10-K 1 reiform10k2001.txt 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, 2001 [ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Act of 1934 Commission File No. 333-42641 RAM ENERGY, INC. (Exact name of registrant as specified in its charter) Delaware 52-1535102 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 5100 East Skelly Drive, Suite 650 Tulsa, Oklahoma 74135 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (918) 663-2800 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: None 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 X 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 amendments to this Form 10-K. _____ As of March 31, 2002, there were outstanding 2,727,000 shares of the registrant's common stock, $.01 par value per share. The common stock is privately held by affiliates of the registrant. Documents incorporated by reference: None RAM ENERGY, INC. Annual Report on Form 10-K for the Year Ended December 31, 2001 Table of Contents Item Number Page PART I 1 Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Submission of Matters to a Vote of Security Holders . . . . . . . . . . . PART II 5 Market for Registrant's Common Equity and Related Matters . . . . . . . 6 Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . 7 Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . 7A Quantitative and Qualitative Disclosure About Market Risk . . . . . . . 8 Financial Statements and Supplementary Data . . . . . . . . . . . . . . 9 Changes in and Disagreements with Accountants on Accounting And Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . PART III 10 Directors and Executive Officers of Registrant . . . . . . . . . . . . . 11 Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . 12 Security Ownership of Certain Beneficial Owners and Management . . . . . 13 Certain Relationships and Related Transactions . . . . . . . . . . . . . PART IV 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . ATTACHMENT I 8 Audited Financial Statements . . . . . . . . . . . . . . . . . . . .Last PART I Item 1 Business General RAM Energy, Inc. is an independent, natural gas-focused company engaged in the exploration and production of natural gas and oil properties and the ownership and operation of a natural gas and oil pipeline system in northwest Oklahoma. Our core operating areas are the Permian Basin, Gulf Coast and Mid-Continent regions, where we have been active since 1987. Our management team has extensive technical and operating expertise in all areas of our geographic focus. From 1989 to November 1996, we primarily developed and operated natural gas and oil properties owned jointly with a limited partnership in which we and one of our affiliates were the general partners and an institutional investor was the sole limited partner. We acquired all of the partnership's natural gas and oil properties and other assets in November 1996. In February 1998, as part of our acquisition of Carlton Resources, Inc., we acquired natural gas and oil properties and a natural gas and oil pipeline. In 1999, we expanded our strategy to include exploration activities. Effective December 1, 2001, we sold to Carmen Acquisition Corp. a substantial number of our producing and non-producing natural gas and oil properties located in Oklahoma, Texas and New Mexico for $76.0 million. The sale involved approximately 86 Bcfe of proved reserves, of which approximately 27 Bcfe were undeveloped reserves. This sale included substantially all of our natural gas and oil properties in the Deep Anadarko Basin of southwest Oklahoma and northwest Texas and the Anadarko Shelf of western Oklahoma and the Texas panhandle, and a portion of our natural gas and oil properties in the Permian Basin area of west Texas and southeastern New Mexico. As a result of this sale, we have changed the focus of our business to accelerate our exploration program and expand our natural gas and oil pipeline system. This report includes our drilling results and production information with respect to our interests in the natural gas and oil properties that we sold to Carmen Acquisition until the effective date of sale. At December 31, 2001, our estimated net proved reserves were 46.9 Bcfe, of which 76% were natural gas, with a PV-10 Value of approximately $40.5 million before income taxes. Our proved developed reserves comprised 67% of our total reserves, and our reserve life for total proved reserves was approximately 16 years. At December 31, 2001, we operated 127 wells, representing approximately 60% of our PV-10 Value. In addition to our proved reserves, our wholly owned subsidiary, Great Plains Pipeline Company (formerly known as Magic Circle Energy Corporation), owns and operates a 182-mile natural gas and oil pipeline system and saltwater disposal operation located in the Anadarko Shelf area in Oklahoma. Our pipeline system generated approximately $2.9 million of cash flow from third parties during 2001. Through our Great Plains pipeline system, we purchase natural gas and oil at the well head and transport the production, with associated saltwater, to a collection and separation facility that we operate. From this point, the natural gas is delivered to a processing and compression facility operated by a third party operator. After processing, gas volumes are returned to us and sold into a variety of delivery points. Oil purchasing and saltwater disposal comprise an integrated operation whereby oil and saltwater are gathered at the lease and subsequently measured and transported to a central facility through the liquids gathering line. Upon separation, the oil is aggregated and sold at a central sales point to a number of crude purchasers, and the saltwater is disposed into our saltwater disposal well. Until 1998, we had grown principally through our acquisitions of producing properties and the further development of these acquired properties. We have acquired approximately $242.0 million of natural gas and oil properties since 1989. Since 1998, we have grown primarily through drilling of new wells. From 1989 through December 31, 2001, we drilled or participated in the drilling of 359 natural gas and oil wells with a 92% success rate. Since 1996, our historical average finding cost from all sources has been $ 0.79 per Mcfe including revisions of previous estimates. While we believe there are substantial additional acquisition, development and exploitation opportunities in our core areas, we intend to give greater emphasis to our exploration activities, including the acquisition of 2-D and 3-D seismic data, the internal generation of exploratory prospects and participation in exploratory drilling prospects generated by industry partners. In 2001, we drilled 17 wells with a success ratio of 82%. In addition, during 2001 we increased our proved reserves by 3.0 Bcfe, including revisions. For the year ended December 31, 2001, we had EBITDA of $14.7 million, or $1.99 per Mcfe, excluding the gain from our sale of natural gas and oil properties to Carmen Acquisition Corp. Also in 2001, we acquired leasehold acreage on internally generated exploration prospects. We currently have identified four exploration prospects on which we have acquired leasehold acreage and intend to drill all four of these prospects in 2002. We participated in 5 exploration projects in 2001; of these 3 were successful, 1 was a dry hole and 1 is still being evaluated. We intend to participate in the drilling of at least 4 new exploration projects in 2002. Forward-Looking Statements This document contains forward-looking statements under the meaning of the federal securities laws. All statements other than statements of historical facts are based on, or express, our expectations about future events, including statements regarding such matters as: - the drilling of wells; - the development of proved undeveloped reserves; - the amount, nature and timing of other capital expenditures; - the timing and amount of future production; - future cash flow and liquidity; - future operating costs and other expenses; - future oil and gas prices; - budgets; and - future property acquisitions. There are many factors that could cause our forward-looking statements to be incorrect, including the effect of economic conditions generally, the results of financing efforts, oil and gas price volatility, market demand, and other risks