for the year ended December 31, 2006, a decrease of 9% compared to $6.61 per Mcf for the year ended December 31, 2005.

Other Revenues. Other revenues for the year ended December 31, 2006 decreased $353,000, or 41%, compared to the year ended December 31, 2005.

Realized and Unrealized Gain (Loss) from Derivatives. For the year ended December 31, 2006, our gain from derivatives was $1.6 million, compared to a loss of $11.7 million for the year ended December 31, 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 RAM Energy’s derivative contracts.

41

	Year ended December 31,
	2005			2006
Contract settlements and premium costs:
Oil	$	(2,594	)	$	(4,349	)
Natural gas		(2,799	)		(301	)
Realized (losses)		(5,393	)		(4,650	)
Mark-to-market gains (losses):
Oil		(2,075	)		1,686
Natural gas		(4,227	)		4,553
Unrealized gains (losses)		(6,302	)		6,239
Realized and unrealized gains (losses)	$	(11,695	)	$	1,589

Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes for the year ended December 31, 2006, remained steady at $3.3 million, increasing by $9,000, or 0.3%, from the year ended December 31, 2005. 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 also increase or decrease. As a percentage of oil and natural gas sales, oil and natural gas production taxes were 4.9% for the year ended December 31, 2006, compared to 5.0% for the previous year.

Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $18.3 million for the year ended December 31, 2006, an increase of $2.2 million, or 13%, from the $16.1 million for the year ended December 31, 2005. The increase was primarily due to increased utility costs and higher maintenance costs due to additional producing wells. For the year ended December 31, 2006, our oil and natural gas production expense was $14.16 per Boe compared to $11.46 per Boe for the year ended December 31, 2005, an increase of 24%. As a percentage of oil and natural gas sales, oil and natural gas production expense was 27% for the year ended December 31, 2006, a 3% increase compared to the previous year.

Amortization and Depreciation Expense. Our amortization and depreciation expense increased $280,000, or 2%, for the year ended December 31, 2006, compared to the year ended December 31, 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 $12.6 million was $9.77 per Boe for the year ended December 31, 2006, an increase per Boe of 9% compared to $12.5 million, or $8.93 per Boe for the year ended December 31, 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 $535,000 for the year ended December 31, 2006, compared to $510,000 for the previous year.

Share-Based Compensation. Concurrent with our RAM Energy acquisition 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 year ended December 31, 2006, our share-based compensation on these grants was $2.2 million, calculated using a closing price on May 8, 2006, the day the shares were granted, of $6.72 per share.

On November 11, 2006, our Board of Directors awarded grants in accordance with our 2006 Long-Term Incentive Plan totaling 646,805 shares of our common stock to certain key employees. The $3.3 million share-based compensation on these grants was calculated using the closing price on November 10, 2006, the grant date, of $5.06 per share. The total share-based compensation will be recognized over a five year vesting period. For the year ended December 31, 2006, we recognized a total of $91,000 share-based compensation on these grants, bringing our total share-based compensation to $2.3 million for 2006.

42

General and Administrative Expense. For the year ended December 31, 2006, our general and administrative expense was $9.3 million, compared to $8.6 million for the year ended December 31, 2005, an increase of $690,000, or 8%.

Interest Expense. Our interest expense increased by $4.4 million, to $17.1 million for the year ended December 31, 2006, compared to $12.6 million incurred for the year ended December 31, 2005. During the second quarter we charged off $1.1 million of unamortized costs associated with our previous credit facility and paid prepayment premiums of $1.0 million. The remaining interest expense of $15.0 million represents an increase of $2.4 million, or 19%, over the $12.6 million reported for the previous year. This increase was due to higher interest rates and higher outstanding indebtedness during the 2006 period.

Income Taxes. For the year ended December 31, 2006, we recorded an income tax expense of $1.5 million, on a pre-tax income of $6.5 million. For the year ended December 31, 2005, our income tax expense was $806,000, on a pre-tax income of $1.3 million. The effective tax rate was 22% for 2006 and 60% for 2005. The decrease in the effective tax rate is due to an adjustment to deferred taxes for a reduction in tax rates in Texas.

Net Income. Our net income was $5.0 million for the year ended December 31, 2006, compared to net income of $543,000 for the previous year. The increase in our net income for the year 2006 resulted from higher product prices and gains from derivatives, partially offset by increased production expense, share-based compensation, and interest expense.

Liquidity and Capital Resources

As of December 31, 2007, we had cash and cash equivalents of $6.9 million and $68.6 million was available under our revolving credit facility. At that date, we had $335.7 million of indebtedness outstanding, including $306.4 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’s 11½% senior notes due 2008, and $1.0 million in other indebtedness.

As of December 31, 2007, we had an accumulated deficit of $29.0 million and a working capital deficit of $34.4 million. The working capital deficit includes a current liability of $28.4 million for RAM Energy’s senior notes which matured and were retired in February 2008 using proceeds from borrowings under our credit facility. Our management believes that borrowings currently available to us under our credit facilities ($68.6 million available at December 31, 2007), the balance of unrestricted cash, and anticipated cash flows from operations will be sufficient to satisfy our 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. We cannot assure you that any such financing will be available on acceptable terms or at all.

New Credit Facility. In November 2007, in conjunction with the Ascent acquisition, we entered into a new $500.0 million credit facility with Guggenheim Corporate Funding, LLC, for itself and on behalf other institutional lenders. The new facility, which replaced our previous $300.0 million facility, includes a $175.0 million revolving credit facility and a $200.0 million term loan facility. The entire amount of the $200.0 million term loan was advanced at closing. The borrowing base under the revolving credit facility at the closing was $175.0 million, a portion of which was advanced at the closing of the Ascent acquisition. Borrowings under the new facility were used to refinance RAM Energy’s existing indebtedness, fund the cash requirements in connection with the closing of the Ascent acquisition, and for working capital and other general corporate purposes. Funds advanced under the revolving credit facility may be paid down and re-borrowed during the four-year term of the revolver, and bear interest at LIBOR plus a margin ranging from 1.25% to 2.0% based on a percentage of usage. The term loan provides for payments of interest only during its five-year term, with the interest rate being LIBOR plus 7.5%.

43

Advances under the new facility are secured by liens on substantially all of our properties and assets and those of our subsidiaries, including Ascent and its subsidiaries. The loan agreement contains representations, warranties and covenants customary in transactions of this nature, including financial covenants relating to current ratio, minimum interest coverage ratio, maximum leverage ratio and a required ratio of asset value to total indebtedness. We are required to maintain commodity hedges with respect to not less than 50%, but not more than 85%, of our projected monthly production volumes on a rolling 30-month basis, until the leverage ratio is less than or equal to 2.0 to 1.0. At December 31, 2007, approximately $28.4 million of availability under the revolving credit facility was reserved for payment of RAM Energy’s outstanding 11½% senior notes, which became due and payable on February 15, 2008, and $25.0 million was allocated for development of our proved undeveloped properties. At December 31, 2007, $106.4 million was outstanding under the revolving credit facility and $200.0 was outstanding under the term facility.

Senior Notes. On February 24, 1998, RAM Energy issued $115.0 million principal amount of its 11½% senior notes which matured February 15, 2008. We were not a party to, or a guarantor of, the senior notes or of any obligations under the indenture covering the senior notes. At December 31, 2007, RAM Energy had outstanding $28.4 million aggregate principal amount of its senior notes. We paid off the RAM Energy senior notes at their maturity on February 15, 2008 with long term borrowings under our revolving credit facility.

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 year ended December 31, 2007, our net loss was $1.3 million, as compared with net income of $5.0 million for the year ended December 31, 2006. Adjustments (primarily non-cash items such as depreciation and amortization, unrealized gain or loss on derivatives, share-based compensation and deferred income taxes) were $24.9 million for the year ended December 31, 2007 compared to $13.0 million for the year of 2006, an increase of $11.9 million. Unrealized loss on derivatives and changes in depreciation offset by changes in deferred income taxes caused most of this increase. Working capital changes for the year ended December 31, 2007 were a negative $6.6 million compared with positive changes of $11.5 million for the year ended December 31, 2006. For the year ended December 31, 2007, in total, net cash provided by operating activities was $17.0 million compared to $29.7 million of net cash provided by operations for the previous year.

For the year ended December 31, 2006, our net income was $5.0 million, as compared with net income of $0.5 million for 2005. Adjustments (primarily non-cash items such as depreciation and amortization, unrealized (gain) loss on derivatives, share-based compensation and deferred income taxes) were $13.0 million for 2006 compared to $22.5 million for 2005, a decrease of $9.5 million. Unrealized gain on derivatives, partially offset by share-based compensation, changes in deferred income taxes, was the primary reason for the decrease. Working capital changes for 2006 were a positive $11.5 million compared with negative changes of $4.6 million for 2005. For 2006, in total, net cash provided by operating activities was $29.7 million compared to $18.4 million of net cash provided by operations for the previous year.

Cash Flow From Investing Activities. For the year ended December 31, 2007, net cash used in our investing activities consisted of $200.0 million (net of cash acquired) for our acquisition of Ascent Energy, $18.7 million in other acquisitions, capital expenditures of $21.4 million, and other additions and sales proceeds which totalled $1.1 million.

For the year ended December 31, 2006, net cash used in our investing activities was $25.3 million, consisting of $28.1 million in payments for oil and natural gas properties and equipment and $812,000 in payments for other property and equipment, offset by $3.6 million of proceeds from the sale of undeveloped acreage, $500,000 in proceeds from the sale of other property and equipment, and $400,000 of net merger costs. The year ended December 31, 2006 reflected a 102% increase in cash used in investing activities compared to the previous year. For 2005, net cash used in our investing activities was $12.6 million, consisting of $13.5 million in payments for oil and natural gas properties and $1.5 million for other property and equipment additions, offset by $2.5 million in proceeds from the sale of oil and natural gas properties.

