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, 2006

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

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer  ¨ Accelerated Filer  ¨ Non-Accelerated Filer  þ

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 30, 2007, there were outstanding 41,153,530 shares of registrant’s $.0001 par value common stock; 12,650,000 warrants, each warrant evidencing the right to purchase one share of common stock at an exercise price of $5.00 per share, and 478,727 Units, each Unit consisting of one share of common stock and two warrants, each 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 June 30, 2006, the aggregate market value of 7,700,000 shares of common stock held by non-affiliates of the registrant was approximately $44.0 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 2007 annual meeting of stockholders, which will be filed with the Securities and Exchange Commission, or SEC, no later than 120 days after December 31, 2006.

RAM ENERGY RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2006

TABLE OF CONTENTS

Item Number		Page
	PART I
1	Business	1
1A	Risk Factors	7
1B	Unresolved Staff Comments	13
2	Properties	13
3	Legal Proceedings	26
4	Submission of Matters to a Vote of Security Holders	27
	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
6	Selected Consolidated Financial Data	30
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
7A	Quantitative and Qualitative Disclosures About Market Risk	42
8	Financial Statements	44
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	71
9A	Controls and Procedures	71
9B	Other Information	71
	PART III
10	Directors, Executive Officers and Corporate Governance	72
11	Executive Compensation	72
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	72
13	Certain Relationships and Related Transactions and Director Independence	72
14	Principal Accountants Fees and Services	72
	PART IV
15	Exhibits and Financial Statement Schedules	73
	Consent of Independent Registered Public Accounting Firm
	Rule 13a-14(a) Certification by our Principal Executive Officer
	Rule 13a-14(a) Certification by our Principal Financial Officer
	Section 1350 Certification by our Principal Executive Officer
	Section 1350 Certification by our Principal Financial Officer

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., our wholly owned subsidiary. Unless the context otherwise requires, the information contained in this report to gives effect to the May 8, 2006 consummation of the merger of RAM Energy Acquisition, Inc., our wholly owned subsidiary, with and into RAM Energy, and the change of our name from Tremisis Energy Acquisition Corporation to RAM Energy Resources, Inc., which transactions are collectively called the “merger.” See “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 subsidiary, RAM Energy, Inc. and its wholly owned subsidiaries which we refer to collectively as RAM Energy. Our executive offices are at 5100 East Skelly Drive, Suite 650, Tulsa, Oklahoma 74135 (918) 663-2800. We also have an office in 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 and Oklahoma. Our producing properties are located in highly prolific basins with long histories of oil and natural gas operations. We have been active in these core areas since our inception in 1987 and have grown through a balanced strategy of acquisitions and development and exploratory drilling. We have completed over 20 acquisitions of producing oil and natural gas properties and related assets for an aggregate purchase price approximating $400 million. Through December 31, 2006, we have drilled or participated in the drilling of 561 oil and natural gas wells, 93% of which were successfully completed and produced hydrocarbons in commercial quantities. Our management team has extensive technical and operating expertise in all areas of our geographic focus.

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

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

• Boonsville, Jack and Wise Counties, Texas;

• Vinegarone, Val Verde County, Texas; and

• Egan, Acadia Parish, Louisiana.

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

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

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At December 31, 2006, our estimated net proved reserves were 18.5 MMBoe, of which approximately 59% were crude oil, 30% were natural gas, and 11% were natural gas liquids, or NGLs. The PV-10 Value of our proved reserves was approximately $269.9 million based on prices we were receiving as of December 31, 2006, which were $58.74 per Bbl of oil, $36.51 per Bbl of NGLs and $5.51 per Mcf of natural gas. At December 31, 2006, our proved developed reserves comprised 71% of our total proved reserves, and the estimated reserve life for our total proved reserves was approximately 17 years.

At December 31, 2006, we owned interests in approximately 2,900 wells and were the operator of leases upon which approximately 1,900 of these wells are located. The PV-10 Value attributable to our interests in the properties we operate represented approximately 94% of our aggregate PV-10 Value as of December 31, 2006. 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, 2006, our reserve replacement percentage, through discoveries, extensions, revisions and acquisitions, but excluding divestitures, was 355%. 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, 2006, we drilled or participated in the drilling of 92 wells on our oil and natural gas properties, 80 of which were successfully completed as producing wells, four of which were dry holes and eight of which were either drilling or waiting to be completed at the end of that period. For the twelve months ended December 31, 2006 we generated EBITDA of $33.4 million from production averaging 3,533 Boe per day. For more information regarding our EBITDA, including a reconciliation to our net income (loss), see Item 6. “Selected Consolidated Financial Data.”

Our Business Strategy and Strengths

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

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

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

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

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

Ÿ Develop and Exploit Existing Oil and Natural Gas Properties. We have historically increased stockholder value by fully developing or exploiting our acquired and discovered properties until we determine that it is no longer economically attractive to do so. As of December 31, 2006, we have identified 228 proved development and extension drilling projects and 166 recompletion/workover projects on our existing properties and wells.

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

We believe that the following strengths complement our business strategy:

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

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

Ÿ Balanced Oil and Natural Gas Production. At year-end 2006, approximately 59% of our estimated proved reserves were oil, 30% 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 91% of our aggregate PV-10 Value at December 31, 2006. Our high degree of operating control allows us to control capital allocation and expenses and the timing of additional development and exploitation of our producing properties.

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

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

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

Ÿ Insider Ownership. At March 27, 2007 our directors, executive officers and our two principal stockholders beneficially owned approximately 60% of our outstanding shares of common stock, providing a strong alignment of interest between management, the board of directors and our outside stockholders.

Ÿ Balance Sheet Flexibility. We have significant liquidity for pursuing acquisitions, accelerating our development and exploratory activities and taking advantage of opportunities as they arise.

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.

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MMBoe. One million Boe.

Mcf. One thousand cubic feet of natural gas.

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

MMBtu. One million Btus.

MMcf. One million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

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

PV-10 Value. When used with respect to oil and natural gas reserves, the estimated future gross revenues to be generated from the production of proved reserves, net of estimated production and future development costs, using the prices provided in this 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.

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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.

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.

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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.

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

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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 projects or other replacement activities will result in significant additional reserves or that we will succeed in drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

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

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

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

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

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

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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 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 prospectus.

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

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

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

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

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

As part of our business strategy, we continually seek acquisitions of oil and natural gas properties. 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 the merger, RAM Energy regularly paid cash dividends to its stockholders. We intend to retain any future earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future.

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

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

On November 10, 2006, we approved the grant of restricted stock awards under our 2006 Long-Term Incentive Plan for an aggregate of 646,805 shares of our common stock to 22 of our employees, including two of our vice presidents, one of whom received an award of 75,100 shares, and the other who received an award of 69,170 shares. We will incur compensation expense of approximately $3.3 million, which will be recognized ratably through 2011, in connection with our November 10, 2006 restricted stock issuances. For the year ended December 31, 2006, we recognized $91,000 share-based compensation expense with respect to these grants.

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 60% of our outstanding common stock are parties to a voting agreement. These persons have agreed to vote for each other’s designees to our board of directors through director elections in 2008. Accordingly, they will be able to control the election of directors and, therefore, our policies and direction during the term of the voting agreement. This concentration of voting power could have the effect of delaying or preventing a change in our control or discouraging a potential acquirer from attempting to obtain control of us, which in turn could have a material adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the market price for their shares of common stock.

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

We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders and purchasers of common stock offered hereby. We 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 determined by our board of directors. As of the date of this report, we had outstanding 41,153,530 shares of common stock, warrants to purchase 12,650,000 shares of our common stock and an agreement to issue 825,000 shares of our common stock upon the exercise of currently exercisable options to purchase 275,000 units, each unit consisting of one share of common stock and two warrants, each warrant to purchase one share of our common stock. These warrants, when issued, will be immediately exercisable. In addition, we have reserved an additional 1,209,195 shares for future issuance to employees as restricted stock or stock option awards pursuant to our 2006 Long-Term Incentive Plan. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future issuances of our securities for capital raising purposes or for other business purposes. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.

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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.

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

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

We are authorized to issue up to one million shares of preferred stock, which shares may be issued from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions thereof, if any, of each such series of our preferred stock may differ

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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, 2006, 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, 2006, we owned interests in approximately 1,600 wells in the Electra/Burkburnett Area, of which 536 were active producing wells and 210 were active injection wells.

We drilled more than 152 wells in the Electra/Burkburnett Area from November 1, 2004 through December 31, 2006, and, as of December 31, 2006, 200 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, 2006, we drilled 79 net wells in the Electra/Burkburnett Area, of which 75 were completed as producing wells and four were in various stages of completion at the end of the year. We own a 100% working interest in and operate all 79 of the wells. The initial net daily production from wells drilled and completed during the year ended December 31, 2006 averaged 26 Bbls of oil. The average cost incurred by us to drill, complete and equip a producing well in our Electra/Burkburnett Area during the year ended December 31, 2006 was $128,000.

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 760 Mcf per day of casinghead gas produced from our properties in the area. The gas is processed

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in a 1,400 Mcf per day capacity refrigeration unit where approximately 163 Bbls of NGLs per day, net to our interest, are extracted and sold. Approximately 250 Mcf per day of residue gas is used for compressor fuel at the plant, 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.

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

On April 1, 2005, we purchased a drilling rig specifically for the purpose of facilitating our ongoing drilling program in the Electra/Burkburnett Area and have been using this rig and our own crew and equipment to drill from six to eight wells per month in the field. We also use our own personnel and equipment to perform routine maintenance on our properties and typically do not require third party vendor services. We own our own pulling units, earthmoving equipment, tank trucks and other field equipment to ensure availability and facilitate operations in the field. We employ approximately 65 field employees dedicated to our Electra/Burkburnett operations, all of which work out of our field office in the town of Electra.

We sell the crude oil produced from our Electra/Burkburnett area properties to Shell Trading (US) Company at the STUSCO WTI posted price, plus a premium which was $1.50 until December 31, 2006 and is now $1.30.