normally associated with the business of oil and gas drilling, production and marketing. Our forward-looking statements speak only as of the date made and we make no commitment to update these statements to reflect events or circumstances that may occur after this date. Strategy Our primary goal is to enhance stockholder value by finding and developing natural gas and oil reserves, increasing the value of our natural gas and oil pipeline system and reducing our indebtedness. Key elements of our strategy include the following: o Exploration Project Development. We are strongly committed to increasing our emphasis on exploration. We intend to participate in the drilling of at least 4 new exploration projects in 2002. We will continue to acquire, review and analyze 2D and 3D seismic data, and our experienced technical staff will continue to generate exploratory projects and evaluate opportunities proposed by third parties. o Expand Our Natural Gas and Oil Pipeline System. We will seek to expand our Great Plains pipeline system by connecting additional wells to increase the volume of natural gas and oil flowing through the system. We have identified a number of natural gas wells scheduled to be drilled this year and a large number of existing wells in our area of service that we have targeted for connection to our pipeline system. We believe that our pipeline's ability to transport oil and saltwater, in addition to natural gas, gives us a competitive edge over the pipelines that move only natural gas. o Develop and Exploit Existing Natural Gas and Oil Properties. We have identified numerous infill drilling, recompletion and workover opportunities on our properties through year-end 2003. We plan to selectively pursue these relatively lower-risk development activities. o Complete Selective Natural Gas and Oil Acquisitions. The members of our staff have many years of experience in acquiring and exploiting natural gas and oil properties in our core areas. Where feasible, we will seek additional acquisitions of producing properties that will provide us with opportunities for reserve additions and increased cash flow through operating improvements, production enhancement and additional development and exploratory drilling. Our Strengths: o Natural gas focus. At year-end 2001, approximately 76% of our proved reserves were natural gas. We will continue our focus on natural gas properties and prospects. We believe that the economics of natural gas are more favorable than oil. o Strong management and technical staff. Our management and technical staff possess many years of experience in the natural gas and oil industry, substantially all of which has been focused on operations in our two core areas. We believe that the knowledge, experience and expertise of our staff will continue to support our efforts to enhance stockholder value. o Drilling success rate. Since 1989, we have drilled or participated in the drilling of 359 natural gas and oil wells with a 92% success rate, most of which were development wells in our core areas. Because of our increased emphasis on exploration, in future periods, we expect our overall success rate to decline. o Great Plains pipeline system. Our Great Plains pipeline system is a 182-mile natural gas and oil pipeline system and saltwater disposal operation. As the owner and operator of this system, we purchase production from third parties at the wellhead, transport that production through our system and sell it at a price in excess of our cost. Our ownership of this system provides us with an asset that generates cash flow irrespective of fluctuations in prices for natural gas and oil. o Operating control. We currently are the operator of wells that represent 61% of our PV-10 Value, which allows us to control capital allocation and expenses, and the timing of additional development and exploitation of our producing properties. Recent Events Sale to Carmen Acquisition. Effective December 1, 2001, we sold to Carmen Acquisition Corp., a subsidiary of Chesapeake Energy Corporation, all of our producing and non-producing natural gas and oil properties located in 17 counties in Oklahoma, Texas and New Mexico. The base purchase price of $76.0 million was paid 85% in cash and 15% by the surrender of approximately $11.1 million principal amount of our 11 1/2% senior notes due 2008. The sale included approximately 86 Bcfe of proved reserves as of December 1, 2001, including approximately 27 Bcfe of undeveloped reserves. At the time of the sale, Carmen Acquisition owned 49.5% of our outstanding common stock. Immediately following the sale, Carmen Acquisition sold all of our common stock owned by it to our two principal shareholders, Larry E. Lee and William W. Talley II. As a result of this sale, Messrs. Lee and Talley own all of our outstanding common stock. At the closing, $7.5 million of the purchase price was deposited in escrow to secure post-closing claims for title and environmental defects and other matters. As of March 31, 2002, we have received approximately $3.0 million out of the escrow account. Under the terms of the Asset Purchase Agreement governing the sale, the final date for reconciling claims against the escrow account is April 3, 2002. Our properties sold to Carmen Acquisition included all of the properties that were subject to volumetric production payment in favor of a unit of Duke Energy Corporation, and Carmen Acquisition assumed all obligations under the production payment from and after the effective date of the sale. Proceeds of the sale to Carmen Acquisition, net of transaction costs, were used to fully repay our senior secured credit facility with Foothill Capital Corporation and to obtain a release of all mortgages and other liens securing that facility, to reduce our working capital deficit and to provide additional capital to fund our exploration and development activities. Summary Historical and Pro Forma Consolidated Financial and Other Data The following table sets forth: o certain historical consolidated financial and other data for us for the year ended December 31, 2001; and o certain pro forma financial and other data for the year ended December 31, 2001. We derived our summary historical consolidated financial data for the year ended December 31, 2001 from our audited consolidated financial statements included elsewhere in this report. The pro forma results of operations for the year ended December 31, 2001 give pro forma effect to our sale of certain of our natural gas and oil properties to Carmen Acquisition Corp. as if such sale had been completed and the proceeds from such sale had been applied as of January 1, 2001. The summary pro forma consolidated financial data are based on currently available information and assumptions that we believe are reasonable. The summary pro forma consolidated financial data do not purport to represent what our results of operations would have been if the pro forma transactions had been completed on the dates and for the periods indicated, nor do they purport to indicate our future results of operations. You should read the summary pro forma consolidated financial data in conjunction with "Selected Consolidated Financial and Other Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," and the financial statements and related notes that we include elsewhere in this report. (This space left blank intentionally)

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Reorganization of Certain Subsidiaries. In connection with the sale of our properties to Carmen Acquisition, we dissolved the wholly-owned limited partnership that owned our pipeline system and certain of our natural gas and oil properties. All of the oil and gas properties that had been owned by the dissolved limited partnership and its partners were either sold to Carmen Acquisition or distributed to RAM Energy. The pipeline system was distributed to and is now owned by and operated as the sole asset of our subsidiary, Great Plains Pipeline Company. Net Production, Unit Prices and Costs The following table presents certain information with respect to our natural gas and oil production, prices and costs attributable to all natural gas and oil properties owned by us for the periods shown. Average realized prices reflect the actual realized prices received by us, including the results of our hedging activities.