44

Cash Flow From Financing Activities. For the year ended December 31, 2007, net cash provided by our financing activities was $224.3 million, compared to net cash provided of $2.3 million for the year ended December 31, 2006. The cash provided in 2007 included $199.5 million in proceeds from borrowing on long-term debt in connection with the Ascent acquisition, and $27.4 million in net proceeds from a common stock offering, partially offset by a $2.4 million net debt decrease and $177,000 for the repurchase of stock. The cash provided in 2006 included an approximate $16.4 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.

The net cash used in 2005 of $6.9 million included $5.5 million net debt decrease and $1.4 million in dividends paid.

Capital Commitments

During 2007, we had capital expenditures of $344.8 million relating to our oil and natural gas operations, of which $12.9 million was allocated to drilling new development wells, $7.7 million was for exploration costs, and $324.2 million was for acquisition costs. Our non-acquisition capital expenditures for the year 2007 aggregated approximately $20.6 million.

We have budgeted $80.0 million for non-acquisition capital expenditures in 2008 related to:

• geological, geophysical and seismic costs ($5.0 million);

• developmental drilling and recompletions ($71.5 million); and

• exploratory drilling, including leasehold acquisitions ($3.5 million).

In our 2008 non-acquisition capital budget, we have allocated $19.0 million for drilling and development activities on our West Virginia Devonian shale properties, an additional $19.0 million for drilling on our South Texas properties, $10.0 million for our North Texas Barnett shale, $7.5 million for continued development of our Electra/Burkburnett area, and $7.5 million to our Pontotoc properties in Oklahoma.

The amount and timing of our capital expenditures for calendar year 2008 may vary depending on a number of factors, including the favorable or unfavorable results of operations actually conducted, projects proposed by third party operators on jointly owned acreage, development by third party operators on adjoining properties, rig and service company availability, and other influences that we cannot predict.

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, 2007, which are obligations during the following years:

	Total		2008		2009-2010		2011-12		and after
	(in thousands)
Contractual Cash Obligations
Long-term debt	$	335,747	$	29,231	$	159	$	306,357	$	—
Operating leases		4,439		944		1,466		1,447		582
Total contractual cash obligations	$	340,186	$	30,175	$	1,625	$	307,804	$	582

45

Item 7A. 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, and as required by our lenders, we 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 open derivative positions at December 31, 2007 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
2008	1,500	$	65.33	1,500	$	83.79	4,000	$	6.77	4,000	$	13.23
2009	1,248	$	58.42	1,248	$	79.03	4,000	$	7.00	4,000	$	10.98
2010	500	$	60.00	500	$	80.00	—		—	—		—
	Secondary Floors
	Per Day	Price
Year
2009	800	$	75.00
	Bare Floors
	Per Day	Price
Year
2008	1,800	$	71.15
2009	1,000	$	65.00

Crude oil and natural gas floors and ceilings for 2008 cover the calendar year. Crude oil bare floors for 2008 cover the calendar year. Crude oil floors and ceilings for 2009 cover the calendar year, and natural gas floors and ceilings for 2009 cover January through September. Crude oil secondary floors for 2009 cover January through March. Crude oil bare floors for 2009 cover January through June. Crude oil floors and ceilings for 2010 cover January through March.

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Item 8. Financial Statements

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
RAM Energy Resources, Inc.
Report of Independent Registered Public Accounting Firm	48
Consolidated Balance Sheets as of December 31, 2007 and 2006	49
Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005	50
Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2007, 2006 and 2005	51
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005	52
Notes to Consolidated Financial Statements	53

47

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RAM Energy Resources, Inc.

We have audited the accompanying consolidated balance sheets of RAM Energy Resources, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the 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 presently fairly, in all material respects, the consolidated financial position of RAM Energy Resources, Inc. and subsidiaries at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note A to the consolidated financial statements, the Company changed its method of accounting for uncertain income tax positions effective January 1, 2007.

As discussed in Note N to the consolidated financial statements, the Company changed its method of accounting for share-based compensation effective January 1, 2006.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of RAM Energy Resources, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 17, 2008 expressed an unqualified opinion on the effective operation of internal control over financial reporting.

/s/    UHY LLP

Houston, Texas

March 17, 2008

48

RAM Energy Resources, Inc.

Consolidated Balance Sheets

(in thousands, except share and per share amounts)

	As of December 31,
	2007			2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,873		$	6,721
Accounts receivable:
Oil and natural gas sales, net of allowance of $287 ($0 at December 31, 2006)		15,136			6,194
Joint interest operations, net of allowance of $428 ($187 at December 31, 2006)		687			750
Income taxes		58			121
Other, net of allowance of $26 ($33 at December 31, 2006)		2,180			236
Derivative assets		—			677
Prepaid expenses		1,928			1,013
Deferred tax asset		3,786			—
Other current assets		842			—
Total current assets		31,490			15,712
PROPERTIES AND EQUIPMENT, AT COST:
Proved oil and natural gas properties and equipment, using full cost accounting		573,470			185,284
Unevaluated oil and natural gas properties		26,895			—
Other property and equipment		8,787			6,098
		609,152			191,382
Less accumulated depreciation and amortization		(67,529	)		(48,577	)
Total properties and equipment		541,623			142,805
OTHER ASSETS:
Deferred loan costs, net of accumulated amortization of $4,540 ($4,840 at December 31, 2006)		5,135			2,593
Other		1,994			615
Total assets	$	580,242		$	161,725
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable:
Trade	$	11,121		$	7,810
Oil and natural gas proceeds due others		7,800			3,886
Related party		31			14
Other		1,371			31
Accrued liabilities:
Compensation		3,807			1,611
Interest		3,794			3,849
Franchise taxes		1,286			—
Income taxes		203			223
Other		75			—
Derivative liabilities		5,302			—
Asset retirement obligations		1,904			—
Long-term debt due within one year		29,231			756
Total current liabilities		65,925			18,180
OIL & NATURAL GAS PROCEEDS DUE OTHERS		2,383			2,481
DERIVATIVE LIABILITIES		3,073			—
LONG-TERM DEBT		306,516			131,481
DEFERRED INCOME TAXES		71,051			17,044
ASSET RETIREMENT OBLIGATIONS		25,741			10,801
UNCERTAIN TAX POSITIONS		6,855			9,633
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY (DEFICIT):
Common stock, $0.0001 par value, 100,000,000 shares authorized, 60,842,836 and 34,276,805 shares issued, 59,971,945 and 33,439,530 shares outstanding at December 31, 2007 and 2006, respectively		6			3
Additional paid-in capital		131,625			2,308
Treasury stock—889,666 shares (837,275 shares at December 31,2006) at cost		(3,945	)		(3,768	)
Accumulated deficit		(28,988	)		(26,438	)
Stockholders' equity (deficit)		98,698			(27,895	)
Total liabilities and stockholders' equity (deficit)	$	580,242		$	161,725

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

49

RAM Energy Resources, Inc.

Consolidated Statements of Operations

(in thousands, except share and per share amounts)

	Years ended December 31,
	2007			2006			2005
REVENUES AND OTHER OPERATING INCOME:
Oil and natural gas sales	$	81,877		$	68,015		$	66,243
Gain on sale of assets		61			142			—
Other		427			498			851
Realized and unrealized gains (losses) from derivatives		(12,725	)		1,589			(11,695	)
Total revenues and other operating income		69,640			70,244			55,399
OPERATING EXPENSES:
Oil and natural gas production taxes		4,869			3,329			3,320
Oil and natural gas production expenses		21,574			18,266			16,099
Depreciation and amortization		18,948			13,252			12,972
Accretion expense		704			535			510
Share-based compensation		989			2,308			—
General and administrative, overhead and other expenses, net of operator’s overhead fees		11,891			9,300			8,610
Total operating expenses		58,975			46,990			41,511
Operating income		10,665			23,254			13,888
OTHER INCOME (EXPENSE):
Interest expense		(20,757	)		(17,050	)		(12,614	)
Interest income		1,047			309			75
Other expense		(57	)		—			—
INCOME (LOSS) BEFORE INCOME TAXES		(9,102	)		6,513			1,349
INCOME TAX PROVISION (BENEFIT)		(7,852	)		1,465			806
Net income (loss)	$	(1,250	)	$	5,048		$	543
BASIC EARNINGS (LOSS) PER SHARE	$	(0.03	)	$	0.16		$	0.02
BASIC WEIGHTED AVERAGE SHARES OUTSTANDING		41,240,021			30,808,065			26,492,286
DILUTED EARNINGS (LOSS) PER SHARE	$	(0.03	)	$	0.16		$	0.02
DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING		41,240,021			32,105,885			26,492,286

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

50

RAM Energy Resources, Inc.

Consolidated Statements of Stockholders’ Equity (Deficit)

Years ended December 31, 2007, 2006, and 2005

(In thousands, except share amounts)

	Common Stock				Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Stockholders' Equity (Deficit)
	Shares		Amount
BALANCE, January 1, 2005	26,492,286		$	2	$	94		$	—		$	(20,008	)	$	(19,912	)
Net income	—			—		—			—			543			543
Dividends declared	—			—		—			—			(1,400	)		(1,400	)
BALANCE, December 31, 2005	26,492,286			2		94			—			(20,865	)		(20,769	)
Net income	—			—		—			—			5,048			5,048
Dividends declared	—			—		—			—			(500	)		(500	)
Stock redemption & cancellation	(892,286	)		—		(93	)		—			(9,699	)		(9,792	)
Net cost of acquisition, less cash acquired, May 8, 2006	7,700,000			1		(1	)		—			(422	)		(422	)
Repurchase of stock	—			—		—			(3,768	)		—			(3,768	)
Share-based compensation	976,805			—		2,308			—			—			2,308
BALANCE, December 31, 2006	34,276,805			3		2,308			(3,768	)		(26,438	)		(27,895	)
Long term incentive plan grants	300,262			—		—			—			—			—
Long term incentive plan forfeitures	(18,775	)		—		—			—			—			—
Adoption of FIN 48 (uncertain tax positions)	—			—		—			—			(1,300	)		(1,300	)
Net loss	—			—		—			—			(1,250	)		(1,250	)
Issuance of shares for cash, net of costs	7,500,000			1		27,365			—			—			27,366
Issuance of shares relating to merger with Ascent Energy, Inc.	18,783,344			2		96,908			—			—			96,910
Issuance of warrants relating to merger with Ascent Energy, Inc.	—			—		4,049			—			—			4,049
Warrants exercised	1,200			—		6			—			—			6
Repurchase of stock	—			—		—			(177	)		—			(177	)
Share-based compensation	—			—		989			—			—			989
BALANCE, December 31, 2007	60,842,836		$	6	$	131,625		$	(3,945	)	$	(28,988	)	$	98,698

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

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RAM Energy Resources, Inc.