During the year ended December 31, 2006, the aggregate net production attributable to our interest in the Electra/Burkburnett properties was 641,308 Bbls of oil and 48,834 Bbls of NGLs, or 690,142 Boe, and the average daily production for the period was 1,757 Bbls of oil and 134 Bbls of NGLs, or 1,891 Boe per day.

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

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

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

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

During the year ended December 31, 2006, the aggregate net production attributable to our interest in the Egan Field properties was 16,166 Bbls of oil and 387 MMcf of natural gas, or 80,674 Boe, and average daily production for the period was 44 Bbls of oil and 1,060 Mcf of natural gas, or 221 Boe per day.

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

Our properties in Jack and Wise Counties are comprised of two discrete subsets: the shallow gas zones and the Barnett Shale acreage. Because a considerable portion of our leasehold in the area is segregated with respect

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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 88 wells producing from these shallow gas zones and operate all but one of such wells.

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

During the year ended December 31, 2006, the aggregate net production attributable to our working interests in the Boonsville shallow gas properties (above the Marble Falls) was 16,543 Bbls of oil, 420 MMcf of natural gas and 84,971 Bbls of NGLs, or 171,546 Boe, and average daily production for the period was 45 Bbls of oil, 1,151 Mcf of natural gas and 233 Bbls of NGLs, or 470 Boe per day.

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

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

The core area of the play is in Denton, Wise and Tarrant Counties, lying just to the east-southeast of our acreage in Jack and Wise Counties. The most productive wells in the Barnett Shale play are wells that have been drilled horizontally. The average cost of drilling and completing a horizontal well to the Barnett Shale is approximately $2.9 million.

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

• 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

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earn under the agreement will terminate, and Devon’s interests in undrilled acreage will revert to us. Through December 31, 2006, six horizontal wells have been drilled under the agreement and completed as commercially productive in the Barnett Shale. In January 2007, Devon proposed its next well and we elected to participate in that well.

• 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, 2006, EOG has drilled one well on our Barnett Shale acreage, which was completed as a commercially productive well. We proposed one well in January, one well in February and one well in March 2007. EOG timely elected to participate in the first two wells proposed by us, but has not yet given us notice of whether it will participate in the third well.

During the year ended December 31, 2006, the aggregate net production attributable to our interest in the currently producing Barnett Shale wells was 5,393 Bbls of oil, 402 MMcf of natural gas, and 6,886 Bbls of NGLs, or 79,327 Boe. The average daily production for the period was 15 Bbls of oil and 1,102 Mcf of natural gas, and 19 Bbls of NGLs, or 217 Boe per day.

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

We continue to acquire and interpret seismic data covering a portion of our Barnett Shale acreage. Currently, we own 35 square miles of 3-D seismic data and expect to acquire an additional 60 square miles of 3-D seismic data during 2007. At December 31, 2006, we owned an interest in nine (gross) Barnett Shale producing wells, two of which are operated by us, six of which are operated by Devon Energy and one of which is operated by EOG.

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

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

During the year ended December 31, 2006, we participated in the drilling of three wells in the Vinegarone Field, two of which were unproductive and one of which was successfully completed as a commercial well. We have identified three proved undeveloped locations in the field and expect to continue our development of the field over the next two years.

During the year ended December 31, 2006, the aggregate net production attributable to our interest in the Vinegarone Field properties was 312 MMcf of natural gas, and the average daily production for the period was 856 Mcf of natural gas, or 143 Boe per day.

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Other Properties

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

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

In Texas, in addition to the Electra/Burkburnett and Boonsville Area properties, we own miscellaneous operated and non-operated interests in 576 producing wells across the state, from the Panhandle down through the Permian Basin to South Texas, and eastward to Louisiana. We also own leasehold interests in approximately 84,000 gross (6,600 net) acres in an exploratory project located in southwest Texas principally targeting the Barnett and Woodford Shales and approximately 15,000 gross and net acres (including options) in another southwest Texas exploration project targeting the Wolfcamp formation.

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

On our southwest Texas Wolfcamp project, we drilled two 100%-owned wells during the fourth quarter of 2006. We are in the completion process for these wells but we are unable to predict at this time whether such completion operations will result in commercially productive wells.

We also participated in two gross (0.2 net) exploratory wells in the Arkoma Basin during 2006, both of which were successfully completed with initial production rates in excess of 1,500 Mcf per day.

Ownership and Control of Service and Other Supply Assets

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

Development, Exploitation and Exploration Programs

Development and Exploitation Program. Our future production and performance depends to a large extent on the successful development of our existing reserves of oil and natural gas. We have identified multiple development projects on our existing properties (substantially all of which are located in our core areas), and these projects involve both the drilling of development wells (including 455 injection wells) and extension wells. We are lease operator of leases covering approximately 1,966 of the wells in which we own interests, and as such we are able to control expenses, capital allocation and the timing of development activities of these properties. We also own interests, and operate, 455 injection wells. During the year ended December 31, 2006, we drilled or participated in the drilling of 84 gross (81.2 net) development wells on our oil and gas properties, 82 of which were either successfully completed as producing wells, were still drilling, or were awaiting completion at the end

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of that period. Capital expenditures in connection with these activities during this period aggregated approximately $18.3 million.

Another determinant of future performance is the exploitation of existing wells that can be re-completed or otherwise reworked to extract additional hydrocarbons. We have identified 178 projects involving re-completions of existing wells, all of which involve reserves included in our proved reserves at December 31, 2005. During the year ended December 31, 2006, we conducted or participated in recompletion/workover operations on eight of our existing wells, resulting in the reestablishment or enhancement of production from seven of these wells. Our capital expenditures in connection with these recompletion operations aggregated approximately $1.7 million.

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

We have an experienced technical staff, including geologists, landmen, engineers and other technical personnel devoted to prospect generation and identification of potential drilling locations. We seek to reduce exploration risk by exploring at moderate depths that are deep enough to discover sizeable 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, 2006, we drilled or participated in the drilling of eight gross (4.3 net) exploratory wells at a cost of approximately $3.9 million and incurred total capital expenditures of approximately $4.5 million for all exploration activities. At December 31, 2006, three gross (2.1 net) exploratory wells were awaiting completion. Of these, one gross (0.1 net) well was subsequently completed as a commercially productive well, and the others remain subject to completion.

Oil and Natural Gas Reserves

At December 31, 2006, our estimated net proved reserves were 18.5 million Boe, of which 59% was crude oil, 30% was natural gas, and 11% was NGLs, with a PV-10 Value of approximately $269.9 million before income taxes. Our estimated proved developed reserves comprised 71% of our total proved reserves, and our reserve life for total proved reserves was approximately 17 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, 2006 was prepared by the independent petroleum engineering firms of Williamson Petroleum Consultants, Inc. and Forrest A. Garb & Associates.

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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,
	2004		2005		2006
Reserve Data:
Proved developed reserves:
Oil (MBbls)		6,198		7,337		6,954
Natural gas (MMcf)		31,048		26,752		26,888
Natural gas liquids (MBbls)(1)		1,611		1,396		1,671
Total (MBoe)		12,984		13,192		13,106
PV-10 Value (in thousands)	$	164,007	$	245,107	$	192,045

	As of December 31,
	2004		2005		2006
Proved reserves:
Oil (MBbls)		10,667		11,199		10,796
Natural gas (MMcf)		38,195		34,234		33,199
Natural gas liquids (MBbls)(1)		2,087		1,891		2,123
Total (MBoe)		19,120		18,796		18,452
PV-10 Value (in thousands)	$	236,201	$	345,501	$	269,892
Prices used in calculating PV-10 Value:
$/Bbl (Oil)		40.25		58.63		58.74
$/Mcf		6.02		9.14		5.51
$/Bbl (NGL)		27.56		35.89		36.51

(1) Approximately 20% of our estimated proved reserves of NGLs at December 31, 2006, result from our equity ownership in the Electra Gas Plant.

The following is a summary of the standardized measure of discounted net cash flows using methodology provided for in Statement of Financial Accounting Standard No. 69, related to our estimated proved oil and natural gas reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves were computed using oil and natural gas prices as of the end of the period presented. Future development and production costs attributable to the proved reserves were estimated assuming that existing conditions would continue over the economic lives of the individual leases and costs were not escalated for the future. Estimated future income tax expenses were calculated by applying future statutory tax rates (based on the current tax law adjusted for permanent differences and tax credits) to the estimated future pretax net cash flows related to proved oil and natural gas reserves, less the tax basis of the properties involved. For further information regarding the standardized measure of discounted net cash flows related to our estimated proved oil and natural gas reserves for the years ended December 31, 2004, 2005 and 2006, please review note Q in the notes to our year-end 2006 financial statements appearing elsewhere in this report.