Producing Wells The following table sets forth the number of productive wells in which we owned an interest as of December 31, 2001. Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections and oil wells awaiting connection to production facilities. Wells that are completed in more than one producing horizon are counted as one well.

Acreage The following table sets forth our developed and undeveloped gross and net leasehold acreage as of December 31, 2001:

Approximately 85% of our net acreage was located in our core areas as of December 31, 2001. 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 natural gas and oil , regardless of whether or not such acreage is held by production or contains proved reserves. A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. Drilling Activities During the periods indicated, we drilled or participated in drilling the following wells.

Natural Gas and Oil Marketing and Hedging Our natural gas and oil production is sold primarily under market sensitive or spot price contracts. The revenues received by us from the sale of natural gas liquids are included in crude oil sales. We utilize "keep whole" contracts in which the Btu content of the natural gas liquids is added to the natural gas proceeds. During the year ended December 31, 2001, three purchasers accounted for approximately 69% of our natural gas and oil sales and one customer accounted for approximately 79% of our pipeline system revenue. We believe there are numerous other companies available to purchase our crude oil and natural gas and that the loss of any or all of these purchasers would not materially affect our ability to sell crude oil and natural gas. To reduce exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow, we periodically utilize various hedging strategies to manage the price received for a portion of our future natural gas and oil production. We have not established hedges in excess of our expected production. These strategies customarily involve contracts for specified monthly volumes at prices determined with reference to the natural gas futures market or swap arrangements that establish an index-related price above which we pay the hedging partner and below which we are paid by the hedging partner. These contracts allow us to predict with greater certainty the effective natural gas and oil prices to be received for our production and benefit us when market prices are less than the fixed prices under our hedging contracts. However, we will not benefit from market prices that are higher than the fixed prices in these contracts for our hedged production. At December 31, 2001, we had no hedging contracts in place. For the year ended December 31, 2001, our hedging strategies covered natural gas only and reduced our realized gas prices by $0.47 per Mcf. We have only limited involvement with derivative financial instruments, as defined in Statement of Financial Accounting Standards, or SFAS, No. 133 "Accounting for Derivative Instruments and Hedging Activities" and do not use them for trading purposes. Our objective is to hedge a portion of our exposure to price volatility from producing natural gas and oil. These arrangements expose us to credit risk of our counterparties and to basis risk. Recent Accounting Pronouncements A description of recent accounting pronouncements is contained in the footnotes to the audited consolidated financial statements. Employees As of December 31, 2001, we had 39 employees, six of whom were administrative, accounting or financial personnel and 33 of whom were technical and operations personnel. 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. Competition The natural gas and oil industry is highly competitive. We compete for the acquisition of natural gas and oil properties, primarily on the basis of the price to be paid for such properties, with numerous entities including major oil companies, other independent natural gas and oil 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 natural gas and oil 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. Item 2 Properties Principal Natural Gas and Oil Properties and Reserves We own and operate numerous natural gas and oil properties, with our proved reserves being located primarily in two core areas: the Permian Basin of west Texas and southeastern New Mexico and the Gulf Coast Area of southern Louisiana and Mississippi. Our natural gas and oil properties located in our two core areas represented approximately 76% of our PV-10 Value as of December 31, 2001. At December 31, 2001, we operated 127 productive wells and owned non-operated interests in 733 productive wells. Our interests in the wells we operate represented approximately 61% of our PV-10 Value at December 31, 2001. In the following table, we present information regarding our natural gas and oil reserves, including reserves in our two core areas, as of December 31, 2001. Net Proved Reserves for Principal Oil and Gas Properties

Permian Basin. Our properties in the Permian Basin area accounted for approximately 50% of our PV-10 Value at December 31, 2001. The Permian Basin area is located in West Texas and Southeastern New Mexico. In this core area, we own an interest in 41 natural gas and oil producing wells which we operate and 525 natural gas and oil producing wells operated by others. During the year ended December 31, 2001, we successfully drilled or participated in the drilling of one gross natural gas and oil well in this core area. In addition, during 2001 we successfully recompleted three wells in this core area. During 2001, our total net daily production from the Permian Basin area averaged approximately 3,178 Mcfe. The majority of our production in this core area is from the Canyon, Delaware and Strawn formations, from depths of 5,000 feet to 8,000 feet. Our principal fields in the Permian Basin area are the SCB and the Vinegarone Fields. We have identified 25 workover and recompletion opportunities, along with 24 infill drilling locations and three exploratory prospects in the Permian Basin area. At December 31, 2001, approximately 83% of the PV-10 Value of our proved, undeveloped reserves were in the Permian Basin area. Gulf Coast. Our properties in the Gulf Coast area accounted for approximately 26% of our PV-10 Value at December 31, 2001. The Gulf Coast area is located in south Louisiana and Mississippi. In this core area, we own and operate an interest in 30 natural gas and oil producing wells. We also own interests in 15 natural gas and oil producing wells operated by others. During the year ended December 31, 2001, we participated in the drilling of one successful natural gas well in this core area. During 2001, our total net daily production from the Gulf Coast area averaged approximately 1,390 Mcfe. The majority of our production in this core area is from the Camerina and Margunilina formations, from depths of 9,000 feet to 11,000 feet. Our principal field in the Gulf Coast area is the Egan Field. We have identified 16 workover and recompletion opportunities, no infill drilling locations and one potential exploratory prospect in the Gulf Coast area. At December 31, 2001, none of the PV-10 Value of our proved, undeveloped reserves were in the Gulf Cost area For 2001, we have scheduled the recompletion of four wells, and the drilling of one exploratory well in the Gulf Coast area. Natural Gas and Oil Reserves 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 natural gas and oil properties as of December 31, 1999, 2000 and 2001 were prepared by Garb Grubbs Harris & Associates (formerly Forrest A. Garb & Associates, Inc.). In the following table, PV-10 Value represents the present value of estimated future net revenues before income tax discounted at 10%, using prices in effect at the end of the respective periods presented and excluding the effects of hedging activities. In accordance with applicable requirements of the Securities and Exchange Commission, estimates of our proved reserves and future net revenues are made using applicable location differentials from published year-end spot natural gas and oil sales prices and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). The spot prices used in calculating PV-10 Value as of December 31, 2001 were $2.72 per Mcf of natural gas and $19.78 per Bbl of oil, compared to spot prices used as of December 31, 2000 of $9.98 per Mcf of natural gas and $23.75 per Bbl of oil. The prices at which we sell natural gas are determined on the first day of each month for the entire month. Estimated quantities of proved reserves and future net revenues therefrom are affected by natural gas and oil prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating natural gas and oil 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 natural gas and oil 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 natural gas and oil prices, operating costs and other factors, which revisions may be material. The PV-10 Value of our proved natural gas and oil reserves does not necessarily represent the current or fair market value of such proved reserves, and the 10% discount factor required by the Securities and Exchange Commission may not reflect current interest rates, our cost of capital or any risks associated with the development and production of our proved natural gas and oil reserves. In general, the volume of production from natural gas and oil properties declines as reserves are depleted. Except to the extent that we acquire properties containing proved reserves or conduct successful exploration and development activities, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent upon our level of success in finding or acquiring additional reserves.