Consolidated Statements of Cash Flows

(in thousands)

	Years ended December 31,
	2007			2006			2005
OPERATING ACTIVITIES:
Net income (loss)	$	(1,250	)	$	5,048		$	543
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depreciation and amortization		18,948			13,252			12,972
Amortization of deferred loan costs and Senior Notes discount		945			988			839
Write off of loan fees due to debt refinancing		2,435			1,055			—
Accretion expense		704			535			510
Unrealized (gain) loss on derivatives		10,056			(6,239	)		6,302
Derivative premiums net of amortization		—			—			634
Deferred income taxes		(9,165	)		1,311			1,199
Share-based compensation		989			2,308			—
Gain on disposal of other property and equipment		(61	)		(142	)		—
Undistributed losses on investment		57			—			—
Changes in operating assets and liabilities, net of acquisitions
Accounts receivable		(2,775	)		1,012			(2,608	)
Prepaid expenses and other assets		(117	)		229			(143	)
Accounts payable and proceeds due others		(3,626	)		4,173			(165	)
Accrued liabilities and other		(1,286	)		6,025			(1,331	)
Income taxes payable		1,313			105			(393	)
Asset retirement obligations		(125	)		—			—
Total adjustments		18,292			24,612			17,816
Net cash provided by operating activities		17,042			29,660			18,359
INVESTING ACTIVITIES:
Payments for oil and natural gas properties and equipment		(40,101	)		(28,145	)		(13,528	)
Proceeds from sales of oil and natural gas properties		170			3,565			2,471
Payments for other property and equipment		(1,394	)		(812	)		(1,497	)
Proceeds from sales of other property and equipment		71			461			—
Acquisition of Ascent, net of cash acquired		(199,726	)		(4,187	)		—
Cash acquired in reverse merger		—			3,801			—
Other investments		(212	)		—			—
Net cash used in investing activities		(241,192	)		(25,317	)		(12,554	)
FINANCING ACTIVITIES:
Payments on long-term debt		(921	)		(88,094	)		(15,615	)
Proceeds from borrowings on long-term debt		199,508			107,443			10,670
Payments for deferred loan costs		(1,480	)		(2,981	)		(565	)
Stock redemption		—			(9,792	)		—
Stock repurchased		(177	)		(3,768	)		—
Common stock offering, net of costs		27,366			—			—
Warrants exercised		6			—			—
Dividends paid		—			(500	)		(1,400	)
Net cash provided by (used in) financing activities		224,302			2,308			(6,910	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		152			6,651			(1,105	)
CASH AND CASH EQUIVALENTS, beginning of year		6,721			70			1,175
CASH AND CASH EQUIVALENTS, end of year	$	6,873		$	6,721		$	70
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for income taxes	$	18		$	124		$	20
Cash paid for interest	$	16,936		$	10,080		$	3,297
DISCLOSURE OF NON CASH INVESTING AND FINANCING ACTIVITIES:
Accrued interest added to principal balance of credit facility	$	481		$	2,848		$	8,093
Loan fees added to principal balance of credit facility	$	4,400		$	—		$	—
Issuance of stock and warrants for Ascent merger	$	101,065		$	—		$	—
Establishment of asset retirement obligations	$	17,328		$	—		$	—

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

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RAM Energy Resources, Inc.

Notes to consolidated financial statements

December 31, 2007 and 2006

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

1. Nature of Operations and Organization

On May 8, 2006, Tremisis Energy Acquisition Corporation, or Tremisis, acquired RAM Energy, Inc., or RAM Energy, through the merger of a subsidiary of Tremisis into RAM Energy. 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 and the stockholders of RAM Energy. Upon completion of the merger, RAM Energy 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 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 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 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 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 redeemed a portion of its outstanding stock for an aggregate consideration of $10.0 million.

The merger was 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 RAM Energy and RAM Energy has been treated as the acquirer and continuing reporting entity for accounting purposes. The assets and liabilities of Tremisis have been stated at historical cost, and added to those of RAM Energy.

On November 29, 2007, the Company acquired Ascent Energy Inc., an acquisition that significantly increased the size of the Company. See Note B.

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, New Mexico and West Virginia.

2. Basis of Presentation

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

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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. The costs of unevaluated oil and natural gas properties are excluded from the amortizable base until the time that either proven reserves are found or it has been determined that such properties are impaired. The Company had capitalized costs related to unevaluated properties of $26,895,000 as of December 31, 2007. As these properties become evaluated, the related costs will be transferred to proved oil and natural gas properties using full cost accounting. All capitalized costs were included in the amortization base as of December 31, 2007.

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 $2,886,000, $2,303,000, and $1,778,000 for the years ended December 31, 2007, 2006, and 2005, 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.

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, 2007 and 2006 is approximately $4,041,000 and $3,375,000, 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 2007, 2006, or 2005.

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 twenty 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

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

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less than the Company’s net interest is recorded as a gas balancing asset or liability. At December 31, 2007 and 2006, the Company’s gas imbalances were immaterial.

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.

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 2007, approximately 62% of total revenues were to three customers (75% to two customers in 2006 and 73% to two customers in 2005), with sales to each comprising 50%, 7% and 5% (62% and 13% in 2006 and 55% and 18% in 2005) of total revenues. The Company provides an allowance for doubtful accounts for certain purchasers and certain joint interest owners receivable balances when the Company believes the receivable balance may not be collected. Accounts receivable are presented net of the related allowance for doubtful accounts.

In 2007 and 2006 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 (in thousands):

Year ending December 31,
2008	$1,185
2009	$1,175
2010	$1,175
2011	$1,121
2012	$   479

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, $271,000, and $228,000 for the years ended December 31, 2007, 2006, and 2005, 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

55

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. The Company evaluates its estimates and assumptions on a regular basis. Estimates are based on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates used in preparation of our financial statements. In addition, alternatives can exist among various accounting methods. In such cases, the choice of accounting method can have a significant impact on reported amounts.

11. Oil and Natural Gas Reserves Estimates

Independent petroleum and geological engineers prepare estimates of the Company’s oil and natural gas reserves. Proved reserves, estimated future net revenues and the present value of our reserves are estimated based upon a combination of historical data and estimates of future activity. Consistent with SEC requirements, we have based our present value of proved reserves on spot prices on the date of the estimate. The reserve estimates are used in calculating depletion, depreciation and amortization and in the assessment of the Company’s Ceiling Limitation. Significant assumptions are required in the valuation of proved oil and natural gas reserves which, as described herein, may affect the amount at which oil and natural gas properties are recorded. Actual results could differ materially from these estimates.

12. 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 approximates fair value at December 31, 2007 and was approximately $710,000 below fair value at December 31, 2006 based on management’s estimates. Management based its estimate on information from the bond underwriters on current bids for the Company’s Senior Notes.

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 less a discount to recognize the present value for contracts in excess of one year.

13. Reclassifications

Certain reclassifications of previously reported amounts for 2006 and 2005 have been made to conform to the 2007 presentation. These reclassifications had no effect on net income or loss or cash flows from operating, investing or financing activities.

14. 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 J). The Company did not designate these

56

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 2007, 2006 and 2005 have been recorded in the statements of operations.

15. Earnings (Loss) per Common Share

Basic earnings (loss) per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) 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):

	2007			2006		2005
Net income (loss)	$	(1,250	)	$	5,048	$	543
Weighted average shares – basic		41,240,021			30,808,065		26,492,286
Dilutive effect of unvested stock grants		—			78,864		—
Dilutive effect of warrants		—			1,218,956		—
Weighted average shares – diluted		41,240,021			32,105,885		26,492,286
Basic earnings (loss) per share	$	(0.03	)	$	0.16	$	0.02
Diluted earnings (loss) per share	$	(0.03	)	$	0.16	$	0.02

16. 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. We determine our asset retirement obligation by calculating the present value of the estimated cash flows related to the liability. Periodic accretion of the discount of the estimated liability is recorded in the income statement. The Company recorded accretion expense of approximately $704,000, $535,000, and $510,000 in 2007, 2006, and 2005, respectively.

The Company recorded the following activity related to the asset retirement obligation for the years ended December 31, 2007 and 2006 (in thousands):

	2007			2006
Liability for asset retirement obligations, beginning of year	$	10,801		$	10,192
Accretion expense		704			535
Change in estimates		(657	)		283
Obligations for wells acquired and wells drilled		17,328			—
Obligations for wells sold or retired		(531	)		(209	)
Liability for asset retirement obligations, end of year		27,645			10,801
Less: current asset retirement obligation		1,904			—
Long-term asset retirement obligations	$	25,741		$	10,801

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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 basis differences reverse.

18. Uncertain Tax Positions

Effective January 1, 2007, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (“FIN 48”). The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.

The cumulative effect of applying FIN 48 must be reported as an adjustment to the opening balance of retained earnings in the year of adoption. The net impact of the cumulative effect of adopting FIN 48 on January 1, 2007, was a $1.3 million decrease to retained earnings, with a corresponding increase to accrued interest related to uncertain tax positions.

	Year Ended December 31, 2007
Uncertain Tax Positions:
Balance as of December 31, 2006	$	9,633
Liability established at adoption of FIN 48		1,300
Additions for tax positions of prior periods		507
Decreases in tax positions in prior period		—
Settlements		—
Additions based on tax positions related to the current year		—
Lapse of statutes of limitations		(4,585	)
Balance as of December 31, 2007	$	6,855

As a result of the pending tax audit settlements and the expiration of the applicable statute of limitations period, the Company currently estimates that the amount of unrecognized tax benefit could be reduced by up to $6.9 million during the next twelve months, which would decrease income tax expense for the relevant period. While the Company believes that it has adequately accrued for possible audit adjustments, the final resolution of the examinations cannot be determined at this time and could result in final settlements that differ from current estimates.