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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,
	2004			2005			2006
	(in thousands)
Future cash inflows	$	711,781		$	1,037,337		$	894,626
Future production costs		(247,314	)		(336,007	)		(356,961	)
Future development costs		(36,495	)		(45,272	)		(48,605	)
Future income tax expenses		(136,669	)		(219,640	)		(158,602	)
Future net cash flows		291,303			436,418			330,458
10% annual discount for estimated timing of cash flows		(129,983	)		(209,758	)		(150,717	)
Standardized measure of discounted future net cash flows	$	161,320		$	226,660		$	179,741

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,
	2004			2005			2006
Production volumes:
Oil (MBbls)		178			787			752
Natural gas liquids (MBbls)		12			170			143
Natural gas (MMcf)		1,928			2,681			2,365
Total (MBoe)		511			1,405			1,290
Average realized prices (before effects of derivative contracts):
Oil (per Bbl)	$	37.63		$	53.75		$	63.82
Natural gas liquids (per Bbl)		26.41			36.33			40.33
Natural gas (per Mcf)		5.69			6.61			6.02
Total per Boe		35.14			47.16			52.74
Effect of settlement of derivative contracts:
Oil (per Bbl)	$	(4.48	)	$	(1.40	)	$	(5.78	)
Natural gas liquids (per Bbl)		—			—			—
Natural gas (per Mcf)		.05			(1.04	)		(.13	)
Total per Boe		(1.37	)		(2.78	)		(3.61	)
Average realized prices (after effects of derivative contracts):
Oil (per Bbl)	$	33.15		$	52.35		$	58.04
Natural gas liquids (per Bbl)		26.41			36.33			40.33
Natural gas (Per Mcf)		5.74			5.57			5.89
Total per Boe		33.77			44.38			49.13
Expenses (per Boe):
Oil and natural gas production taxes	$	2.47		$	2.36		$	2.58
Oil and natural gas production expenses		7.04			11.46			14.16
Amortization of full cost pool		5.89			8.93			9.77
General and administrative		12.90			6.13			7.21

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,
	2004		2005		2006
Proved property acquisition costs	$	82,577	$	155	$	4,476
Unproved property acquisition costs		—		—		705
Development costs		5,173		11,864		18,475
Exploration costs		727		1,507		4,489
Total costs incurred	$	88,477	$	13,526	$	28,145

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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,
	2004	2005	2006
Proved reserves acquired/discovered (MBoe)	13,704	1,323	946
Total cost per Boe of reserves acquired/discovered	$6.46	$10.23	$27.18

Producing Wells

The following table sets forth the number of productive wells in which we owned an interest as of December 31, 2006. Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline connections or connection to production facilities. Wells that we complete in more than one producing horizon are counted as one well.

	Gross	Net
Oil	1,874	1,362
Natural gas	267	122
Total	2,141	1,484

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, 2006:

	Gross	Net
Developed	104,199	38,248
Undeveloped	131,883	32,228
Total	236,082	70,476

Approximately 90% of our net acreage was located in our core areas as of December 31, 2006. Our undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether or not such acreage is held by production or contains proved reserves. A gross acre is an acre in which we own an interest. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres.

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Drilling Activities

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

	Year Ended December 31,
	2004		2005		2006 (1)
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive	23	16.3	66	58.1	77	75.7
Non-productive	1	0.3	—	—	2	0.5
Exploratory wells:
Productive	1	0.3	1	0.3	3	0.7
Non-productive	4	0.5	—	—	2	1.5
Total	29	17.4	67	58.4	84	78.4

(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.

Oil and Natural Gas Marketing and Derivative Activities

During the year ended December 31, 2006, two purchasers accounted for approximately 75% of our oil and natural gas revenue. Shell Trading-US accounted for $42.0 million, or 62%, and Targa Midstream Services, or Targa (formerly, Dynegy) accounted for $8.8 million, or 13%, of our oil and natural gas revenue for that period. No other purchaser accounted for 10% or more of our oil and natural gas revenue during 2006. Our agreement with Shell Trading-US, or STUSCO, which covers all of our north Texas oil production, through June 30, 2006 provided for payment, on a per barrel basis, of a price equal to Koch’s posted price for West Texas Intermediate Crude, plus Platt’s Trade-month P+ (a fluctuating premium based on refinery demand), minus $1.15. Effective July 1, 2006, we negotiated a new price of STUSCO WTI plus $1.50 until December 31, 2006 and $1.30 thereafter. The agreement is on a month-to-month basis and is cancelable by either party upon 30 days’ prior written notice. Our gas purchase contract with Targa, which expires February 1, 2013, covers our predominately natural gas producing properties located in Jack and Wise Counties, Texas. Under the terms of the contract, Targa takes delivery of our gas in the field and transports the gas to the nearby Chico Plant where it is processed for the extraction of liquefiable hydrocarbons. Targa pays us 85% of the weighted average price received by Targa for the sale of natural gas and natural gas liquids attributable to the gas delivered by us. There are other purchasers in the fields where our production sold to these two purchasers is produced and marketed, and such other purchasers would be available to purchase our production should any of these two purchasers discontinue operations. We have no reason to believe that any such cessation is likely to occur. However, if the Chico Plant were to cease operations, whether for mechanical, financial or other reasons, such cessation could materially and adversely affect our cash flow 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, 2006 are shown in the following table:

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

Crude oil contracts cover each month of 2007 and natural gas contracts are for February through December 2007. Natural gas secondary floors for 2007 are for April through October. Crude oil contracts and natural gas contracts for 2008 are for January through December. For the year ended December 31, 2006 our average daily production was 2,061 Bbls of oil, 6,479 Mcf of natural gas, and 392 Bbls of NGLs.

Competition

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

Title to Properties

We believe that we have satisfactory title to our properties in accordance with standards generally accepted in the oil and natural gas industry. As is customary in the oil and natural gas industry, we make only a cursory review of title to farmout acreage and to undeveloped oil and natural gas leases upon execution of any contracts. Prior to the commencement of drilling operations, a title examination is conducted and curative work is performed with respect to significant defects. To the extent title opinions or other investigations reflect title defects, we, rather than the seller of the undeveloped property, typically are responsible to cure any such title defects at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent for us to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We have obtained title opinions or reports on substantially all of our producing properties. Prior to completing an acquisition of producing oil and natural gas leases, we perform a title review on a material portion of the leases. Our oil and natural gas properties are subject to customary royalty interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties.

Facilities

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

Regulation

General. Various aspects of our oil and gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and gas industry is under constant review for amendment or expansion.

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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.

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

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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, 2006, we had 100 employees, 11 of whom were administrative, accounting or financial personnel and 89 of whom were technical and operations personnel. Our exploration staff includes two exploration geologists and two exploration landmen. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreement and we have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.

Financial Information About Geographical Areas

We have no revenue or segment profit or loss attributable to international activities.

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.

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

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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, less any shares withdrawn from the escrow to satisfy other indemnity obligations, will remain in escrow until the Sacket litigation is resolved. To date, no other claims have been made against the shares in escrow.

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

None.

PART II

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

Market for Common Stock

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

	Units				Common Stock				Warrants
	High		Low		High		Low		High		Low
2007:
First Quarter (through March 26)	$	7.36	$	5.01	$	5.52	$	4.00	$	0.87	$	0.41
2006:
First Quarter	$	8.25	$	7.00	$	5.89	$	5.46	$	1.18	$	0.78
Second Quarter		11.00		7.20		6.79		5.19		2.00		1.05
Third Quarter		8.74		6.45		5.79		4.68		1.75		0.77
Fourth Quarter		7.15		6.00		5.64		4.65		1.00		0.67
2005:
First Quarter	$	7.35	$	6.70	$	5.50	$	5.01	$	0.94	$	0.74
Second Quarter		7.05		6.36		5.56		5.12		0.82		0.57
Third Quarter		7.30		6.20		5.55		5.13		0.98		0.50
Fourth Quarter		7.35		6.65		5.56		5.31		0.95		0.65
2004:
Second Quarter (commencing May 24)	$	6.40	$	6.10	$	5.00	$	4.70	$	0.82	$	0.69
Third Quarter		6.35		5.97		5.00		4.81		0.72		0.52
Fourth Quarter		6.65		5.70		5.14		4.80		0.80		0.48

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Holders

As of March 28, 2007, there were 52 holders of record of our units, 1,081 holders of record of our common stock and 421 holders of record of our warrants. We believe that the beneficial holders of the units, common stock and warrants are in excess of 400 persons each.

Dividends

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

The following table provides information for all equity compensation plans as of the fiscal year ended December 31, 2006, 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)	976,805	(2)	$	5.62	(3)	1,423,195(4)
Equity compensation plans not approved by security holders	—			—		—
Total	976,805					1,423,195

(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.

(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 1,423,195 shares available for issuance under our 2006 Long Term Incentive Plan. In addition, shares related to grants that are forfeited, terminated, cancelled, expire unexercised, or settled in such manner that all or some of the shares are not issued to a participant or are surrendered unvested shall immediately become available for issuance.

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Stockholder Return Performance Presentation

The following graph compares the cumulative 31-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, 2006, 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, 2006. The identity of the 50+ companies included in the Dow Jones Wilshire MicroCap Exploration and production Index will be provided upon request.

	Fiscal year ending December 31,
	12/31/04		12/31/05		12/31/06
RAM Energy Resources, Inc.	$	108	$	117	$	117
Nasdaq Composite		113		117		129
Dow Jones Wilshire MicroCap Exploration & Production Index		136		169		194

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 merger 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.

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 2004 and 2005 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,
	2002			2003			2004			2005 (1)			2006
Revenues and Other Operating Income:
Oil and natural gas sales	$	10,166		$	20,053		$	17,975		$	66,243		$	68,015
Pipeline system		—			—			—			—
Gain on sale of subsidiary		—			—			12,139			—
Other		163			170			338			851			640
Realized and unrealized gains (losses) from derivatives		(146	)		(203	)		(793	)		(11,695	)		1,589
Total revenues and other operating income		10,183			20,020			29,659			55,399			70,244
Operating Expenses:
Oil and natural gas production taxes		1,044			1,408			1,263			3,320			3,329
Oil and natural gas production expenses		3,023			3,527			3,600			16,099			18,266
Pipeline purchases		—			—			—			—			—
Pipeline operations		—			—			—			—			—
Depreciation and amortization		2,947			4,098			3,273			12,972			13,252
Accretion expense		—			48			78			510			535
Contract termination and severance payments		—			—			—			—			—
Share-based compensation		—			—			—			—			2,308
General and administrative, net of operator’s overhead fees		5,858			6,331			6,601			8,610			9,300
Total operating expenses		12,872			15,412			14,815			41,511			46,990
Operating income (loss)		(2,689	)		4,608			14,844			13,888			23,254
Other Income (Expense):
Gain on early extinguishment of debt		32,883			—			—			—			—
Gain on sale of oil and natural gas properties		—			—			—			—			—
Interest expense		(9,240	)		(4,912	)		(5,070	)		(12,614	)		(17,050	)
Interest income		277			41			35			75			309
Income (Loss) from Continuing Operations Before Income Taxes and Extraordinary Item		21,231			(263	)		9,809			1,349			6,513
Income Tax Provision (Benefit)		7,975			228			3,733			806			1,465
Income (Loss) from Continuing Operations Before Extraordinary Item		13,256			(491	)		6,076			543			5,048
Extraordinary loss on acquisition of debt, net of income tax benefit of $674		—			—			—			—			—
Income (Loss) from Continuing Operations		13,256			(491	)		6,076			543			5,048
Discontinued operations:
Loss from discontinued operations		(18,016	)		(1,723	)		—			—			—
Income tax benefit		(6,846	)		(655	)		—			—			—
Loss from discontinued operations		(11,170	)		(1,068	)		—			—			—
Income (loss) before cumulative effect of change in accounting principle		2,086			(1,559	)		6,076			543			5,048
Cumulative effect of change in accounting principle (net of tax benefit of $275)		—			(448	)		—			—			—
Net income (loss)	$	2,086		$	(2,007	)	$	6,076		$	543		$	5,048