Title to Properties We believe we have satisfactory title to our properties in accordance with standards generally accepted in the natural gas and oil industry. As is customary in the natural gas and oil industry, we make only a cursory review of title to farmout acreage and to undeveloped natural gas and oil 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, are typically 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 on substantially all of our producing properties. Prior to completing an acquisition of producing natural gas and oil leases, we perform a title review on a material portion of the leases. Our natural gas and oil 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. We lease all of our significant facilities. We believe that our facilities are adequate for our current needs. Regulation General. Various aspects of our natural gas and oil operations are subject to extensive and continually changing regulation, as legislation affecting the oil and gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and gas industry and its individual members. Regulation of Sales and Transportation of Natural Gas. The Federal Energy Regulatory Commission (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 oil and gas could be sold. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids 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 nonpipeline 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 it competes. 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 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 natural gas and oil 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 natural gas and oil operations, including its 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 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 natural gas and oil 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 natural gas and oil operations. The possible legislative reclassification of certain wastes generated in connection with oil and gas operations as "hazardous wastes" would have a significant impact on our operating costs , as well as the oil and gas industry in general. The cost of compliance with more stringent environmental laws and regulations, or the more vigorous administration and enforcement of those laws and regulations, could result in material expenditures by us to remove, acquire, modify, and install equipment, store and dispose of wastes, remediate facilities, employ additional personnel, and implement systems to ensure compliance with those laws and regulations. These accumulative expenditures could have a material adverse effect upon our profitability and future capital expenditures. Regulation of Natural Gas and Oil 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 utilization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and gas can be produced from our properties. Item 3 Legal Proceedings From time to time, we are party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. 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. Item 4 Submission of Matters to a Vote of Security Holders By written consent in lieu of meeting dated December 12, 2001, our shareholders re-elected Dr. William W. Talley II as a Class I Director for a term of three years and ratified the appointment of Ernst & Young as the Company's independent auditors for 2001. PART II Item 5 Market for Registrant's Common Equity and Related Stockholder Matters There is no established trading market for our common stock. As of March 31, 2002, there were two record holders of the common stock. We sold no equity securities during the three years ended December 31, 2001. On July 1, 1998 we granted to a person who was neither a director, officer nor employee of the Company options to purchase an aggregate of 50,000 shares of our common stock at an exercise price of $7.33 per share. The person to whom the options were granted is an "accredited investor" as that term is defined in Regulation D promulgated under the Securities Act. We relied on the exemption from registration provided by Regulation D. Item 6 Selected Financial Data The following tables set forth certain of our historical consolidated financial data with respect to each of the five years ended December 31, 2001 which have been derived from our audited consolidated financial statements. The historical consolidated financial data should be read in conjunction with Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and the audited consolidated financial statements and related notes thereto included in Item 8. We define EBITDA as earnings before interest income, interest expense, income taxes, depreciation and amortization, writedown of related oil and gas properties and equipment, extraordinary items and equity in loss of affiliates. EBITDA is not a measure of cash flow as determined by generally accepted accounting principles. EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with generally accepted accounting principals or as an indicator of a company's operating performance or liquidity. We believe that EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. In February 1998, we acquired Carlton Resources. Effective December 1, 2001, we sold to Carmen Acquisition Corp., a subsidiary of Chesapeake Energy Corporation, all of our producing and non-producing natural gas and oil properties located in 17 counties in Oklahoma, Texas and New Mexico. These transactions affect the comparability of the historical operating data for the period and the data are not necessarily indicative of our future performance. (This space left blank intentionally)

Selected Quarterly Financial Data (unaudited) (in thousands, except for per share amounts)

Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations General We are an independent oil and gas Company engaged in the acquisition, exploration and development of oil and gas properties and the production of oil and gas. Our oil and gas properties are located primarily in the Permian Basin of west Texas and New Mexico, and on-shore Louisiana and Mississippi. We also operate a natural gas and oil pipeline and salt water disposal system in Oklahoma. Historically, we have added reserves mainly through acquisitions of producing properties and the further development and exploitation of these properties. Beginning in 1999, we initiated an emphasis on exploration activities, including the acquisition of 2-D and 3-D seismic data and the internal generation of exploratory prospects. We continue to generate exploratory prospects with our in-house exploration staff and evaluate exploratory opportunities proposed by third parties. We intend to continue pursuing attractive natural gas and oil acquisitions, as well as development activities and exploratory drilling opportunities. Any future acquisitions or major development will require additional financing which will be dependent upon financing arrangements, if any, available at the time. In February 1998, we acquired Carlton Resources for approximately $41.6 million. In this acquisition we acquired proved reserves and a 182-mile pipeline system. In 1998, in connection with our purchase for $6.5 million of a one-half interest in certain proved undeveloped natural gas and oil properties, we made a $2.0 million investment in RVC Energy, Inc. RVC Energy then acquired the remaining one-half interest in the same proved undeveloped properties in which we had acquired interests, as well as other producing properties and the stock of another oil and gas company. We were designated as the operator of most of the properties owned directly or indirectly by RVC Energy. In 1999, RVC Energy's properties were sold to satisfy its indebtedness, and we wrote off our remaining $1.3 million investment in RVC. Effective December 1, 2001, we sold 86 Bcfe of our proved reserves to Carmen Acquisition Corp., an affiliate of Chesapeake Energy Corporation, for $76.0 million in a combination of cash and a surrender of approximately $11.1 million principal amount of our 11 1/2% senior notes due 2008. The natural