Related to the uncertain tax benefits noted above, the Company had recognized $1.3 million in accrued interest at the date of implementation of FIN 48. The amount of interest related to unrecognized tax benefits which was decreased due to expirations of applicable statutes of limitations was $870,000 during the course of the year. Additional interest in the amount of $507,000 accrued on the remaining balance in the year ended December 31, 2007. The Company recognizes related interest and penalties as a component of income tax expense.

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Tax years open for audit by federal and state tax authorities as of the date of adoption are the years ended December 31, 2004, 2005, and 2006. Tax years ending prior to 2004 are open for audit to the extent that net operating losses generated in those years are being carried forward or utilized in an open year. The Company is currently under audit by a federal taxing authority for the 2005 tax year.

19. New Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board issued SFAS No. 157 “Fair Value Measurements” (“SFAS 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 157 is effective for financial statements issued for fiscal years beginning on or after November 15, 2007. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements, however, it does not require any new fair value measurements. In some instances, the application of SFAS 157 will change current accounting practices. The Company is currently evaluating the impact of adopting SFAS 157.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The fair value option established by the Statement permits all entities to choose to measure eligible items at fair value at specified election dates. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact of adopting SFAS 159.

In December 2007, the FASB issued SFAS No. 141 (Revised), “Business Combinations” (“SFAS 141(R)”), which significantly changes the financial accounting and reporting of business combination transactions. SFAS 141(R) establishes principles and requirements for how an acquirer in a business combination: (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The adoption of this pronouncement may have an impact on the accounting for any acquisition the Company may make after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS 160”). This statement amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We do not expect the adoption of this pronouncement to have an impact on our financial position or results of operations.

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B –  SIGNIFICANT ACQUISITIONS

1. Ascent Energy Inc.

On November 29, 2007, RAM completed the acquisition of Ascent Energy Inc (“Ascent”), a company engaged in exploration and development of oil and natural gas properties, and the production of oil and natural gas. RAM’s investment in the Ascent acquisition was valued at $303.8 million, and included 18,783,344 shares of RAM common stock and warrants to purchase 6,200,000 shares of RAM common stock at an exercise price of $5.00 per share, exercisable at any time on or prior to May 11, 2008. Sales proceeds of $20.0 million were placed in escrow as a source of funds to adjust for Ascent’s closing date working capital and to indemnify RAM against, among other things, breaches of covenants, representations and warranties by Ascent. Through this transaction, RAM acquired properties and assets located in Texas, Oklahoma, Louisiana and the Appalachian region. RAM financed $187.0 million of the consideration paid in connection with the acquisition through borrowings under its new credit facility with Guggenheim Corporate Funding, LLC, for itself and as agent on behalf of a group of lenders.

The acquisition was accounted for using the purchase method in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations” (“SFAS 141”). The purchase allocation of the Ascent acquisition is subject to future adjustments pending settlement of the escrowed proceeds. The calculation of the acquisition cost and the preliminary allocation to assets and liabilities is as follows (in thousands):

Cash	$	201,708
Direct acquisition costs		1,340
Fair value of shares of RAM common stock		97,016
Fair value of shares of RAM warrants		4,049
Net receivable due from escrow		(271	)
Total Acquisition Cost	$	303,842

Fair Value of Assets and Liabilities Acquired:
Current assets	$	12,678
Oil and natural gas properties and equipment, using full cost accounting		347,442
Unevaluated oil and gas properties		26,254
Other property and equipment		1,466
Other assets		1,339
Current liabilities		(17,351	)
Long-term asset retirement obligations		(13,847	)
Deferred tax liability		(54,139	)
Total Purchase Price	$	303,842

Operating results for Ascent have been included in the consolidated statements of operations since the date of acquisition. The following unaudited pro forma results of operations assume that the Ascent merger occurred on January 1, 2006. The unaudited pro forma consolidated financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined (in thousands, except per share amounts):

	Year ended December 31, 2007			Year ended December 31, 2006
	(unaudited)
Revenue	$	116,216		$	143,957
Net loss	$	(17,396	)	$	(15,560	)
Basic and diluted loss per share	$	(0.31	)	$	(0.31	)

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2. Layton acquisition.

On May 15, 2007 the Company purchased a 100% working interest in certain oil and natural gas properties in the Permian Basin area of Southeast New Mexico and West Texas on which there are 120 wells. The aggregate purchase price for these properties was $18.7 million.

C – LONG-TERM DEBT

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

	2007		2006
11.5% Senior Notes due 2008, net of discount	$	28,393	$	28,351
Credit facility		306,357		103,000
Installment loan agreements		997		886
		335,747		132,237
Less amount due within one year		29,231		756
	$	306,516	$	131,481

The amount of required principal payments for the next five years and thereafter, as of December 31, 2007, is as follows (in thousands): 2008 - $29,231; 2009 - $106; 2010 - $53, 2011 - $106,357, and 2012 - $200,000.

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 $28.4 million remained outstanding at December 31, 2007 and 2006. 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.

At December 31, 2007 and 2006, the unamortized original issue discount associated with the Notes totaled approximately $3,000 and $45,000, respectively. These notes were retired at maturity on February 15, 2008 using proceeds from the Company’s revolving credit facility.

2. Revolving Credit Facility

New Credit Facility. In November 2007, in conjunction with the Ascent acquisition, we entered into a new $500.0 million credit facility with Guggenheim Corporate Funding, LLC, for itself and on behalf other institutional lenders. The new facility, which replaced our previous $300.0 million facility, includes a $175.0 million revolving credit facility and a $200.0 million term loan facility. The entire amount of the $200.0 million term loan was advanced at closing. The borrowing base under the revolving credit facility at the closing was $175.0 million, a portion of which was advanced at the closing of the Ascent acquisition. Borrowings under the new facility were used to refinance RAM Energy’s existing indebtedness, fund the cash requirements in connection with the closing of the Ascent acquisition, and for working capital and other general corporate purposes. Funds advanced under the revolving credit facility may be paid down and re-borrowed during the four-year term of the revolver, and will bear interest at LIBOR plus a margin ranging from 1.25% to 2.0% based on a

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percentage of usage. The term loan provides for payments of interest only during its five-year term, with the interest rate being LIBOR plus 7.5%.

Advances under the new facility are secured by liens on substantially all properties and assets of the Company and its subsidiaries, including Ascent and its subsidiaries. The loan agreement contains representations, warranties and covenants customary in transactions of this nature, including financial covenants relating to current ratio, minimum interest coverage ratio, maximum leverage ratio and a required ratio of asset value to total indebtedness. We will be required to maintain commodity hedges with respect to not less than 50%, but not more than 85%, of our projected monthly production volumes on a rolling 30-month basis, until the leverage ratio is less than or equal to 2.0 to 1.0. At December 31, 2007, approximately $28.4 million of availability under the revolving credit facility was reserved for payment of RAM Energy’s outstanding 11½% senior notes, which became due and payable on February 15, 2008, and $25.0 million was allocated for development of our proved undeveloped properties. At December 31, 2007, $106.4 million was outstanding under the revolving credit facility and $200.0 million was outstanding under the term facility.

D –  SUBSIDIARY GUARANTORS

RAM Energy Resources, Inc., Ascent Energy Inc. and Ascent Energy Inc.’s wholly owned subsidiaries are not party to, or guarantors of obligations under, RAM Energy, Inc.’s outstanding 11.5% Senior Notes due 2008. RAM Energy, Inc.’s Senior Notes are fully and unconditionally 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”), and its wholly owned subsidiaries at December 31, 2007 and 2006 (in thousands):

	Parent			Ascent Energy Inc.		RAM Energy, Inc.			Subsidiary Guarantors		Consolidating Adjustments			Total Consolidated Amounts
December 31, 2007
Current assets	$	4,738		$	197,383	$	2,953		$	46,419	$	(220,003	)	$	31,490
Property and equipment, net		642			374,685		35,795			130,501		—			541,623
Investment in subsidiaries		271,762			—		54,186			—		(325,948	)		—
Other assets		5,330			988		662			149		—			7,129
Total assets	$	282,472		$	573,056	$	93,596		$	177,069	$	(545,951	)	$	580,242
Current liabilities	$	189,337		$	15,173	$	74,888		$	6,530	$	(220,003	)	$	65,925
Long-term debt		—			187,357		36,621			82,538		—			306,516
Other non-current liabilities		—			13,959		6,899			10,339		—			31,197
Deferred income taxes and other non-current income taxes		(6,444	)		53,606		7,268			23,476		—			77,906
Total liabilities		182,893			270,095		125,676			122,883		(220,003	)		481,544
Stockholders’ equity (deficit)		99,579			302,961		(32,080	)		54,186		(325,948	)		98,698
Total liabilities and stockholders’ equity (deficit)	$	282,472		$	573,056	$	93,596		$	177,069	$	(545,951	)	$	580,242

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	Parent			RAM Energy, Inc.			Subsidiary Guarantors		Consolidating Adjustments			Total Consolidated Amounts
December 31, 2006
Current assets	$	1,464		$	3,044		$	34,113	$	(22,909	)	$	15,712
Property and equipment, net		4			13,780			129,021		—			142,805
Investment in subsidiaries		(30,723	)		42,684			—		(11,961	)		—
Other assets		1			3,069			138		—			3,208
Total assets	$	(29,254	)	$	62,577		$	163,272	$	(34,870	)	$	161,725
Current liabilities	$	1,191		$	30,379		$	9,519	$	(22,909	)	$	18,180
Long-term debt		—			48,945			82,536		—			131,481
Other non-current liabilities		—			3,339			9,943		—			13,282
Deferred income taxes and other non-current income taxes		(2,550	)		10,637			18,590		—			26,677
Total liabilities		(1,359	)		93,300			120,588		(22,909	)		189,620
Stockholders’ equity (deficit)		(27,895	)		(30,723	)		42,684		(11,961	)		(27,895	)
Total liabilities and stockholders’ equity (deficit)	$	(29,254	)	$	62,577		$	163,272	$	(34,870	)	$	161,725