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Selected Consolidated Financial Data (continued)

(in thousands, except share data)

	Year Ended December 31,
	2002			2003			2004			2005 (1)			2006
Net income (loss) per share attributable to common stockholders—basic
Income (loss) from continuing operations before extraordinary item	$	4,861.01		$	(180.05	)	$	2,383.67		$	238.94		$	0.21
Extraordinary loss		—			—			—			—			—
Loss from discontinued operations		(4,096.08	)		(391.64	)		—			—			—
Cumulative effect of change in accounting principle		—			(164.28	)		—			—			—
Net income (loss) per share	$	764.93		$	(735.97	)	$	2,383.67		$	238.94		$	0.21
Cash dividends per share	$	—		$	294.83		$	470.77		$	615.93		$	0.02
Earnings (loss) per share:
Basic	$	764.93		$	(735.97	)	$	2,383.67		$	238.94		$	0.21
Diluted		764.93			(735.97	)		2,299.77			230.72			0.20
Weighted average shares outstanding:
Basic		2,727			2,727			2,549			2,273			24,347,607
Diluted		2,727			2,727			2,642			2,354			25,015,531
Statement of Cash Flow Data
Cash provided by (used in):
Operating activities	$	(14,842	)	$	5,774		$	1,793		$	18,359		$	30,537
Investing activities		(46	)		7,422			(64,852	)		(12,554	)		(25,317	)
Financing activities		(3,731	)		(12,333	)		62,116			(6,910	)		1,431
Other Data
Capital expenditures (2)	$	6,700		$	5,258		$	102,719		$	13,528		$	28,145
EBITDA		473			8,670			18,153			33,747			33,419
	As of December 31,
	2002			2003			2004			2005 (1)			2006
Balance Sheet Data
Total assets	$	62,192		$	45,908		$	140,324		$	143,276		$	161,725
Long-term debt, including current portion		56,267			46,057			117,344			112,846			132,237
Stockholders’ deficit		(16,842	)		(19,653	)		(19,912	)		(20,769	)		(27,895	)

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

(2) Includes costs of acquisitions.

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

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

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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,
	2002			2003			2004			2005		2006
	(in thousands)
Reconciliation of EBITDA to net income (loss):
Net income (loss)	$	2,086		$	(2,007	)	$	6,076		$	543	$	5,048
Plus: Interest expense		9,240			4,912			5,070			12,614		17,050
Plus: Amortization and depreciation expense		2,947			4,098			3,273			12,972		13,252
Plus: Accretion expense		—			48			78			510		535
Plus: Income tax expense		7,975			228			3,733			806		1,465
Less: Gain on early extinguishment of debt		(32,883	)		—			—			—		—
Less: Gain on sale of oil and natural gas properties		—			—			—			—		—
Plus: Share-based compensation		—			—			—			—		2,308
Plus: Extraordinary (gain) loss		—			—			—			—		—
Plus: Loss from discontinued operations, net of tax		11,170			1,068			—			—		—
Less: Cumulative effect of change in accounting principle		—			448			—			—		—
Plus: Unrealized (gain) loss on derivatives		(62	)		(125	)		(77	)		6,302		(6,239	)
EBITDA	$	473		$	8,670		$	18,153		$	33,747	$	33,419

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 and Oklahoma. Through our RAM Energy subsidiary, we have been active in these core areas since 1987. Our management team has extensive technical and operating expertise in all areas of our geographic focus.

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

Upon consummation of the merger, the stockholders of RAM Energy received an aggregate of 25,600,000 shares of our common stock and $30.0 million of cash. Prior to consummation of the merger, and as permitted by

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the merger agreement, on April 6, 2006, RAM Energy redeemed a portion of its outstanding stock for an aggregate consideration of $10.0 million.

The merger is accounted for as a reverse acquisition. RAM Energy has been treated as the acquiring company and the continuing reporting entity for accounting purposes. Upon completion of the merger, 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.

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

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. The net proceeds are currently invested in short-term investments pending our determination of the most appropriate uses for such proceeds.

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.

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Results of Operations

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, compared with average daily production during calendar year 2005 of 3,848 Boe. After giving pro forma effect to a reversionary interest burdening our properties in our Boonsville shallow gas area that vested in September 2005, which reduced our interest in the related properties, our average daily production in 2006 decreased by four percent (4%) compared to 2005.

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 $211,000, or 25%, compared to the year ended December 31, 2005.

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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.

	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 acquisition of RAM Energy 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.

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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.

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.

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

Revenues and Other Operating Income. Our revenues and other operating income increased by $25.7 million, or 87%, for the year ended December 31, 2005, compared to the year ended December 31, 2004. The following table summarizes our oil and natural gas sales, production volumes, average sales prices and period-to-period comparisons for the periods indicated:

	Year Ended December 31,				Increase (Decrease)
	2004		2005
Oil and natural gas sales (in thousands)	$	17,975	$	66,243	268.5	%
Production volumes:
Oil (MBbls)		178		787	342.0	%
NGL (MBbls)		12		170	1,316.7	%
Natural gas (MMcf)		1,928		2,681	39.0	%
Total MBoe		511		1,405	174.7	%
Average sale prices:
Oil (per Bbl)	$	37.63	$	53.75	43.0	%
NGL (per Bbl)		26.41		36.33	37.6	%
Natural gas (per Mcf)		5.69		6.61	16.3	%
Per Boe		35.15		47.16	34.2	%

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

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

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

	Year Ended December 31, 2004
Oil and natural gas sales (in thousands)	$	2,302
Production volumes:
Oil (Mbls)		47
Natural gas (MMcf)		410
Average sale prices:
Oil (per Bbl)	$	33.49
Natural gas (per Mcf)	$	5.68

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

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

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

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

Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes for the year ended December 31, 2005, were $3.3 million, an increase of $2.0 million, or 163%, from the $1.3 million incurred for the year ended December 31, 2004. Of the increase in production taxes for the year ended December 31, 2005,

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

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

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

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

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

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

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

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

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

Liquidity and Capital Resources

As of December 31, 2006, we had cash and cash equivalents of $6.7 million and $37.0 million was available under our revolving credit facility. At that date, we had $132.2 million of indebtedness outstanding, including $103.0 million under our credit facility, $28.4 million principal amount of indebtedness evidenced by RAM Energy’s 11½% senior notes due 2008, and $0.9 million in other indebtedness. RAM Energy does not guarantee any of our debt and we do not guarantee any debt 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. The net proceeds are currently invested in short-term investments pending our determination of the most appropriate uses for such proceeds.

Credit Facility. On April 5, 2006, RAM Energy entered into a Third Amended and Restated Loan Agreement with Guggenheim Corporate Funding, LLC, for itself and as Agent for a group of lenders. This new facility, which we refer to as the Guggenheim facility, amended, restated and replaced a prior credit facility known as the Foothill facility. Currently, we are not a party to, or a guarantor of obligations under, the Guggenheim facility. As part of the transaction creating the Guggenheim facility, Foothill assigned the notes and liens under the Foothill facility to the Agent for the lenders under the Guggenheim facility. The Guggenheim facility includes a $150.0 million revolving credit facility of which $50.0 million was immediately available, and a $150.0 million term loan facility of which $90.0 million was advanced at closing. The remainder of the term loan facility may become available, subject to approval of each lender desiring to fund its proportionate share of the additional term loan advance, for certain of the future needs of RAM Energy, including acquisitions. The Guggenheim revolving credit facility is scheduled to mature in four years, during which time amounts may be borrowed, repaid and re-borrowed, subject to a borrowing base limitation to be determined by the lenders. The term loan facility is scheduled to mature in five years, with permitted prepayments after the first year, subject to a prepayment premium in the second and third years of the term. Advances under the revolving credit facility bear interest at LIBOR plus 2% per annum, while amounts outstanding under the term loan bear interest at LIBOR plus 5.5% to 6.0% per annum. Obligations under the Guggenheim facility are secured by liens on substantially all of the assets of RAM Energy and its subsidiaries. The initial advance under the Guggenheim facility was used to refinance the Foothill facility, to pay expenses associated with establishing the Guggenheim facility, and to fund a $10.0 million redemption payment. Subsequent advances may be used to:

• repurchase all of RAM Energy’s outstanding 11½% senior notes due 2008 ($28.4 million principal amount); and

• fund general working capital purposes.

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

Senior Notes. On February 24, 1998, RAM Energy issued $115.0 million principal amount of its 11½% senior notes which mature February 15, 2008. Currently, we are not a party to, or a guarantor of, the senior notes

40

or of any obligations under the indenture covering RAM Energy’s senior notes. At December 31, 2006, RAM Energy had outstanding $28.4 million aggregate principal amount of its senior notes. The notes bear interest at an annual rate of 11½%, payable semi-annually on each February 15 and August 15. Pursuant to a Second Supplemental Indenture executed in November 2002, substantially all of the restrictive covenants and certain events of default contained in the original indenture were eliminated.