gas reserves that we sold included certain reserves that were subject to a volumetric production payment in favor of Duke Energy. All our obligations to Duke Energy under the volumetric production payment were assumed by Carmen Acquisition . We used a portion of the net proceeds from the sale to fully repay our senior secured credit facility. Critical Accounting Policies Our revenue, profitability and cash flow are directly impacted by prevailing prices for natural gas and oil and the volumes of natural gas and oil we produce. In addition, our proved reserves and the rates of our natural gas and oil production will decline as natural gas and oil are produced unless we are successful in acquiring additional producing properties or conducting successful exploration and development drilling activities. The Company follows the entitlements method of accounting for natural gas and oil sales. We periodically utilize various hedging strategies to manage the price received for a portion of our future natural gas and oil production. These strategies customarily involve contracts for specified monthly volumes at prices determined with reference to the natural gas futures market or swap arrangements that establish an index-related price above which we pay the hedging partner and below which we are paid by the hedging partner. These contracts allow us to predict with greater certainty the effective natural gas and oil prices to be received for our production and benefit us when market prices are less than the fixed prices under our hedging contracts. However, we will not benefit from market prices that are higher than the fixed prices in these contracts for our hedged production. At December 31, 2001, we had no hedging contracts in place. For the year ended December 31, 2001, our hedging strategies covered natural gas only and reduced our realized gas prices by $0.47 per Mcf. We use the full cost method of accounting for our investment in natural gas and oil properties. Under the full cost method of accounting, all of our costs of acquisition, exploration and development of natural gas and oil 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 natural gas and oil prices that are not offset by other factors could result in a writedown for impairment of the carrying value of our natural gas and oil properties. Once incurred, a writedown of natural gas and oil properties is not reversible at a later date, even if our quantity estimates or natural gas or oil prices subsequently increase. Results of Operations Year Ended December 31, 2001 Compared to Year Ended December 31, 2000 Operating Revenues. Our operating revenues increased by $1.2 million, or 3% for the year ended December 31, 2001 compared to the same period in 2000. An increase of $1.5 million in the revenues of our gathering system primarily accounts for the increase in 2001 compared to 2000. Natural Gas and Oil Sales. The following table summarizes our natural gas and oil production volumes, average sales prices and period to period comparisons, including the effect on our oil and gas operating revenues, for the periods indicated:

Our oil and gas sales were lower during 2001 compared to 2000 as a result of a 13% increase in realized prices, offset by a 12% decrease in production, both on an Mcfe basis. Our average daily production was 20.2 MMcfe in 2001 compared to 23.0 MMcfe for 2000. Our natural gas production decreased by 13% and oil production decreased by 11% for the comparable periods. We realized an average sales price for natural gas of $3.28 per Mcf for 2001, compared to $2.64 per Mcf for 2000, an increase of 24%. Our average realized sales price for oil for 2001 was $24.09 per Bbl, compared to $27.38 per Bbl for 2000, a 12% decrease. Our natural gas sales are computed net of gains or losses from fixed-price swaps for physical deliveries during the reporting period. Our natural gas sales were reduced by $2.7 million (or $0.47 per Mcf) from these transactions in 2001 compared to $6.1 million in decreases (or $0.92 per Mcf) for 2000. Pipeline System. Our pipeline system revenue was $15.6 million for the year ended December 31, 2001, compared to $14.1 million for 2000, an increase of $1.5 million, or 11%. We are obligated to deliver 10,000 Mmbtu's per day at the tailgate of the system, and we purchase natural gas from wells connected to the system to satisfy that obligation. In addition, we purchase and re-sell oil and dispose of salt water. Our third party purchases and system operating costs were $12.7 million for the year of 2001, compared to $10.9 million for 2000, an increase of $1.9 million, or 17%. Volumes of gas, oil, and water disposed were unchanged for 2001 compared to 2000; higher prices account for the increases in both revenues and costs. The operating margin of the system decreased $363,000 (or 11%) to $2.9 million for the year 2001 compared to $3.2 million for the year 2000. Natural gas and Oil Production Taxes. Our natural gas and oil production taxes were the same amount for the year ended December 31, 2001, compared to the year of 2000. On an Mcfe basis, our natural gas and oil production taxes increased to $0.37 per Mcfe for the year 2001, compared to $0.33 for the year 2000. This increase was caused by prior year adjustments submitted by outside operators and a provision for non-collectibility of production tax credits recorded in prior years. Natural Gas and Oil Production Expense. Our natural gas and oil production expense decreased by $1.0 million, or 20%, for the year ended December 31, 2001, compared to the same period in 2000. Our natural gas and oil production expense was $0.81 per Mcfe for 2001, a 37% increase from $0.59 per Mcfe compared to 2000. This increase was due to increased costs to maintain production, settlement of prior years' charges from outside operators, and plugging of two salt water disposal wells during the year 2001 compared to costs incurred for the year 2000. Amortization and Depreciation Expense. Our amortization and depreciation expense decreased by $325,000, or 3% for 2001 compared to 2000, and was $1.32 per Mcfe for 2001, an increase of $0.17, or 10% compared to the $1.20 per Mcfe for the year 2000. Contract Termination and Severance. As a result of the expiration of employment agreements with our three senior vice-presidents, we recorded $730,000 in contract terminations. Due the sale of a substantial number of our natural gas and oil properties, we reduced our office staff and recorded $374,000 in severance pay relating to these terminations. During 2000, we closed our Oklahoma City accounting office and our Midland, Texas operations office. Severance pay and other costs incidental to these office closings totaled $337,000. In December 2000, we terminated the severance agreement with the Chairman of the Board and entered into a new employment agreement with him. Total benefits paid in connection with the contract termination were $884,000. General and Administrative Expense. Our general and administrative expense increased to $4.1 million, an increase of $708,000, or 21% in 2001 compared with $3.4 million in 2000. This increase is due primarily bonuses paid to our executive officers during 2001. Gain on Sale of Natural Gas and Oil Properties. The gain on the sale of natural gas and oil properties is comprised of the purchase price of $76.0 million, less costs of sale allocated from the full-cost pool of $56.6 million, less other costs and purchase price adjustments of $2.1 million. Interest Expense. Our interest expense decreased $941,000 to $14.5 million for 2001 compared to $15.5 million for 2000. During 2001, we had lower average outstanding indebtedness on our senior notes due to our receiving approximately $11.1 million of our 11 1/2% senior notes with the sale of natural gas and oil properties. On our credit facility, interest expense decreased due to lower average outstanding balances as the facility was fully repaid in December 2001, and lower effective interest rates. Income Taxes. In connection with our acquisition