The following represents the condensed consolidating statements of operations and statements of cash flows for RAM Energy Resources, Inc. and its subsidiaries for the years ended December 31, 2007, 2006 and 2005 (in thousands):

	Parent			Ascent Energy Inc.			RAM Energy, Inc.			Subsidiary Guarantors			Consolidating Adjustments			Total Consolidated Amounts
Year ended December 31, 2007
Operating revenues	$	17		$	5,855		$	1,180		$	62,588		$	—		$	69,640
Operating expenses		5,969			5,188			9,977			37,841			—			58,975
Operating income (loss)		(5,952	)		667			(8,797	)		24,747			—			10,665
Other expense		(2,325	)		(2,072	)		(41	)		(8,360	)		(6,969	)		(19,767	)
Income (loss) before income taxes		(8,277	)		(1,405	)		(8,838	)		16,387			(6,969	)		(9,102	)
Income taxes		(7,908	)		(524	)		(4,306	)		4,886			—			(7,852	)
Net income (loss)	$	(369	)	$	(881	)	$	(4,532	)	$	11,501		$	(6,969	)	$	(1,250	)
Cash flows provided by (used in) operating activities	$	181,141		$	(185,642	)	$	9,315		$	12,228		$	—		$	17,042
Cash flows provided by (used in) investing activities		(203,429	)		1,016			(25,623	)		(13,156	)		—			(241,192	)
Cash flows provided by financing activities		20,978			187,357			15,965			2			—			224,302
Increase (decrease) in cash and cash equivalents		(1,310	)		2,731			(343	)		(926	)		—			152
Cash and cash equivalents, beginning of year		1,347			—			749			4,625			—			6,721
Cash and cash equivalents, end of year	$	37		$	2,731		$	406		$	3,699		$	—		$	6,873

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	Parent			RAM Energy, Inc.			Subsidiary Guarantors			Consolidating Adjustments			Total Consolidated Amounts
Year ended December 31, 2006
Operating revenues	$	(7	)	$	9,327		$	60,924		$	—		$	70,244
Operating expenses		4,448			6,010			36,532			—			46,990
Operating income (loss)		(4,455	)		3,317			24,392			—			23,254
Other expense		6,919			3,599			(8,702	)		(18,557	)		(16,741	)
Income (loss) before income taxes		2,464			6,916			15,690			(18,557	)		6,513
Income taxes		(2,584	)		61			3,988			—			1,465
Net income (loss)	$	5,048		$	6,855		$	11,702		$	(18,557	)	$	5,048
Cash flows provided by (used in) operating activities	$	(268	)	$	1,938		$	27,990		$	—		$	29,660
Cash flows (used in) investing activities		(389	)		(2,116	)		(22,812	)		—			(25,317	)
Cash flows provided by financing activities		2,004			310			(6	)		—			2,308
Increase in cash and cash equivalents		1,347			132			5,172			—			6,651
Cash and cash equivalents, beginning of year		—			617			(547	)		—			70
Cash and cash equivalents, end of year	$	1,347		$	749		$	4,625		$	—		$	6,721

	Parent		RAM Energy, Inc.			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 operating activities	$	—	$	9,592		$	8,767		$	—		$	18,359
Cash flows (used in) investing activities		—		(3,108	)		(9,446	)		—			(12,554	)
Cash flows (used in) by financing activities		—		(6,910	)		—			—			(6,910	)
(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

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

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E –  LEASES

The Company leases office space and certain equipment under non-cancelable operating lease agreements that expire on various dates through 2013. Approximate future minimum lease payments for operating leases at December 31, 2007 are as follows (in thousands):

Year Ending December 31,
2008	$	944
2009		736
2010		730
2011		712
2012		735
2013 and thereafter		582
	$	4,439

Rent expense of approximately $492,000, $389,000, and $519,000 was incurred under operating leases in the years ended December 31, 2007, 2006, and 2005, respectively.

F – 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 provided matching contributions to the plan in 2007, 2006, and 2005 of $338,000, $691,000, and $210,000, respectively.

G – CAPITAL STOCK

RAM Energy, Inc. paid cash dividends of $500,000 for the year ended December 31, 2006 prior to being acquired by the Company. RAM Energy, Inc. also declared cash dividends of $1,400,000 for the year ended December 31, 2005.

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

The Company has outstanding warrants to purchase 12,648,800 shares of its common stock at any time or from time to time on or prior to May 11, 2008 at an exercise price of $5.00 per share, which warrants were issued in connection with the Company’s initial public offering. The Company also has outstanding an option to purchase up to 275,000 units, each unit consisting of one share of the Company’s common stock and two warrants, each to purchase one share of the Company’s common stock. This option is currently exercisable at $9.90 per unit and expires May 12, 2009. The warrants included in this option, when issued, will be immediately exercisable at an exercise price of $6.25. However, the warrants will cease to be exercisable after May 11, 2008.

Also, on May 8, 2006, the shareholders of the Company approved the Company’s 2006 Long-Term Incentive Plan (the “Plan”), effective upon the consummation of the Company’s acquisition by merger of RAM Energy. At the request of certain of the grantees upon vesting in shares awarded by the Plan, on June 8, 2006, the

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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. Also, at the request of certain of the grantees upon vesting in shares awarded by the Plan, on November 10, 2007, the Company repurchased 33,616 of these shares at $5.28 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. These repurchased shares are held by the Company as treasury stock at December 31, 2007.

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 December 31, 2007.

On February 13, 2007, the Company completed a public offering in which it issued 7,500,000 shares of its common stock, priced at $4.00 per share. Net proceeds of the offering were $27.4 million and were used to provide additional working capital for general corporate purposes, including acquisition, development, exploitation and exploration of oil and natural gas properties, and reduction of indebtedness.

On November 29, 2007, the Company acquired Ascent Energy Inc. in exchange for the issuance of 18,783,344 shares of common stock, warrants to purchase 6,200,000 shares of common stock at an exercise price of $5.00 per share, exercisable on or prior to May 11, 2008, and $202.8 million in cash, including direct acquisition costs. Ascent Energy Inc. is now a wholly-owned subsidiary of the Company.

H – INCOME TAXES

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

	Year Ended December 31,
	2007			2006			2005
Current	$	(1,313	)	$	(154	)	$	393
Deferred		9,165			(1,311	)		(1,199	)
Provision for income tax expense	$	7,852		$	(1,465	)	$	(806	)

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.

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

	Year Ended December 31,
	2007			2006			2005
Income tax provision at the federal statutory rate (34%)	$	3,039		$	(2,214	)	$	(459	)
State income (tax) benefit, net of federal benefit		732			781			12
Meals and entertainment expense		(18	)		(21	)		(34	)
Non-deductible dues		(13	)		(17	)		(15	)
Non-deductible related party expenses		—			—			(302	)
Previously unrecognized tax benefits		3,715			—			—
Interest on previously unrecognized tax benefits		363
Other		34			6			(8	)
Income tax provision	$	7,852		$	(1,465	)	$	(806	)

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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.

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

	December 31,
	2007			2006
Deferred tax assets:
Current:
Derivative liabilities	$	3,483		$	—
Accrued expenses and other		1,752			490
	$	5,235		$	490
Valuation allowance		—			—
Net current deferred tax assets	$	5,235		$	490
Noncurrent deferred tax assets:
Net operating loss carryforward	$	51,694		$	3,373
Accrued liabilities and other		6,378			263
	$	58,072		$	3,636
Valuation allowance		(19,409	)		—
Net noncurrent deferred tax assets	$	38,663		$	3,636
Deferred tax liabilities:
Current:
Prepaid expenses and other	$	(134	)	$	(2,172	)
		(134	)		(2,172	)
Noncurrent:
Depreciable/depletable property, plant and equipment	$	(110,979	)	$	(18,998	)
Other		(50	)		—
Total noncurrent deferred tax liabilities	$	(111,029	)	$	(18,998	)
Net noncurrent deferred tax liability	$	(111,163	)	$	(21,170	)
Net deferred tax liability	$	(67,265	)	$	(17,044	)

As of December 31, 2007, the Company has federal net operating loss carryforwards of approximately $139.6 million for tax purposes, $138.2 million of which were an inherited attribute from the Ascent acquisition during 2007. These net operating loss carryforwards are subject to the ownership change limitation provisions of Section 382 of the Internal Revenue Code. Based on the value of Ascent at the time of the acquisition, and the annual limitation on utilization of losses imposed by Section 382, it is estimated that approximately $55.3 million of these net operating losses will expire without being utilized. Accordingly, a valuation allowance has been established with respect to the portion of the net operating losses for which the Company believes it is not likely to realize a benefit. If not used, the remaining net operating losses will generally expire between 2020 and 2026. 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 disclosed in the financial statements as the Company does not believe that these net operating losses are material to the amounts presented herein.

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I – COMMITMENTS AND CONTINGENCIES

Contingent Receivables. Ascent Energy Inc., a wholly owned subsidiary of the Company, engaged a consulting firm to audit a gas processing plant utilized in South Texas. Based on the audit findings, the Company believes the gas processing plant used incorrect volumes to calculate natural gas liquids and therefore, may owe the Company additional revenues. However, the Company believes that any revenue due to it may be partially offset by a reciprocal adjustment to residue gas. The Company, at this time, is unable to estimate the net adjustment resulting from the audit findings and accordingly, has not reflected the adjustment in the financial statements. Upon finalization of the audit findings, any adjustment related to the audit findings will be recorded in the Company’s financial statements.

Contingent Liabilities. 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 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. In conjunction with our May 8, 2006 acquisition of RAM Energy, the former stockholders of RAM Energy deposited in escrow 3,200,000 shares of our common stock to secure their potential indemnity obligations to us, including any loss we might sustain in the Sacket litigation. These escrowed shares will remain in escrow until the Sacket litigation is resolved.

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.

J – DERIVATIVE CONTRACTS

During 2007, 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 statements of operations.