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, 2006, our net income was $5.0 million, as compared with net income of $543,000 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 $10.6 million for 2006 compared to $20.5 million for 2005, a decrease of $9.9 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, 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.

Cash Flow From Financing Activities. For 2006, net cash provided by our financing activities was $2.3 million, compared to net cash used of $6.9 million for 2005. 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.

Capital Commitments

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

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

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

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

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

During 2006, we had capital expenditures of $28.1 million relating to our oil and natural gas operations, of which $18.5 million was allocated to drilling new development wells, $4.5 million was for exploration costs, and $5.2 million was for acquisition costs. Our non-acquisition capital expenditures for the year 2006 aggregated approximately $23.7 million. The amount and timing of our capital expenditures may vary depending on the rate at which we expand and develop our oil and natural gas properties. We may require additional financing for future acquisitions and to refinance our debt before or at its final maturities.

41

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, 2006, which are obligations during the following years:

	Total		2007		2008-2009		2010-11		and after
	(in thousands)
Contractual Cash Obligations
Long-term debt	$	132,282	$	756	$	28,526	$	103,000	$	—
Operating leases		627		359		231		37		—
Total contractual cash obligations	$	132,909	$	1,115	$	28,757	$	103,037	$	—

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, we periodically utilize various derivative strategies to manage the price received for a portion of our future oil and natural gas production. We have not established derivatives in excess of our expected production.

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

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

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Crude oil contracts cover each month of 2007 and natural gas contracts are for February through December 2007. Natural gas secondary floors for 2007 are for April through October. Crude oil contracts and natural gas contracts for 2008 are for January through December. For 2006, we had a realized loss from our derivative activities of approximately $4.7 million.

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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	45
Consolidated Balance Sheets as of December 31, 2006 and 2005	46
Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004	47
Consolidated Statements of Stockholders’ Deficit for the years ended December 31, 2006, 2005 and 2004	48
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004	49
Notes to Consolidated Financial Statements	51

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

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, 2006 and 2005, and the related consolidated statements of operations, stockholders’ deficit, and cash flows for each of the three years in the period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of RAM Energy Resources, Inc. and subsidiaries as of December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

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

/s/ UHY LLP

Houston, Texas

April 2, 2007

45

RAM Energy Resources, Inc.

Consolidated balance sheets

(in thousands, except share and per share amounts)

	As of December 31,
	2006			2005
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,721		$	70
Accounts receivable:
Oil and natural gas sales		6,194			7,422
Joint interest operations, net of allowance of $187 ($31 at December 31, 2005)		750			566
Related party		—			142
Income taxes		121			—
Other, net of allowance of $33 ($13 at December 31, 2005)		236			175
Derivative assets		677			—
Prepaid expenses		1,013			756
Other current assets		—			484
Total current assets		15,712			9,615
PROPERTIES AND EQUIPMENT, AT COST:
Oil and natural gas properties and equipment, using full cost accounting		185,284			160,704
Other property and equipment		6,098			7,276
		191,382			167,980
Less accumulated amortization and depreciation		(48,577	)		(36,848	)
Total properties and equipment		142,805			131,132
OTHER ASSETS:
Deferred loan costs, net of accumulated amortization of $4,840 ($4,905 at December 31, 2005)		2,593			1,613
Other		615			916
Total assets	$	161,725		$	143,276
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable:
Trade	$	7,810		$	4,343
Oil and natural gas proceeds due others		3,886			3,201
Related party		14			41
Other		31			—
Accrued liabilities:
Compensation		1,611			749
Interest		3,849			1,745
Income taxes		223			146
Derivative liabilities		—			3,510
Long-term debt due within one year		756			560
Total current liabilities		18,180			14,295
OIL & NATURAL GAS PROCEEDS DUE OTHERS		2,481			1,972
LONG-TERM DEBT		131,481			112,286
DEFERRED AND OTHER NON-CURRENT INCOME TAXES		26,677			25,300
ASSET RETIREMENT OBLIGATION		10,801			10,192
COMMITMENTS AND CONTINGENCIES		—			—
STOCKHOLDERS’ DEFICIT:
Common stock, $0.0001 par value, 100,000,000 and 30,000,000 shares authorized, 33,630,000 and 7,700,000 shares issued, 33,439,530 and 7,700,000 outstanding at December 31, 2006 and 2005, respectively		3			1
Additional paid-in capital		2,308			95
Treasury stock—837,275 shares at cost		(3,768	)		—
Accumulated deficit		(26,438	)		(20,865	)
Stockholders’ deficit		(27,895	)		(20,769	)
Total liabilities and stockholders’ deficit	$	161,725		$	143,276

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

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RAM Energy Resources, Inc.

Consolidated statements of operations

(in thousands, except share and per share amounts)

	Years ended December 31,
	2006			2005			2004
REVENUES AND OTHER OPERATING INCOME:
Oil and natural gas sales	$	68,015		$	66,243		$	17,975
Gain on sale of subsidiary		—			—			12,139
Other		640			851			338
Realized and unrealized gains (losses) from derivatives		1,589			(11,695	)		(793	)
Total revenues and other operating income		70,244			55,399			29,659
OPERATING EXPENSES:
Oil and natural gas production taxes		3,329			3,320			1,263
Oil and natural gas production expenses		18,266			16,099			3,600
Depreciation and amortization		13,252			12,972			3,273
Accretion expense		535			510			78
Share-based compensation		2,308			—			—
General and administrative, overhead and other expenses, net of operator’s overhead fees		9,300			8,610			6,601
Total operating expenses		46,990			41,511			14,815
Operating income		23,254			13,888			14,844
OTHER INCOME (EXPENSE):
Interest expense		(17,050	)		(12,614	)		(5,070	)
Interest income		309			75			35
INCOME BEFORE INCOME TAXES		6,513			1,349			9,809
INCOME TAX PROVISION		1,465			806			3,733
Net income	$	5,048		$	543		$	6,076
BASIC EARNINGS PER SHARE	$	0.21		$	0.07		$	1.06
BASIC WEIGHTED AVERAGE SHARES OUTSTANDING		24,347,607			7,700,000			5,739,057
DILUTED EARNINGS PER SHARE	$	0.20		$	0.07		$	1.06
DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING		25,658,711			7,700,000			5,739,057

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

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RAM Energy Resources, Inc.

Consolidated statements of stockholders’ deficit

Years ended December 31, 2006, 2005, and 2004

(In thousands, except share amounts)

	Common Stock			Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Total
	Shares	Amount
BALANCE, January 1, 2004	—	$	—	$	114		$	—		$	(19,768	)		(19,654	)
Net income	—		—		—			—			6,076			6,706
Dividends declared	—		—		—			—			(1,200	)		(1,200	)
Issuance of Common Stock to Initial Shareholders	1,375,000		—		—			—			—			—
Sale of 6,325,000 Units and Underwriters Option, net of underwriters discount and offering expenses	6,325,000		1		—			—			—			1
Purchase and cancellation of common shares and outstanding options	—		—		(19	)		—			(5,116	)		(5,135	)
BALANCE, December 31, 2004	7,700,000		1		95			—			(20,008	)		(19,912	)
Net income	—		—		—			—			543			543
Dividends declared	—		—		—			—			(1,400	)		(1,400	)
BALANCE, December 31, 2005	7,700,000		1		95			—			(20,865	)		(20,769	)
Net income	—		—		—			—			5,048			5,048
Dividends declared	—		—		—			—			(500	)		(500	)
Stock redemption & cancellation	—		—		(95	)		—			(9,697	)		(9,792	)
Issuance of shares and restatement of equity relating to merger with Ram Energy, Inc., net of merger costs	25,600,000		2		—			—			(424	)		(422	)
Repurchase of stock	—		—		—			(3,768	)		—			(3,768	)
Share-based compensation	330,000		—		2,308			—			—			2,308
BALANCE, December 31, 2006	33,630,000	$	3	$	2,308		$	(3,768	)	$	(26,438	)	$	(27,895	)

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,
	2006			2005			2004
OPERATING ACTIVITIES:
Net income	$	5,048		$	543		$	6,076
Adjustments to reconcile net income to net cash provided by (used in) operating activities—
Depreciation and amortization		13,252			12,972			3,273
Amortization of deferred loan costs and Senior Notes discount		988			839			492
Write off of loan fees due to debt refinancing		1,055			—			—
Accretion expense		535			510			78
Gain on sale of subsidiary		—			—			(12,139	)
Provisions for doubtful accounts		—			—			385
Unrealized (gain) loss on derivatives		(6,239	)		6,302			(1,569	)
Derivative premiums net of amortization		—			634			45
Deferred income taxes		1,311			1,199			(3,159	)
Share-based compensation		2,308			—			—
Gain on disposal of other property and equipment		(142	)		—			(1	)
Changes in operating assets and liabilities, net of acquisitions
Accounts receivable		1,012			(2,608	)		(18	)
Prepaid expenses and other assets		229			(143	)		342
Accounts payable		4,173			(165	)		(67	)
Accrued liabilities		6,025			(1,331	)		1,556
Income taxes payable		105			(393	)		6,892
Gas balancing liability		—			—			(393	)
Total adjustments		24,612			17,816			(4,283	)
Net cash provided by operating activities		29,660			18,359			1,793
INVESTING ACTIVITIES:
Payments for oil and natural gas properties and equipment		(28,145	)		(13,528	)		(5,900	)
Proceeds from sales of oil and natural gas properties		3,565			2,471			320
Payments for other property and equipment		(812	)		(1,497	)		(205	)
Proceeds from sales of other property and equipment		461			—			38
Payments of merger costs		(4,187	)		—			—
Cash acquired in merger		3,801			—			—
RWG acquisition, net of cash acquired		—			—			(82,577	)
Proceeds from the sale of subsidiary		—			—			21,791
Proceeds from short-term investments		—			—			1,681
Net cash used in investing activities		(25,317	)		(12,554	)		(64,852	)

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RAM Energy Resources, Inc.