of Carlton Resources in early 1998, we recorded deferred income tax liabilities related to the excess of financial bases of net assets acquired (principally properties and equipment) over their respective bases for income tax purposes. Prior to this acquisition, we offset our existing net operating loss carryforwards and the provision or credit for income taxes by valuation allowances. Our net liability is the result of our providing for income taxes or credits after the date of our acquisition of Carlton Resources. Extraordinary Items. In conjunction with the sales of natural gas and oil properties, the buyer surrendered approximately $11.1 million principal amount of our 11 1/2% senior notes, and with the cash proceeds we retired our revolving credit facility. Extraordinary items for 2001 includes a proportionate write-off of deferred offering costs and original issue discount on the senior notes surrendered, all remaining deferred loan costs associated with our revolving credit facility, along with a prepayment penalty associated with the credit facility, which after tax effects, totaled $1.1 million loss. During 2000, we purchased $5.0 million principal amount of our senior notes for $3.3 million. After adjustments for proportionate offering costs, accrued interest and tax effects, we reported a gain of $916,000. Net Loss. Due to the factors described above, we had net income of $3.8 million in 2001, compared to a net loss of $4.4 million in 2000. Year Ended December 31, 2000 Compared to Year Ended December 31, 1999 Operating Revenues. Our operating revenues increased by $6.9 million, or 21% for the year ended December 31, 2000 compared to the same period in 1999. Natural Gas and Oil Sales: The following table summarizes our natural gas and oil production volumes, average sales prices and period to period comparisons, including the effect on our oil and gas operating revenues, for the periods indicated:

Our natural gas and oil sales were higher during 2000 compared to 1999 as a result of a 38% increase in realized prices, partially offset by a 19% decrease in production, both on an Mcfe basis. Of the decrease in production, approximately 28% was due to the production payment we entered into at the end of September, 1999, with 785 MMcf delivered for the year of 2000 compared to 208 MMcf delivered in the last quarter of 1999. Our average daily production was 23.1 MMcfe in 2000 compared to 28.6 MMcfe for 1999. Our natural gas production decreased by 20% and oil production decreased by 19% for the comparable periods. We realized an average sales price for natural gas of $2.64 per Mcf for 2000, compared to $2.08 per Mcf for 1999, an increase of 27%. Our average realized sales price for oil for 2000 was $27.38 per Bbl, compared to $16.13 per Bbl for 1999, a 70% increase. Our natural gas sales are computed net of gains or losses from fixed-price swaps for physical deliveries during the reporting period. Our natural gas sales were reduced by $6.1 million (or $0.92 per Mcf) from these transactions in 2000 compared to $362,000 in decreases (or $0.04 per Mcf) for 1999. Pipeline System. Our pipeline system revenue was $14.1 million for the year ended December 31, 2000, compared to $9.2 million for 1999, an increase of $4.9 million, or 53%. We are obligated to deliver 10,000 Mmbtu's per day at the tailgate of the system, and we purchase natural gas from wells connected to the system to satisfy that obligation. In addition, we purchase and re-sell oil and dispose of salt water. Our third party purchases and system operating costs were $10.9 million for the year of 2000, compared to $7.0 million for 1999, an increase of $3.8 million, or 54%. Volumes of gas, oil, and water disposed were virtually unchanged for 2000 compared to 1999; higher prices account for the increases in both revenues and costs. The operating margin of the system increased $1.0 million (or 45%) to $3.2 million for the year 2000 compared to $2.2 million for the year 1999. Natural Gas and Oil Production Taxes. Our oil and gas production taxes increased by $795,000, or 40%, for the year ended December 31, 2000, compared to the same period in 1999. This increase was due entirely to higher wellhead oil and gas revenue during 2000 compared to 1999. Natural Gas and Oil Production Expense. Our oil and gas production expense decreased by $832,000, or 14%, for the year ended December 31, 2000, compared to the same period in 1999. Our oil and gas production expense was $0.59 per Mcfe for 2000, a 5% increase from $0.56 per Mcfe compared to 1999, due to reduced production volumes in 2000 compared to 1999. Amortization and Depreciation Expense. Our depreciation and amortization expense decreased by $2.9 million, or 22% for 2000 compared to 1999, and was $1.20 per Mcfe for 2000, a decrease of $0.04, or 3% compared to the $1.24 per Mcfe for 1999. Our oil and gas amortization expense was $0.82 per Mcfe for 2000 compared with $0.92 per Mcfe for 1999, an 11% decrease, due to increased reserve quantities at the end of 2000 compared to the end of 1999. Contract Termination and Severance. During the first quarter of 2000, we closed our Oklahoma City accounting office and our Midland, Texas operations office. Severance pay and other costs incidental to these office closings totaled $337,000. In December 2000, we terminated the severance agreement with the Chairman of the Board and entered into a new employment agreement with him. Total benefits to be paid in connection with the contract termination were $884,000. General and Administrative Expense. Our general and administrative expense decreased to $3.3 million, a decrease of $1.1 million, or 24% in 2000 compared with $4.4 million in 1999. This decrease is due primarily to the office closings described above, and decreased costs of managing RVC Energy, a partially owned unrestricted affiliate, for which we received $600,000 in management fees during 1999. Interest Expense. Our interest expense increased $832,000 to $15.5 million for 2000 compared to $14.6 million for 1999. During 2000, we had lower average outstanding indebtedness on our senior notes due to our purchase of $5.0 million principal amount of senior notes during August, 2000, offset by higher outstanding balances and higher effective interest rates under our credit facility. Equity in Loss of Affiliate. During 1999 we wrote off our remaining investment of $1.3 million in RVC Energy. Income Taxes. In connection with our acquisition of Carlton Resources in early 1998, we recorded deferred income tax liabilities related to the excess of financial bases of net assets acquired (principally properties and equipment) over their respective bases for income tax purposes. Prior to this acquisition, we offset our existing net operating loss carryforwards and the provision or credit for income taxes by valuation allowances. Our net liability is the result of our providing for income taxes or credits after the date of our acquisition of Carlton Resources. Extraordinary Item. During 2000, we purchased $5.0 million principal amount of our senior notes for $3.3 million. After adjustments for proportionate offering costs, accrued interest and tax effects, we reported a gain of $916,000. Net Loss. Due to the factors described above, our net loss decreased by $4.8 million, from a net loss of $9.2 million in 1999 to a net loss of $4.4 million in 2000. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires that our management 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Liquidity and Capital Resources As of December 31, 2001, we had cash and cash equivalents of $19.9 million, and in conjunction with the sales of natural gas and oil properties previously discussed, $6.1 million in an escrowed cash account discussed further below. As of December 31, 2001, we had $91.1 million ($92.0 million excluding the original issue discount) of indebtedness outstanding evidenced by our senior notes due 2008 issued in February 1998. Under the terms of the indenture governing our outstanding senior notes, we currently may incur up to $30.0 million in permitted indebtedness in addition to the indebtedness outstanding under our senior notes. Historically, we have funded our business activities with operating cash flow and reserve-based bank borrowings. From time to time we engage in discussions relating to potential acquisitions of natural gas and oil properties or companies engaged in the natural gas and oil business. We have no present agreement, commitment or understanding with respect to any material acquisitions. Any future acquisitions may require that we obtain additional financing that will depend upon financing arrangements, if any, available at the time. Sale to Carmen Acquisition. Effective December 1, 2001, we sold to Carmen Acquisition Corp., a subsidiary of Chesapeake Energy Corporation, all of our producing and non-producing oil and gas properties located in 17 counties in Oklahoma, Texas and New Mexico. The base purchase price of $76 million (before customary closing and post-closing adjustments) was paid 85% in cash and 15% by the surrender of approximately $11.1 principal amount of our 11 1/2% senior notes due 2008, valued at par. The sale included approximately 86 Bcfe of proved reserves as of December 1, 2001, including approximately 27 Bcfe of undeveloped reserves. At the time of the sale, Carmen Acquisition owned 49.5% of our outstanding common stock. Immediately following the sale, Carmen Acquisition sold all of our common stock owned by it to our two major shareholders, Larry E. Lee and William W. Talley II. As a result of this sale, Messrs. Lee and Talley currently own all of our outstanding common stock. At the closing, $7.5 million of the purchase price (85% in cash and 15% in our senior notes) was deposited in escrow to secure post-closing claims for title and environmental defects and other matters. As of March 31, 2002, we have received approximately $3.0 million (85% in cash and 15% in senior notes) out of the escrow account. Under the terms of the Asset Purchase Agreement governing the sale, the final date for reconciling claims against the escrow account is April 3, 2002. Our properties sold to Carmen Acquisition included all of the properties that were subject to volumetric production payment in favor of a unit of Duke Energy Corporation. As part of the sale, Carmen Acquisition assumed all of our obligations under the production payment from and after the effective date of the sale. We used the proceeds of our sale to Carmen Acquisition, net of transaction costs, to fully repay our senior secured credit facility with Foothill Capital Corporation and to obtain a release of all mortgages and other liens securing that facility, to reduce our working capital deficit and to provide additional capital to fund our exploration and development activities. Credit Facility. In December 1999, we obtained a $30.0 million, senior secured, revolving credit facility from Foothill Capital Corporation, a Wells Fargo company. In December 2001 we used a portion of the proceeds from our sale of gas and oil properties to Carmen Acquisition to fully pay all sums outstanding under our credit facility, and such credit facility was terminated and all liens securing the facility were released. Senior Notes. We have outstanding $92.0 million aggregate principal amount of senior notes, which mature in February 2008. The notes were issued under an indenture with United States Trust Company of New York, as Trustee. The notes bear interest at an annual rate of 11 1/2%, payable semi-annually on each February 15 and August 15. Production Payment. In September 1999, we entered into a volumetric production payment agreement with a unit of Duke Energy Corporation, pursuant to which we will deliver to Duke Energy 2.8 Bcf of natural gas produced from certain of our properties over a 5-year period. We received $5.0 million of consideration in this transaction. In connection with our sale of oil and gas properties to Carmen Acquisition in December 2001, Carmen Acquisition assumed our obligations under the Duke Energy production payment. Cash Flows from Operating Activities. Our cash flows from operating activities are comprised of three main items: net income or (loss), adjustments to reconcile net loss to cash provided (used) before changes in working capital, and changes in working capital. For the year ended December 31, 2001, our net income was $8.2 million more than the $4.4 million net loss of 2000. Adjustments (primarily non-cash items such as depreciation and amortization and deferred income taxes) were $(3.6) million for the year of 2001 compared to $6.1 million for 2000, a decrease of $9.6 million. Working capital changes for the year 2001 used cash of $2.0 million compared with cash provided of $4.2 million for 2000. Decreases in accounts receivable, accounts payable and natural gas and oil proceed due others caused this change. For the year ended December 31, 2001, in total, our cash flows from operating activities provided $2.2 million in cash compared to $5.9 million provided in 2000. Cash Flow from Investing Activities. For the year ended December 31, 2001, our net cash provided by investing activities was $44.5 million, including $55.9 million from sales of natural gas and oil property sales to Carmen Acquisition Corp., offset by natural gas and oil property additions of $11.0 million. For the year ended December 31, 2000, our net cash used in investing activities was $4.8 million, including $2.8 million of property sales, offset by $6.9 million for natural gas and oil property additions. Our budget for capital expenditures in 2002 is approximately $7.0 million provided current oil and gas prices realized are maintained. Item 7A Quantitative and Qualitative Disclosures about Market Risk The carrying amounts reported in our balance sheets for cash and cash equivalents, trade receivables and payables, installment notes and variable rate long-term debt approximate their fair values. The carrying value of our senior notes exceeded their fair value at December 31, 2000 and 2001 by approximately $23.2 million and $23.9 million, respectively, based on quoted market prices. 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 borrowings. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes. Commodity Price Risk Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. 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 natural gas and oil that we can economically produce. We currently sell most of our natural gas and oil production under price sensitive or market price contracts. To reduce exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow, we periodically utilize various hedging strategies to manage the price received for a portion of our future natural gas and oil production. We have not established hedges in excess of our expected production. These strategies customarily involve contracts for specified monthly volumes at prices determined with reference to the natural gas futures market or swap arrangements that establish an index-related price above which we pay the hedging partner and below which we are paid by the hedging partner. These contracts allow us to predict with greater certainty the effective natural gas and oil prices to be received for our production and benefit us when market prices are less than the fixed prices under our hedging contracts. However, we will not benefit from market prices that are higher than the fixed prices in these contracts for our hedged production. At December 31, 2001, we had no hedging contracts in place. For year ended December 31, 2001, our hedging strategies reduced our realized gas prices by $0.47 per Mcf. Item 8 Financial Statements and Supplementary Data See last section of this report Item 9 Changes and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable. (This space left blank intentionally) PART III Item 10 Directors and Executive Officers of the Registrant The following table sets forth names, ages and titles of our directors and executive officers of RAM Energy, Inc.