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The Company’s open derivative positions at December 31, 2007 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
2008	1,500	$	65.33	1,500	$	83.39	4,000	$	6.77	4,000	$	13.23
2009	1,248	$	58.42	1,248	$	79.03	4,000	$	7.00	4,000	$	10.98
2010	500	$	60.00	500	$	80.00	—		—	—		—
	Secondary Floors
Year	Per Day	Price
2009	800	$	75.00
	Bare Floors
Year	Per Day	Price
2008	1,800	$	71.15
2009	1,000	$	65.00

Crude oil floors and ceilings and natural gas floors and ceilings for 2008 cover the calendar year. Crude oil bare floors for 2008 cover the calendar year. Crude oil floors and ceilings for 2009 cover the calendar year, and natural gas floors and ceilings for 2009 cover January through September. Crude oil secondary floors for 2009 cover January through March. Crude oil bare floors for 2009 cover January through June. Crude oil floors and ceilings for 2010 cover January through March.

The Company determined the fair value of its derivatives at December 31, 2007, 2006 and 2005, based on quoted market prices, less discounts to recognize present values for contracts in excess of one year. Accordingly, a liability of $8,375,000, an asset of $677,000, and a liability of $3,510,000 were recorded in the consolidated balance sheets at December 31, 2007, 2006 and 2005, respectively.

K – LIQUIDITY

As of December 31, 2007, the Company has an accumulated deficit of $29.0 million and a working capital deficit of $34.4 million. The working capital deficit includes a current liability of $28.4 million for RAM Energy Senior Notes that matured and were retired in February 2008 using proceeds from borrowings under the Company’s credit facility. Management believes that borrowings currently available to the Company under the Company's credit facilities ($68 million available at December 31, 2007), 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.

L – RELATED PARTY TRANSACTIONS

Prior to being acquired by the Company, RAM Energy, Inc. paid rent expense of approximately $29,000, relating to a condominium for one of the shareholders of RAM Energy, Inc. for the year ended December 31, 2005.

Also, prior to being acquired by the Company, for the years ended December 31, 2006 and 2005 approximately $104,000 and $499,000 respectively, of expenses (excluding the rent payments discussed above) for the shareholders of RAM Energy, Inc. are included in general and administrative expenses in the consolidated statements of operations, some of which may be personal in nature.

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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 by certain stockholders 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.

M – 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, 2007, 2006 and 2005, $38,000, $150,000 and $150,000, respectively, has been recorded as compensation expense in the consolidated statements of operations.

N – SHARE-BASED COMPENSATION

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123R, “Share-Based Payments” (“SFAS No. 123R”). 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 effective January 1, 2006.

On May 8, 2006, the Company’s stockholders approved its 2006 Long-Term Incentive Plan (the “Plan”). The Company reserved a maximum of 2,400,000 shares of its common stock for issuances under the Plan. The Company believes that the awards made under the Plan will better align the interests of its employees with those of its stockholders. The Plan includes a provision that, at the request of a grantee, the Company may repurchase shares to satisfy the grantee’s federal and state income tax withholding requirements. All repurchased shares will be held by the Company as treasury stock. As of December 31, 2007, a maximum of 1,122,933 shares of common stock remained reserved for issuance under the Plan.

The Company granted incentive stock awards under the Plan as set forth in the following table. Each grant vests in equal increments over periods ranging from eight months to five years from the date of grant. The incentive stock awards granted on May 8, 2006 vested in full on June 8, 2006. At the request of certain of the grantees, on June 8, 2006, the Company repurchased 98,100 of these shares included in such Awards at $6.04 per share, the closing market price of the Company’s common stock as of that date, to satisfy the requesting grantees’ federal and state income tax withholding requirements. Of the 646,805 shares granted on November 10, 2006, 125,606 shares vested on November 10, 2007. At the request of certain of the grantees, the Company repurchased 33,616 of these shares included in such Awards at $5.28 per share, the closing market price of the Company’s common stock as of that date, to satisfy the requesting grantees’ federal and state income tax withholding requirements. The repurchased shares were held by the Company as treasury stock at December 31, 2007.

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Shares Granted				Shares Repurchased
Date	Number	Closing Price		Date	Number	Closing Price
May 8, 2006	330,000	$	6.72	June 8, 2006	98,100	$	6.04
November 10, 2006	646,805	$	5.06	November 10, 2007	33,616	$	5.28
March 12, 2007	200,000	$	4.18
March 19, 2007	14,000	$	4.25
May 14, 2007	9,148	$	4.61
June 12, 2007	30,000	$	5.13
June 12, 2007	8,000	$	5.13
June 25, 2007	12,183	$	5.47
July 2, 2007	20,000	$	5.32
August 13, 2007	6,931	$	4.70

A summary of the status of the non-vested shares as of December 31, 2007, and changes during the two year period ended December 31, 2007, is presented below:

Nonvested Shares	Shares		Weighted- Average Grant-Date Fair Value
Nonvested at January 1, 2006	—		$	—
Granted	976,805		$	5.62
Vested	(330,000	)	$	6.72
Forfeited	—		$	—
Nonvested at December 31, 2006	646,805		$	5.06
Granted	300,262		$	4.46
Vested	(125,606	)	$	5.06
Forfeited	(18,775	)	$	5.06
Nonvested at December 31, 2007	802,686		$	4.28

As of December 31, 2007, the Company had $3.4 million of unrecognized compensation cost related to non-vested, share-based compensation related to awards granted under the Plan. That cost is expected to be recognized over a weighted-average period of 4 years. The related compensation expense recognized during the years ended December 31, 2007 and 2006 was $1.0 million and $2.3 million, respectively.

O –  SUBSEQUENT EVENT

On February 15, 2008, the outstanding 11  ¹/2% Senior Notes due 2008 issued by the Company’s wholly owned subsidiary, RAM Energy, Inc., matured and were paid in full. The aggregate principal amount paid was $28.4 million, plus accrued interest of $1.6 million. Long term borrowings under the Company’s revolving credit facility were used to retire these notes.

Effective January 1, 2008, the Company granted restricted stock awards of an aggregate of 841,000 shares of our common stock to our officers and other key employees, including certain former Ascent employees whose employment continued following the Ascent acquisition. All of the awards vest ratably over a four-year period. The Company will incur compensation expense of approximately $4.2 million in connection with these awards, which will be recognized ratably through 2011.

P – 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, New Mexico, and West Virginia. The Company does not own or lease any oil and natural gas properties outside the United States of America.

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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):

	2007			2006			2005
Proved oil and natural gas properties	$	573,470		$	185,284		$	160,704
Unevaluated oil and natural gas properties		26,895			—			—
Accumulated depreciation and amortization		(63,480	)		(45,203	)		(32,602	)
	$	536,885		$	140,081		$	128,102

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):

	2007			2006			2005
Acquisition of proved properties	$	299,573		$	4,476		$	155
Acquisition of unproved properties		24,642			705			—
Proceeds from sale of unproved properties		—			(3,565	)		—
Development costs		12,921			18,475			11,864
Exploration costs		7,659			2,766			1,507
Exploration in progress		—			1,723			—
Sale of producing properties		(170	)		—			(2,471	)
Additional asset retirement obligation		17,328			—			3,051
	$	361,953		$	24,580		$	14,106
Amortization rate per equivalent oil barrel	$	12.86		$	9.78		$	8.93

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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, 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
Extensions and discoveries	2,087		2,622		2
Sales of reserves in place	—		—		—
Purchases of reserves in place	126		1,928		—
Revisions of previous estimates	(1,864	)	(3,220	)	373
Production	(752	)	(2,365	)	(143	)
December 31, 2006	10,796		33,199		2,123
Extensions and discoveries	3		1,927		143
Sales of reserves in place	—		(117	)	—
Purchases of reserves in place	8,688		58,628		1,046
Revisions of previous estimates	831		2,506		1,143
Production	(774	)	(2,785	)	(184	)
December 31, 2007	19,544		93,358		4,271
Proved developed reserves:
December 31, 2005	7,337		26,752		1,396
December 31, 2006	6,954		26,888		1,671
December 31, 2007	13,552		50,990		2,565

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 spot 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.

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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):

	2007			2006			2005
Future cash inflows	$	2,722,099		$	894,626		$	1,037,337
Future production costs		(824,576	)		(356,961	)		(336,008	)
Future development costs		(146,734	)		(48,605	)		(45,271	)
Future income tax expenses		(574,169	)		(158,602	)		(219,640	)
Future net cash flows		1,176,620			330,458			436,418
10% annual discount for estimated timing of cash flows		(578,225	)		(150,717	)		(209,758	)
Standardized measure of discounted future net cash flows	$	598,395		$	179,741		$	226,660

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):

	2007			2006			2005
Standardized measure of discounted future net cash flows at beginning of year	$	179,741		$	226,660		$	161,320
Changes during the year:
Sales and transfers of oil and natural gas produced, net of production costs		(55,434	)		(46,272	)		(46,823	)
Net changes in prices and production costs		181,475			(97,697	)		133,301
Extensions and discoveries, less related costs		11,444			30,560			2,311
Development costs incurred and revisions		976			(3,333	)		(8,777	)
Sales of reserves in place		—			—			(2,551	)
Purchases of reserves in place		435,261			4,476			—
Revisions of previous quantity estimates		41,042			2,107			8,219
Net change in income taxes		(223,002	)		28,690			(43,960	)
Accretion of discount		26,892			34,550			23,620
Net change		418,654			(46,919	)		65,340
Standardized measure of discounted future net cash flows at end of year	$	598,395		$	179,741		$	226,660

Prices used in computing these calculations of future cash flows from estimated future production of proved reserves were $93.90, $58.74, and $58.63 per barrel of oil at December 31, 2007, 2006, and 2005, respectively, $7.00, $5.51, and $9.14 per thousand cubic feet of natural gas at December 31, 2007, 2006, and 2005, respectively and $54.69, $36.51 and $35.89 per barrel of natural gas liquids at December 31, 2007, 2006, and 2005, respectively.