Consolidated statements of cash flows

(in thousands)

	Years ended December 31,
	2006			2005			2004
FINANCING ACTIVITIES:
Payments on long-term debt		(88,094	)		(15,615	)		(18,234	)
Proceeds from borrowings on long-term debt		107,443			10,670			88,585
Payments for deferred loan costs		(2,981	)		(565	)		(1,500	)
Stock redemption		(9,792	)		—			—
Stock repurchased		(3,768	)		—			(5,135	)
Dividends paid		(500	)		(1,400	)		(1,600	)
Net cash provided by (used in) financing activities		2,308			(6,910	)		62,116
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		6,651			(1,105	)		943
CASH AND CASH EQUIVALENTS, beginning of year		70			1,175			2,118
CASH AND CASH EQUIVALENTS, end of year	$	6,721		$	70		$	1,175
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for income taxes	$	124		$	20		$	300
Cash paid for interest	$	10,080		$	3,297		$	4,285
DISCLOSURE OF NON CASH INVESTING AND FINANCING ACTIVITIES:
Accrued interest added to principal balance of credit facility	$	2,848		$	8,093		$	554

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, 2006 and 2005

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

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

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

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

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

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

2. Principles of Consolidation

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

3. Properties and Equipment

The Company follows the full cost method of accounting for oil and natural gas operations. Under this method all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. No gains or losses are recognized upon the sale or

51

other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves.

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

The Company has capitalized internal costs of approximately $2,303,000, $1,778,000, and $596,000 for the years ended December 31, 2006, 2005, and 2004, 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, 2006 and 2005 is approximately $3,375,000 and $4,246,000, 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 2006, 2005, or 2004.

4. Depreciation and Amortization

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

5. Natural Gas Sales and Gas Imbalances

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

The Company follows the entitlement method of accounting for natural gas sales, recognizing as revenues only its net interest share of all production sold. Any amount attributable to the sale of production in excess of or less than the Company’s net interest is recorded as a gas balancing asset or liability. At December 31, 2006, the Company’s net underproduced position was approximately 175,000 Mcf with an associated asset of approximately $262,000, which is recorded in other assets on the consolidated balance sheet. At December 31, 2005, the Company’s net underproduced position was approximately 162,000 Mcf with an associated asset of approximately $237,000.

52

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 2006, approximately 75% of total revenues were to two customers (73% to two customers in 2005 and 52% to four customers in 2004), with sales to each comprising 62% and 13% (55% and 18% in 2005 and 23%, 11%, 10% and 8% in 2004) of total revenues.

In 2006 and 2005 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):

2007	$	784
2008	$	677
2009	$	668
2010	$	390

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 $271,000, $228,000, and $212,000 for the years ended December 31, 2006, 2005, and 2004, respectively.

10. Use of Estimates

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

11. Fair Value of Financial Instruments

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

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

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Senior Notes: The carrying amount reported on the consolidated balance sheets is approximately $710,000 below fair value at December 31, 2006 based upon management’s estimates. Management bases 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.

12. Reclassifications

Certain reclassifications of previously reported amounts for 2005 and 2004 have been made to conform to the 2006 presentation. These reclassifications had no effect on net income or loss.

13. Derivatives

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

The Company entered into numerous derivative contracts to reduce the impact of oil and natural gas price fluctuations and as required by the terms of its credit facility (see Note K). The Company did not designate these transactions as hedges as required by SFAS No. 133 in order to receive hedge accounting treatment. Accordingly, all gains and losses on the derivative instruments during 2006, 2005 and 2004 have been recorded in the statements of operations.

14. Earnings per Common Share

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

	2006		2005		2004
BASIC INCOME PER SHARE:
Net income	$	5,048	$	543	$	6,076
Weighted average shares		24,347,607		7,700,000		5,739,057
Basic net income per share	$	0.21	$	0.07	$	1.06
DILUTED INCOME PER SHARE:
Net income	$	5,048	$	543	$	6,076
Weighted average shares—basic		24,347,607		7,700,000		5,739,057
Dilutive effect of unvested stock grants		92,148		—		—
Dilutive effect of warrants		1,218,956		—		—
Weighted average shares assuming dilutive effect of stock options		25,658,711		7,700,000		5,739,057
Diluted net income per share	$	0.20	$	0.07	$	1.06

Diluted earnings per share does not include 825,000 shares of our common stock issuable upon the exercise of currently exercisable options to purchase 275,000 units at an exercise price of $9.90 per unit, each unit consisting of one share of our common stock and two warrants, each warrant to purchase one share of our common stock at an exercise price of $6.26 per share. These shares are anti-dilutive for all periods presented.

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15. Asset Retirement Obligations

The Company accounts for asset retirement obligations in accordance with Financial Accounting Standards Board (FASB) No. 143 Accounting for Asset Retirement Obligations. SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Company recorded accretion expense of approximately $535,000, $510,000, and $78,000 in 2006, 2005, and 2004, respectively.

The Company recorded the following activity related to the asset retirement obligation for the years ended December 31, 2006 and 2005 (in thousands):

	2006			2005
Liability for asset retirement obligations, beginning of year	$	10,192		$	6,656
Accretion expense		535			510
Obligations for new wells drilled or new estimates		283			3,177
Obligations for wells sold or retired		(209	)		(151	)
Liability for asset retirement obligations, end of year	$	10,801		$	10,192

16. Income Taxes

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

17. Revenue Recognition

Revenues associated with sales of oil and natural gas are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which we have an interest with other producers are generally recognized on the basis of the Company’s met working interest (entitlement method).

18. Share-Based Compensation

Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123R, Share-Based Payment, for its share-based compensation plan. Refer to Note O for a discussion of the Company’s share-based compensation expense.

19. New Accounting Pronouncements

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

In September 2006, the Securities and Exchange Commission (“SEC”) issued SAB No. 108 which provides guidance on quantifying and evaluating the materiality of unrecorded misstatements. SAB 108 is effective for annual financial statements covering the fiscal years ending on or after November 15, 2006. SAB 108 requires that a company use both the “iron curtain” and “rollover” approaches when quantifying misstatement amounts.

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The determination that an error is material in a current year that includes prior-year effects may result in the need to correct prior-year financial statements, even if the misstatement in the prior year or years is considered immaterial. When companies correct prior-year financial statements for immaterial errors, SAB 108 does not require previously filed reports to be amended. Such correction may be made the next time the company files the prior year financial statements. The Company does not currently believe there are any errors which would materially impact prior-year financial statements.

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

B—WG ENERGY ACQUISITION

The Company completed the WG Energy Acquisition on December 17, 2004. The final adjusted purchase price was $82.6 million, including the assumption and payment of WG’s long-term debt of $24.5 million, the settlement of all outstanding derivative instruments of $14.4 million, and the balance (excluding the escrow) of $32.7 million was paid in cash. $11.0 million of the purchase price was deposited in two separate escrow accounts to provide funds against which the Company may have made claims for any subsequently determined breach by WG of representations and warranties in the merger agreement and for potential losses that may have arisen in connection with certain litigation against WG that existed at that time. Subsequently, the Company collected claims of $250,000 and the balance of the escrow accounts were released. The acquisition was financed with an existing credit facility. WG’s principal assets are producing oil properties located in north Texas, a gas plant and a significant block of undeveloped deep rights in held-by-production leases.

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

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

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

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

	Year ended December 31, 2004
Revenues and other operating income	$	49,792
Net loss	$	(5,040	)
Basic and diluted loss per share	$	(1,977.25	)

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C—SALE OF SUBSIDIARY

On April 23, 2004 the Company entered into a stock sale agreement with Range Energy I, Inc. to sell all of the issued and outstanding shares of common capital stock of RB Operating Company (RBOC), a wholly-owned subsidiary of the Company. The transaction closed on April 29, 2004 for a purchase price of $22.5 million, subject to customary post-closing adjustments. The Company received proceeds of $21.8 million, net of transaction costs of $363,000 and cash paid of $814,000, from the sale, of which $17.9 million was used to pay the remaining balance on an existing credit facility.

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

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

D—LONG-TERM DEBT

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

	2006		2005
11.5% Senior Notes due 2008, net of discount	$	28,351	$	28,309
Credit facility		103,000		83,897
Installment loan agreements		886		640
		132,237		112,846
Less amount due within one year		756		560
	$	131,481	$	112,286

The amount of required principal payments for the next five years and thereafter, as of December 31, 2006, is as follows (in thousands): 2007—$756; 2008—$28,459; 2009—$22; 2010—$13,000; 2011— $90,000 and thereafter—none.

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, 2006 and 2005. 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.

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

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

At December 31, 2006 and 2005 the unamortized original issue discount associated with the Notes totaled approximately $45,000 and $87,000, respectively.

2. Revolving Credit Facility

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

At closing, $50.0 million of the revolving credit facility was immediately available, and $90.0 million of the term loan was advanced. The remainder of the term loan facility will be available, subject to approval of the lenders, for certain future needs, including acquisitions. The revolving credit facility will mature in April, 2010, during which time amounts may be borrowed and repaid as often as needed, subject to a borrowing base limitation that is re-determined semi-annually, based on oil and gas reserves. The term loan facility will mature in April, 2011, with permitted prepayments after the first year, subject to a prepayment premium in the second and third years of the term. Advances under the revolving credit facility will bear interest at LIBOR plus 2% per annum, while amounts outstanding under the term loan will bear interest at LIBOR plus 5.5% to 6.0% per annum. Obligations under the credit facility are secured by a first lien on substantially all of the assets of RAM Energy, Inc. and its subsidiaries. The initial advance under the credit facility was used to refinance the previous credit facility, and to fund the pre-merger redemption payment permitted by the merger agreement. Subsequent advances may be used to:

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

• for general working capital purposes.