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Q –  QUARTERLY DATA (UNAUDITED)

	2007 - Quarter Ended
	December 31,			September 30,			June 30,			March 31,
	(In thousands except per share data)
Net revenue	$	19,167		$	18,435		$	17,775		$	14,263
Net operating expenses		21,194			13,559			12,781			11,441
Operating income (loss)		(2,027	)		4,876			4,994			2,822
Interest expense		(8,175	)		(4,754	)		(3,990	)		(3,838	)
Interest income		170			357			313			207
Other expense		(57	)		—			—			—
Income (loss) before income taxes		(10,089	)		479			1,317			(809	)
Income tax provision (benefit)		(3,747	)		(4,291	)		415			(229	)
Net income (loss)	$	(6,342	)	$	4,770		$	902		$	(580	)
Basic net income (loss) applicable to common stockholders per common share	$	(0.13	)	$	0.12		$	0.02		$	(0.02	)
Diluted net income (loss) applicable to common stockholders per common share	$	(0.13	)	$	0.12		$	0.02		$	(0.02	)
	2006 - Quarter Ended
	December 31,			September 30,			June 30,			March 31,
	(In thousands except per share data)
Net revenue	$	15,620		$	22,187		$	13,975		$	18,462
Net operating expenses		12,255			11,084			13,230			10,421
Operating income		3,365			11,103			745			8,041
Interest expense		(3,837	)		(3,906	)		(5,778	)		(3,529	)
Interest income		71			129			82			27
Income (loss) before income taxes		(401	)		7,326			(4,951	)		4,539
Income tax provision (benefit)		(1,459	)		3,081			(1,882	)		1,725
Net income (loss)	$	1,058		$	4,245		$	(3,069	)	$	2,814
Basic net income (loss) applicable to common stockholders per common share	$	0.03		$	0.13		$	(0.10	)	$	0.11
Diluted net income (loss) applicable to common stockholders per common share	$	0.03		$	0.13		$	(0.10	)	$	0.11

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

No items to report.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Disclosure Controls and Procedures. We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the U.S. Securities and Exchange Commission (“SEC”), is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act) was performed as of the end of the period covered by the report. This evaluation was performed by our management, with the participation of our Chief Executive Officer and Chief Financial Officer. Based on this evaluation of our disclosure controls and procedures as of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective.

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Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls or our internal controls over financial reporting (“Internal Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that simple errors or mistakes can occur. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based, in part, upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our disclosure controls and internal controls and make modifications as necessary; our intent in this regard is that the disclosure controls and the internal controls will be maintained as systems change and conditions warrant.

Management’s Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. Our controls are designed to provide reasonable assurance that our assets are protected from unauthorized use and that transactions are executed in accordance with established authorizations and properly recorded. The internal controls are supported by written policies and are complemented by a staff of competent business process owners supported by competent and qualified external resources used to assist in testing the operating effectiveness of our internal control over financial reporting. Our management concluded that the design and operations of our internal controls over financial reporting at December 31, 2007 are effective and provide reasonable assurance the books and records accurately reflect the transactions of the Company.

Because of our inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control – Integrated Framework. In conducting our evaluation of the effectiveness of our internal control over financial reporting, we excluded the acquisition of Ascent Energy (“Ascent”) in November 2007 due to its size and complexity. Assets and revenues of Ascent represent approximately 67% and 8% of the total assets and total revenues, respectively, included in our consolidated financial statements as of and for the year ended December 31, 2007. Such exclusion was in accordance with Securities and Exchange Commission guidance that an assessment of a recently acquired business may be omitted in management’s report on internal controls over financial reporting, provided the acquisition took place within twelve months of management’s evaluation.

Based on our assessment, management concluded that, as of December 31, 2007, our internal control over financial reporting is effective based on those criteria, and we believe that we have no material internal control weaknesses in our financial reporting process.

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The effectiveness of our internal control over financial reporting has been audited by UHY LLP, an independent registered public accounting firm, as stated in their report which is included herein.

/S/    LARRY E. LEE	/S/    JOHN M. LONGMIRE
Larry E. Lee	John M. Longmire
Chairman, President and Chief Executive Officer	Senior Vice President and Chief Financial Officer
March 17, 2008	March 17, 2008

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RAM Energy Resources, Inc.

We have audited RAM Energy Resources, Inc. (a Delaware corporation) and subsidiaries’ internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exist, testing and evaluating the design and operating effectiveness of internal control and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, RAM Energy Resources, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO.

RAM Energy Resources, Inc. acquired Ascent Energy Inc. on November 29, 2007, and management excluded from its assessment of the effectiveness of RAM Energy Resources, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2007, Ascent Energy Inc.’s internal control over financial reporting. Assets and revenues of Ascent Energy Inc. represent approximately 67% and 8% of total assets and total revenues, respectively, included in the consolidated financial statements of RAM Energy Resources, Inc. as of and for the year ended December 31, 2007. Our audit of internal control over financial reporting of RAM Energy Resources, Inc. and subsidiaries also excluded an evaluation of the internal control over financial reporting of Ascent Energy Inc.

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We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of RAM Energy Resources, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2007, and our report dated March 17, 2008, expressed an unqualified opinion on those consolidated financial statements.

/s/ UHY LLP

Houston, Texas

March 17, 2008

Item 9B. Other Information

No items to report.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

We have adopted a code of ethics that applies to all directors, officers and employees, including our principal executive officer and principal accounting officer. A copy of our code of ethics is available on our website at www.ramenergy.com. We intend to disclose any amendments to or waivers of our code of ethics by posting the required information on our website, www.ramenergy.com, or by filing a Form 8-K within the required time periods.

The information required by this item is or will be set forth in the definitive proxy statement relating to the 2008 Annual Meeting of Stockholders of RAM Energy Resources, Inc., which is to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the “Proxy Statement”). This definitive proxy statement relates to a meeting of stockholders involving the election of directors and the portions therefrom required to be set forth in this Form 10-K by this item are incorporated herein by reference pursuant to General Instruction G(3) to Form 10-K.

Item 11. Executive Compensation

The information required by this item will be set forth in the Proxy Statement. This definitive proxy statement relates to a meeting of stockholders involving the election of directors and the portions therefrom required to be set forth in this Form 10-K by this item are incorporated herein by reference pursuant to General Instruction G(3) to Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item will be set forth in the Proxy Statement. This definitive proxy statement relates to a meeting of stockholders involving the election of directors and the portions therefrom required to be set forth in this Form 10-K by this item are incorporated herein by reference pursuant to General Instruction G(3) to Form 10-K.

Item 13. Certain Relationships and Related Transactions and Director Independence

The information required by this item will be set forth in the Proxy Statement. This definitive proxy statement relates to a meeting of stockholders involving the election of directors and the portions therefrom required to be set forth in this Form 10-K by this item are incorporated herein by reference pursuant to General Instruction G(3) to Form 10-K.

Item 14. Principal Accountant Fees and Services

The information required by this item will be set forth in the Proxy Statement. This definitive proxy statement relates to a meeting of stockholders involving the election of directors and the portions therefrom required to be set forth in this Form 10-K by this item are incorporated herein by reference pursuant to General Instruction G(3) to Form 10-K.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) (1) The following consolidated financial statements of RAM Energy Resources, Inc. are included in Item 8:

RAM Energy Resources, Inc.

Report of Independent Registered Public Accounting Firm	48
Consolidated Balance Sheets as of December 31, 2007 and 2006	49
Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005	50
Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2007, 2006 and 2005	51
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005	52
Notes to Consolidated Financial Statements	53

All other schedules have been omitted since the required information is not present, or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.

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(a) (3) Exhibits

The following exhibits are filed as a part of this report:

Exhibit	Description	Method of Filing
3.1	Amended and Restated Certificate of Incorporation of the Registrant.	(1) [3.1]
3.2	Amended and Restated Bylaws of the Registrant.	(13) [3.2]
4.1	Specimen Unit Certificate.	(1) [4.1]
4.2	Specimen Common Stock Certificate.	(1) [4.2]
4.3	Amended Specimen Warrant Certificate.	(12) [4.3]
4.4	Amended Form of Unit Purchase Option granted to EarlyBirdCapital, Inc.	(2) [4.4]
4.5	Form of Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant.	(12) [4.5]
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]
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]
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) [10.11]
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) [10.11]

82

Exhibit	Description	Method of Filing
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 10, 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]
10.6.2	Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008	(17) [10.62]
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) [10.7]
10.90	Form of Registration Rights Agreement among the Registrant and the Investors party thereto.	(3) [10.17]
10.10	Agreement between RAM and Shell Trading-US dated February 1, 2006.	(1) [10.22]
10.11	Agreement between RAM 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]
10.13.1	First Amendment to Third Amended and Restated Loan Agreement 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 WEST LB AG, New York Branch, as the Syndication Agent, dated as of August 8, 2007.	(14) [10.13.1]
10.14	Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004*	(12) [10.14]
10.15	Purchase and Sale Agreement dated May 10, 2007 between Layton Enterprises, Inc. and the Registrant (exhibits and schedules intentionally omitted).	(14) [10.15]
10.16	Agreement and Plan of Merger dated October 16, 2007 among RAM Energy Resources Corporation, Ascent Energy Inc. and Ascent Acquisition Corp.	(15) [2.1]

83

Exhibit	Description	Method of Filing
10.17	Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders	(16) [10.1]
21.1	Subsidiaries of the Registrant	**
23.1	Consent of UHY LLP	**
23.2	Consent of Forest A. Garb & Associates, Inc.	**
23.3	Consent of Williamson Petroleum Consultants, Inc.	**
31.1	Rule 13(A) – 14(A) Certification of our Principal Executive Officer	**
31.2	Rule 13(A) – 14(A) Certification of our Principal Financial Officer	**
32.1	Section 1350 Certification of our Principal Executive Officer	**
32.2	Section 1350 Certification of our Principal Financial Officer	**

 * Management contract or compensatory plan or arrangement.

 ** Filed herewith.

(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.

(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.

84

(13) filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on February 2, 2007, as the exhibit number indicated in brackets and incorporated by reference herein.

(14) Filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q filed on August 10, 2007, as the exhibit number indicated in brackets and incorporated by reference herein.

(15) Filed as an exhibit to Registrant’s Form 8-K dated October 18, 2007 as the exhibit number indicated in brackets and incorporated by reference herein.

(16) Filed as an exhibit to Registrant’s Form 8-K dated November 29, 2007 as the exhibit number indicated in brackets and incorporated by reference herein.

(17) Filed as an exhibit to Registrant’s Form 8-K dated February 26, 2008 as the exhibit number indicated in brackets and incorporated by reference herein.

85

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Tulsa, State of Oklahoma, on March 17, 2008.

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 Exchange Act of 1934, this report has been signed by the following persons in the capacities indicated, on March 17, 2008.

Signature	Title
/S/    LARRY E. LEE         Larry E. Lee	Chairman of the Board, President and Chief Executive Officer and Director (Principal Executive Officer)
/S/    JOHN M. LONGMIRE         John M. Longmire	Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
/S/    SEAN P. LANE         Sean P. Lane	Director
/S/    GERALD R. MARSHALL         Gerald R. Marshall	Director
/S/    JOHN M. REARDON         John M. Reardon	Director

86

INDEX TO EXHIBITS

Exhibit	Description	Method of Filing
3.1	Amended and Restated Certificate of Incorporation of the Registrant.	(1) [3.1]
3.2	Amended and Restated Bylaws of the Registrant.	(13) [3.2]
4.1	Specimen Unit Certificate.	(1) [4.1]
4.2	Specimen Common Stock Certificate.	(1) [4.2]
4.3	Amended Specimen Warrant Certificate.	(12) [4.3]
4.4	Amended Form of Unit Purchase Option granted to EarlyBirdCapital, Inc.	(2) [4.4]
4.5	Form of Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant.	(12) [4.5]
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]
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]
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) [10.11]
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) [10.11]

87

Exhibit	Description	Method of Filing
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 10, 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]
10.6.2	Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008	(17) [10.62]
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]
10.90	Form of Registration Rights Agreement among the Registrant and the Investors party thereto.	(3) [10.17]
10.10	Agreement between RAM and Shell Trading-US dated February 1, 2006.	(1) [10.22]
10.11	Agreement between RAM 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]
10.13.1	First Amendment to Third Amended and Restated Loan Agreement 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 WEST LB AG, New York Branch, as the Syndication Agent, dated as of August 8, 2007.	(14) [10.13.1]
10.14	Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004*	(12) [10.14]
10.15	Purchase and Sale Agreement dated May 10, 2007 between Layton Enterprises, Inc. and the Registrant (exhibits and schedules intentionally omitted).	(14) [10.15]
10.16	Agreement and Plan of Merger dated October 16, 2007 among RAM Energy Resources Corporation, Ascent Energy Inc. and Ascent Acquisition Corp.	(15) [2.1]

88

Exhibit	Description	Method of Filing
10.17	Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders	(16) [10.1]
21.1	Subsidiaries of the Registrant	**
23.1	Consent of UHY LLP	**
23.2	Consent of Forest A. Garb & Associates, Inc.	**
23.3	Consent of Williamson Petroleum Consultants, Inc.	**
31.1	Rule 13(A) – 14(A) Certification of our Principal Executive Officer	**
31.2	Rule 13(A) – 14(A) Certification of our Principal Financial Officer	**
32.1	Section 1350 Certification of our Principal Executive Officer	**
32.2	Section 1350 Certification of our Principal Financial Officer	**

 * Management contract or compensatory plan or arrangement.

 ** Filed herewith.

(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.

(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.

89

(13) filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on February 2, 2007, as the exhibit number indicated in brackets and incorporated by reference herein.

(14) Filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q filed on August 10, 2007, as the exhibit number indicated in brackets and incorporated by reference herein.

(15) Filed as an exhibit to Registrant’s Form 8-K dated October 18, 2007 as the exhibit number indicated in brackets and incorporated by reference herein.

(16) Filed as an exhibit to Registrant’s Form 8-K dated November 29, 2007 as the exhibit number indicated in brackets and incorporated by reference herein.

(17) Filed as an exhibit to Registrant’s Form 8-K dated February 26, 2008 as the exhibit number indicated in brackets and incorporated by reference herein.

90

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF RAM ENERGY RESOURCES, INC.

Name of Subsidiary	State of Organization
RAM Energy, Inc.	Delaware
RWG Energy, Inc.	Delaware
RLP Gulf States, L.L.C.	Oklahoma
Great Plains Pipeline Company	Delaware
Magic Circle Acquisition Corp.	Oklahoma
Carmen Development Corporation	Oklahoma
WG Operating, Inc.	Texas
WG Pipeline LLC	Texas
Ascent Energy Inc.	Delaware
Ascent Oil and Gas, Inc.	Delaware
Ascent Energy Holdings, Inc.	Delaware
Ascent Resources WV, Inc.	Delaware
Pontotoc Acquisition Corp.	Nevada
Dyne Exploration Company	Oklahoma
Pontotoc Production Company, Inc.	Texas
Oklahoma Basic Economy Corporation	Oklahoma
Pontotoc Holdings, Inc.	Oklahoma
Pontotoc Gathering, LLC	Oklahoma
South Louisiana Property Holdings, Inc.	Louisiana
Ascent Energy Louisiana, LLC	Delaware
Ascent GP LLC	Delaware
Ascent LP LLC	Delaware
Ascent Operating, LP	Delaware

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File No. 333-135853) and on Form S-3 (File No. 333-113583) of Ram Energy Resources, Inc. of our reports dated March 17, 2008 relating to the consolidated financial statements of Ram Energy Resources, Inc. as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and to the effectiveness of RAM Energy Resources, Inc.’s internal control over financial reporting as of December 31, 2007, which appear in the Annual Report on Form 10-K for the year ended December 31, 2007.

/s/ UHY LLP

Houston, Texas

March 17, 2008

EX-23.2

Exhibit 23.2

FORREST A. GARB & ASSOCIATES, INC.

INTERNATIONAL PETROLEUM CONSULTANTS

5310 HARVEST HILL ROAD, SUITE 275

DALLAS, TEXAS 75230-5805

(972) 788-1110 Telefax 991-3160

E-Mail: forgarb@forgarb.com

Consent of Forrest A. Garb & Associates, Inc.

We consent to the reference to our reports for RAM Energy Resources, Inc., which appears in the December 31, 2007 annual report on Form 10-K of RAM Energy Resources, Inc.

FORREST A. GARB & ASSOCIATES, INC.
By:	/S/    WILLIAM D. HARRIS III
	William D. Harris III
	CEO President

March 17, 2008

EX-23.3

Exhibit 23.3

WILLIAMSON PETROLEUM CONSULTANTS, INC.

550 WEST TEXAS AVENUE, SUITE 300

MIDLAND, TEXAS 79701-4246

PHONE: 432-685-6100

FAX: 432-685-3909

E-MAIL: WPC@WPC-INC.COM

CONSENT OF INDEPENDENT ENGINEERS.

As oil and gas consultants, Williamson Petroleum Consultants, Inc. hereby consents to the inclusion of information from our report for RAM Energy Resources, Inc. effective December 31, 2007 entitled, “Evaluation of Oil and Gas Reserves to the Interests of RAM Energy Resources, Inc. in Certain Properties Effective December 31, 2007 Proved Properties for Disclosure to the Securities and Exchange Commission and Probable Properties Utilizing Nonescalated Economics Williamson Project 7.9246” dated January 28, 2008 and data extracted therefrom (and all references to our Firm) included in or made a part of this Form 10-K Annual Report of RAM Energy Resources, Inc.

/s/ WILLIAMSON PETROLEUM CONSULTANTS, INC.

WILLIAMSON PETROLEUM CONSULTANTS, INC.

Midland, Texas

March 17, 2008

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS FOR FORM 10-K

I, Larry E. Lee, Chief Executive Officer, principal executive officer and Director, certify that:

1. I have reviewed this annual report on Form 10-K of RAM Energy Resources, Inc., referred to as the registrant;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the consolidated financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 17, 2008	RAM ENERGY RESOURCES, INC.
	By:	/S/    LARRY E. LEE
		Larry E. Lee
		Chairman, President, Chief Executive Officer and Director (principal executive officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS FOR FORM 10-K

I, John M. Longmire, Senior Vice President, Chief Financial Officer and principal financial officer, certify that:

1. I have reviewed this annual report on Form 10-K of RAM Energy Resources, Inc., referred to as the registrant;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the consolidated financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 17, 2008	RAM ENERGY RESOURCES, INC.
	By:	/S/    JOHN M. LONGMIRE
		John M. Longmire
		Senior Vice President and Chief Financial Officer (principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATE OF

PRINCIPAL EXECUTIVE OFFICER

OF

RAM ENERGY RESOURCES, INC.

I, Larry E. Lee, Chief Executive Officer, principal executive officer and Director of RAM Energy Resources, Inc., referred to as the Company, hereby certify that, to the best of my knowledge, the annual report of the Company on Form 10-K for the year ended December 31, 2007, referred to as the Report:

a. complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

b. the information contained in the report fairly presents, in all material respects, the financial condition of the Company at December 31, 2007, and the results of the Company’s operations for the year ended December 31, 2007.

March 17, 2008

/S/    LARRY E. LEE        

Larry E. Lee

Chairman, President, Chief Executive Officer and Director

(principal executive officer)

EX-32.2

Exhibit 32.2

CERTIFICATE OF

PRINCIPAL FINANCIAL OFFICER

OF

RAM ENERGY RESOURCES, INC.

I, John M. Longmire, Executive Vice President, Chief Financial Officer and principal financial officer of RAM Energy Resources, Inc., referred to as the Company, hereby certify that, to the best of my knowledge, the annual report of the Company on Form 10-K for the year ended December 31, 2007, referred to as the Report:

a. complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

b. the information contained in the report fairly presents, in all material respects, the financial condition of the Company at December 31, 2007, and the results of the Company’s operations for the year ended December 31, 2007.

March 17, 2008

/S/    JOHN M. LONGMIRE        

John M. Longmire

Senior Vice President and

Chief Financial Officer

(principal financial officer)