The credit facility contains financial covenants requiring RAM Energy, Inc. to maintain certain ratios, including a current ratio, a ratio of earnings before interest, taxes, depreciation and amortization, or EBITDA, to interest expense, a ratio of total indebtedness to EBITDA, and a ratio of asset value to total indebtedness. In addition, the credit facility contains other affirmative and negative covenants customary in lending transactions of this nature, including the maintenance by RAM Energy, Inc. of hedging contracts for a minimum and maximum amount of projected oil and natural gas production from its properties. The Company was in compliance with all covenants as of December 31, 2006.

E—SUBSIDIARY GUARANTORS

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

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

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

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The following represents the condensed consolidating statements of operations and statements of cash flows for RAM Energy Resources, Inc. (“Parent”), RAM Energy Inc. and its subsidiaries for the years ended December 31, 2006, 2005 and 2004 (in thousands):

	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 (used in) provided by operating activities	$	(268	)	$	2,815		$	27,990		$	—		$	30,537
Cash flows (used in) investing activities		(389	)		(2,116	)		(22,812	)		—			(25,317	)
Cash flows provided by (used in) financing activities		2,004			(567	)		(6	)		—			1,431
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) 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

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	Parent		RAM Energy, Inc.			Subsidiary Guarantors			Consolidating Adjustments			Total Consolidated Amounts
Year ended December 31, 2004
Operating revenues	$	—	$	20,370		$	9,369		$	(80	)	$	29,659
Operating expenses		—		11,553			3,342			(80	)		14,815
Operating income		—		8,817			6,027			—			14,844
Other expense		—		359			25			(5,419	)		(5,035	)
Income (loss) before income taxes		—		9,176			6,052			(5,419	)		9,809
Income taxes		—		3,100			633						3,733
Net income (loss)	$	—	$	6,076		$	5,419		$	(5,419	)	$	6,076
Cash flows provided by (used in) operating activities	$	—	$	85,784		$	(83,991	)	$	—		$	1,793
Cash flows (used in) provided by investing activities		—		(66,556	)		1,704			—			(64,852	)
Cash flows (used in) provided by financing activities		—		(20,109	)		82,225			—			62,116
(Decrease) in cash and cash equivalents		—		(881	)		(62	)		—			(943	)
Cash and cash equivalents, beginning of year		—		1,924			194			—			2,118
Cash and cash equivalents, end of year	$	—	$	1,043		$	132		$	—		$	1,175

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.

F—LEASES

The Company leases office space and certain equipment under non-cancelable operating lease agreements that expire on various dates through 2011. Approximate future minimum lease payments for operating leases at December 31, 2006 are as follows (in thousands):

Year Ending December 31,
2007	$	359
2008	$	198
2009	$	33
2010	$	25
2011	$	12
	$	627

Rent expense of approximately $389,000, $519,000, and $288,000 was incurred under operating leases in the years ended December 31, 2006, 2005, and 2004, respectively.

G—DEFINED CONTRIBUTION PLAN

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all of its employees. The plan allows eligible employees to contribute up to 100% of their annual compensation, not to exceed the maximum amount permitted by IRS regulations. Employer contributions to the plan are discretionary. The Company provided matching contributions to the plan in 2006, 2005, and 2004 of $691,000, $210,000, and $190,000, respectively.

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H—STOCKHOLDERS’ EQUITY (DEFICIT)

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 and $1,200,000 for the years ended December, 2005 and 2004, respectively.

On April 6, 2006, RAM Energy, Inc. redeemed a portion of the outstanding shares of its common stock for an aggregate redemption price of 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 12,650,000 shares of common stocks issuable upon the exercise of outstanding warrants at an exercise price of $5.00 per share and 825,000 shares of our common stock are issuable upon the exercise of currently exercisable options to purchase 275,000 units at an exercise price of $9.90 per unit, each unit consisting of one share of our common stock and two warrants, each warrant to purchase one share of our common stock at an exercise price of $6.25 per share. Such warrants, when issued, will be immediately exercisable.

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, Inc. The Company reserved a maximum of 2,400,000 shares of its common stock for issuance under the Plan. Certain officers and directors of the Company were awarded 330,000 shares of common stock under the Plan. The value of the shares was recorded at $6.72 per share, the closing market price of the Company’s common stock as of that date (see note O). At the request of the grantees, on June 8, 2006, the Company repurchased 98,100 of these shares at $6.04 per share, the closing market price of the Company’s common stock as of that date, to satisfy the grantees’ federal and state income tax withholding requirements, as permitted by the Plan. The repurchased shares are held by the Company as treasury stock at December 31, 2006.

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, 2006.

On November 10, 2006 the Company granted 646,805 shares of its common stock to certain employees. These shares will vest to the grantees over a five-year period with 20% of the shares granted being issued on each subsequent anniversary date.

I—INCOME TAXES

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

	Year Ended December 31,
	2006			2005			2004
Current	$	(154	)	$	393		$	(6,892	)
Deferred		(1,311	)		(1,199	)		3,159
Provision for income tax expense	$	(1,465	)	$	(806	)	$	(3,733	)

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.

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

	Year Ended December 31,
	2006			2005			2004
Income tax provision at the federal statutory rate (34%)	$	(2,214	)	$	(459	)	$	(3,088	)
State income (tax) benefit, net of federal benefit		781			12			(361	)
Meals and entertainment expense		(21	)		(34	)		—
Non-deductible dues		(17	)		(15	)		—
Non-deductible related party expenses		—			(302	)		(284	)
Other		6			(8	)		—
Income tax provision	$	(1,465	)	$	(806	)	$	(3,733	)

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,
	2006			2005
Deferred tax assets:
Current:
Accrued expenses and other	$	490		$	163
	$	490		$	163
Valuation allowance		—			—
Net current deferred tax assets	$	490		$	163
Noncurrent deferred tax assets:
Net operating loss carryforward	$	3,373		$	1,510
Accrued liabilities and other		263			3,059
	$	3,636		$	4,569
Valuation allowance		—			—
Net noncurrent deferred tax assets	$	3,636		$	4,569
Deferred tax liabilities:
Current:
Prepaid expenses and other	$	(2,172	)	$	(230	)
		(2,172	)		(230	)
Noncurrent:
Depreciable/depletable property, plant and equipment	$	(18,998	)	$	(20,236	)
Other		—			—
Total noncurrent deferred tax liabilities	$	(18,998	)	$	(20,236	)
Net noncurrent deferred tax liability	$	(21,170	)	$	(20,466	)
Net deferred tax liability	$	(17,044	)	$	(15,734	)

63

As of December 31, 2006, the Company has federal net operating loss carryforwards of approximately $9.11 million for tax purposes, $4.02 million of which were an inherited attribute from the WG Energy Holdings, Inc. acquisition during 2004. These net operating loss carryforwards are subject to the ownership change limitation provisions of Section 382 of the Internal Revenue Code. However, based upon the value of WG Energy Holdings, Inc. at the time of the acquisition, the amount of these net operating losses that may be used annually should be sufficient to allow the losses to be utilized prior to their expiration. Accordingly, the Company believes that it will more likely than not be able to utilize these losses and that no valuation allowance for the deferred tax asset associated therewith is required. If not used, these carryforwards will generally expire between 2021 and 2023. In addition, the Company has generated net operating loss carryforwards for state income tax purposes, which the Company believes will more likely than not be realized during the relevant carryforward periods; however, such amounts have not been separately disclosed in the financial statements as the Company does not believe that these net operating losses are material to the amounts presented herein.

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

J—COMMITMENTS AND CONTINGENCIES

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

RAM Energy, Inc. and other defendants have filed answers in the lawsuit denying all material allegations set out in the petition. The Company believes that fair and proper accounting was made to the royalty owners for production from the subject leases and intends to vigorously defend the lawsuit. Plaintiffs have not specified an amount of claim, nor the time period covered. Management is unable to estimate a range of potential loss, if any, related to this lawsuit, and accordingly no amounts have been recorded in the consolidated financial statements. In the event the court should find RAM Energy, Inc. and its related defendants liable for damages in the lawsuit, a former joint venture partner is contractually obligated to pay a portion of any damages assessed against the defendant lessees up to a maximum contribution of approximately $2.8 million.

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

64

K—DERIVATIVE CONTRACTS

During 2006, 2005, and 2004 the Company entered into numerous derivative contracts. The Company did not formally designate these transactions as hedges as required by SFAS No. 133 in order to receive hedge accounting treatment. Accordingly, all gains and losses on the derivative financial instruments during 2006, 2005, and 2004 have been recorded in the statements of operations.

At December 31, 2006 the Company had collars in place on 45,625 barrels of oil per month through 2007 and 28,967 barrels of oil per month through 2008. The 45,625 barrels per month in 2007 had a weighted average floor and ceiling of $52.67 and $73.24, respectively. The 28,967 barrels per month had a weighted average floor and ceiling of $53.69 and $86.08, respectively. For natural gas, the Company had collars in place on 116,250 Mmbtu per month through 2007 and 122,000 Mmbtu per month through 2008. The 116,250 Mmbtu per month in 2007 had a weighted average floor and ceiling of $7.48 and $11.58, respectively. The 122,000 Mmbtu per month in 2008 had a weighted average floor and ceiling of $6.87 and $13.53, respectively. The Company purchased call options on 122,000 Mmbtu per month of natural gas for seven months in 2007 at a weighted average floor price of $12.00.

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

At December 31, 2004 the Company had purchased put options on 37,958 barrels per month of crude oil through December 2005 with a floor price of $40.00 per barrel. For natural gas the Company had purchased collars on 152,000 Mmbtu per month through October 2005; the weighted average floor price was $5.65 per Mmbtu, and the weighted average ceiling price was $7.84 per Mmbtu.

The Company measured the fair value of its derivatives at December 31, 2006, 2005 and 2004, based on quoted market prices. Accordingly, an asset of $677,000, a liability of $3,510,000, and an asset of $1,627,000 were recorded in the consolidated balance sheets at December 31, 2006, 2005 and 2004, respectively.

L—LIQUIDITY

As of December 31, 2006, the Company has an accumulated deficit of $26,438,000 and a working capital deficit of $2,468,000. Management believes that borrowings currently available to the Company under the Company’s credit facilities ($37 million available at December 31, 2006), the balance of unrestricted cash, and anticipated cash flows from operations will be sufficient to satisfy its currently expected capital expenditures, working capital, and debt service obligations for the foreseeable future. The actual amount and timing of future capital requirements may differ materially from estimates as a result of, among other things, changes in product pricing and regulatory, technological and competitive developments. Sources of additional financing may include commercial bank borrowings, vendor financing and the sale of oil and natural gas properties or equity or debt securities. Management cannot assure that any such financing will be available on acceptable terms or at all.

65

M—RELATED PARTY TRANSACTIONS

Prior to being acquired by the Company, RAM Energy Inc. paid rent expense of approximately $0, $29,000, and $66,000 relating to a condominium for one of the shareholders of the Company for the years ended December 31, 2006, 2005, and 2004, respectively.

Also, prior to being acquired by the Company, for the years ended December 31, 2006, 2005, and 2004 approximately $104,000, $499,000, and $792,000, 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.

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

N—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, 2006 and 2005, $150,000 has been recorded each year as compensation expense in the consolidated statements of operations.

O—SHARE-BASED COMPENSATION

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

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

On November 10, 2006, certain employees were awarded an aggregate 646,805 shares of common stock, which shares become vested 20% per year on each successive anniversary date. Accordingly, share-based compensation is being recognized based upon the fair value of the stock on November 10, 2006 ($5.06) over the five-year vesting period. Approximately $91,000 of share-based compensation was recognized in 2006 attributable to this stock grant. The estimated future share-based compensation that is expected to be recognized from this stock grant is as follows: 2007—$655,000; 2008—$655,000; 2009—$655,000; 2010—$655,000 and 2011—$564,000.

66

P—SUBSEQUENT EVENT

On February 13, 2007, the Company completed a public offering of 7,500,000 shares of its common stock, priced at $4.00 per share. Net proceeds of the offering were $28.05 million and will be 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.

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

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

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

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

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

	2006			2005			2004
Proved oil and natural gas properties	$	185,284		$	160,704		$	146,598
Accumulated depreciation and amortization		(45,203	)		(32,602	)		(20,074	)
	$	140,081		$	128,102		$	126,524

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):

	2006			2005			2004
Acquisition of proved properties	$	4,476		$	155		$	97,243
Acquisition of unproved properties		705			—			—
Proceeds from sale of unproved properties		(3,565	)		—			—
Development costs		18,475			11,864			5,173
Exploration costs		2,766			1,507			727
Exploration in progress		1,723			—			—
Sale of producing properties		—			(2,471	)		(16,881	)
Additional asset retirement obligation		—			3,051			—
	$	24,580		$	14,106		$	86,262
Amortization rate per equivalent oil barrel	$	9.78		$	8.93		$	5.64

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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, 2003	2,322		34,567		—
Extensions and discoveries	17		3,015		—
Sales of reserves in place	(1,319	)	(4,890	)	—
Purchases of reserves in place	9,482		10,013		2,092
Revisions of previous estimates	343		(2,582	)	7
Production	(178	)	(1,928	)	(12	)
December 31, 2004	10,667		38,195		2,087
Extensions and discoveries	5		1,297		—
Sales of reserves in place	(25	)	(1,305	)	—
Purchases of reserves in place	—		—		—
Revisions of previous estimates	1,339		(1,272	)	(26	)
Production	(787	)	(2,681	)	(170	)
December 31, 2005	11,199		34,234		1,891
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
Proved developed reserves:
December 31, 2004	6,198		31,048		1,611
December 31, 2005	7,337		26,752		1,396
December 31, 2006	6,954		26,888		1,671

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

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

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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):

	2006			2005			2004
Future cash inflows	$	894,626		$	1,037,337		$	711,781
Future production costs		(356,961	)		(336,008	)		(247,314	)
Future development costs		(48,605	)		(45,271	)		(36,495	)
Future income tax expenses		(158,602	)		(219,640	)		(136,669	)
Future net cash flows		330,458			436,418			291,303
10% annual discount for estimated timing of cash flows		(150,717	)		(209,758	)		(129,983	)
Standardized measure of discounted future net cash flows	$	179,741		$	226,660		$	161,320

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):

	2006			2005			2004
Standardized measure of discounted future net cash flows at beginning of year	$	226,660		$	161,320		$	67,715
Changes during the year:
Sales and transfers of oil and natural gas produced, net of production costs		(46,272	)		(46,823	)		(13,112	)
Net changes in prices and production costs		(97,697	)		133,301			(5,758	)
Extensions and discoveries, less related costs		30,560			2,311			9,337
Development costs incurred and revisions		(3,333	)		(8,777	)		4,691
Sales of reserves in place		—			(2,551	)		(21,507	)
Purchases of reserves in place		4,476			—			152,083
Revisions of previous quantity estimates		2,107			8,219			(4,560	)
Net change in income taxes		28,690			(43,960	)		(38,026	)
Accretion of discount		34,550			23,620			10,457
Net change		(46,919	)		65,340			93,605
Standardized measure of discounted future net cash flows at end of year	$	179,741		$	226,660		$	161,320

Prices used in computing these calculations of future cash flows from estimated future production of proved reserves were $58.74, $58.63, and $40.25 per barrel of oil at December 31, 2006, 2005, and 2004, respectively, $5.51, $9.14, and $6.02 per thousand cubic feet of natural gas at December 31, 2006, 2005, and 2004, respectively and $36.51, $35.89 and $27.56 per barrel of natural gas liquids at December 31, 2006, 2005, and 2004, respectively.

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R—Supplementary Data

Selected Quarterly Financial Data (unaudited)

RAM Energy Resources, Inc.

	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 (loss)		3,365			11,103			745			8,041
Interest expense		(3,837	)		(3,906	)		(5,778	)		(3,529	)
Interest income		71			129			82			27
Income 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		$	(0.13	)	$	1,238.01
Diluted net income (loss) applicable to common stockholders per common share	$	0.03		$	0.13		$	(0.13	)	$	1,195.41
	2005 - Quarter Ended
	December 31,			September 30,			June 30,			March 31,
	($ In thousands except per share data)
Net revenue	$	22,889		$	5,975		$	11,768		$	14,767
Net operating expenses		11,883			10,671			9,400			9,557
Operating income (loss)		11,006			(4,696	)		2,368			5,210
Interest expense		(3,845	)		(3,145	)		(2,851	)		(2,773	)
Interest income		34			19			13			9
Income before income taxes		7,195			(7,822	)		(470	)		2,446
Income tax provision (benefit)		3,028			(2,972	)		(179	)		929
Net income (loss)	$	4,167		$	(4,850	)	$	(291	)	$	1,517
Basic net income (loss) applicable to common stockholders per common share	$	0.54		$	(0.63	)	$	(0.04	)	$	667.40
Diluted net income (loss) applicable to common stockholders per common share	$	0.54		$	(0.63	)	$	(0.04	)	$	644.44

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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

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in Rules 13A-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the “Exchange Act”) as of December 31, 2006. On the basis of this review, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial officer, in a manner that allows timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting during the fourth quarter of 2006 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

No items to report.

71

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 2007 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.

72

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	45
Consolidated Balance Sheets as of December 31, 2006 and 2005	46
Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004	47
Consolidated Statements of Stockholders’ Deficit for the years ended December 31, 2006, 2005 and 2004	48
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004	49
Notes to Consolidated Financial Statements	51

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.	(1) [3.2]
4.1	Specimen Unit Certificate.	(1) [4.1]
4.2	Specimen Common Stock Certificate.	(1) [4.2]
4.3	Specimen Warrant Certificate.	(1) [4.3]
4.4	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.	(2) [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]

74

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) [10.12]
10.4.1	Second Amended and Restated Voting Agreement included as Annex D of the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006 and incorporated by reference herein.	(5) [Annex D]
10.5	Lock-Up Agreement dated October 20, 2005 executed by the stockholders of RAM Energy, Inc.	(3) [10.11]
10.6	Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006.*	(1) [10.15]
10.6.1	First Amendment to Employment Agreement between Registrant and Larry E. Lee dated October 18, 2006, *	(9) [10.1]
10.7	Escrow Agreement by and among the Registrant, Larry E. Lee and Continental Stock Transfer & Trust Company dated May 8, 2006.	(1) [10.16]
10.8	Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.*	(1) [10.17]
10.90	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.	(8) [10.14]
10.14	Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004*	(12) [10.14]
21.1	Subsidiaries of the Registrant	(12) [21.1]
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	**

75

 * 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-K 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.

(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.

76

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 April 2, 2007.

RAM ENERGY RESOURCES, INC.
By	/S/    LARRY E. LEE
	Larry E. Lee, Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities indicated, on April 2, 2007.

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

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.	(1) [3.2]
4.1	Specimen Unit Certificate.	(1) [4.1]
4.2	Specimen Common Stock Certificate.	(1) [4.2]
4.3	Specimen Warrant Certificate.	(1) [4.3]
4.4	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.	(2) [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]

78

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) [10.12]
10.4.1	Second Amended and Restated Voting Agreement included as Annex D of the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006 and incorporated by reference herein.	(5) [Annex D]
10.5	Lock-Up Agreement dated October 20, 2005 executed by the stockholders of RAM Energy, Inc.	(3) [10.11]
10.6	Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006.*	(1) [10.15]
10.6.1	First Amendment to Employment Agreement between Registrant and Larry E. Lee dated October 18, 2006, *	(9) [10.1]
10.7	Escrow Agreement by and among the Registrant, Larry E. Lee and Continental Stock Transfer & Trust Company dated May 8, 2006.	(1) [10.16]
10.8	Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.*	(1) [10.17]
10.90	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.	(8) [10.14]
10.14	Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004*	(12) [10.14]
21.1	Subsidiaries of the Registrant	(12) [21.1]
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	**

79

 * 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-K 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.

(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.

80