William W. Talley II, Ph.D. has been our Chairman of the Board and a director since we were incorporated in 1987 and was Chief Executive Officer from 1987 to 1989 and from 1992 to October 31, 1997. Dr. Talley served as the Society of Petroleum Engineers' Distinguished Lecturer on natural gas marketing and pricing in 1987 and 1988 and was Vice President and director of the Independent Petroleum Association of America in 1987. Dr. Talley has been an officer and a principal of the RAM Group, Ltd., an energy and management-consulting firm, since 1974. He is a registered professional engineer. Larry E. Lee has been our President and a director since we were incorporated in 1987. Mr. Lee served as our Chief Executive Officer from 1989 to 1992 and has served in such capacity since November 1, 1997. Mr. Lee is a member of the Oklahoma Independent Petroleum Association and of the Independent Petroleum Association of America. He served as a director of the Independent Petroleum Association of America from 1990 to 1992. Mr. Lee has been an officer and a principal of the RAM Group, Ltd. since 1984. Gerald R. Marshall became a director in December 1997. Since October 1996, Mr. Marshall has served as Vice Chairman of the Midland Group, an Oklahoma-based financial services organization. Since December 1993, Mr. Marshall has served as President and Chief Executive Officer of Midland Asset Management Co., an asset management and financial consulting firm. He has served as Chairman and Chief Executive Officer of RAM Management Associates, Inc., a management contractor for the Resolution Trust Corporation, since March 1990. John M. Reardon became a director in December 1997 and served as an adviser to our Board of Directors from August 1994 until December 1997. Mr. Reardon has been President and Chief Executive Officer of Valencia Bank & Trust (formerly Valencia National Bank), of Santa Clarita, California, since August 1994. From 1991 to August 1994, he was Senior Vice President of RAMCO Oil & Gas, Inc., a former subsidiary of the Company, and of RAM Management Associates, Inc. From 1987 to 1991, Mr. Reardon was a Senior Vice President of Wells Fargo Bank. John M. Longmire became a Senior Vice President in December 1997 and had been a Vice President of the Company since 1994. Mr. Longmire has been our Chief Financial Officer, Treasurer and Secretary since August 1994 and was our Controller from 1990 to February 1994. Previously, he held various financial management positions with Texas International Company, Amarex, Inc. and Union Oil Company of California. Mr. Longmire is a Certified Public Accountant. Larry G. Rampey became a Senior Vice President in December 1997 and had been a Vice President since 1989. From 1972 to 1989, Mr. Rampey held the positions of Vice President of International Operations, Vice President of Domestic Operations and staff engineer for Reading & Bates Petroleum Co. Drake N. Smiley became a Senior Vice President in December 1997 and had been a Vice President since February 1997. Mr. Smiley was our Vice President - Land and Legal from 1989 to 1994. From 1994 until he rejoined us in 1997, Mr. Smiley served as Vice President - Land of Continental Resources, Inc., an independent oil and gas company. From 1980 to 1989, he was employed by Reading & Bates Petroleum Co., serving as Manager of Land. Mr. Smiley is a member of the Oklahoma and Tulsa County Bar Associations. Our directors are divided into three classes, with each class having as equal a number of directors as practicable. The directors are elected on a staggered basis for three-year terms. One class stands for re-election at each annual meeting of stockholders. The terms of Mr. Lee and Mr. Marshall will expire in 2002 and the term of Mr. Reardon will expire in 2003. Dr. Talley's term will expire in 2004. Our executive officers serve at the discretion of the Board of Directors. Dr. Talley and Mr. Lee beneficially own and were formerly executive officers of Jobs for St. Landry Parish, Inc., d/b/a Standard Fittings Company ("Standard Fittings"), a manufacturer of pipe fittings. Standard Fittings filed a petition pursuant to Chapter 11 of the U.S. Bankruptcy Code in January 1997 in the U.S. Bankruptcy Court for the Western District of Louisiana. The Chapter 11 proceeding was dismissed in June 1997. Dr. Talley and Mr. Lee collectively owned 49.5% of the outstanding common stock and served on the Board of Directors of Oklahoma Double R Corporation, a Delaware corporation ("ODRC"). Dr. Talley and Mr. Lee were the senior executive officers of ODRC. ODRC was special general partner of a limited partnership in which an institutional investor was the sole limited partner. We managed the limited partnership. Upon dissolution of the partnership in 1997, all of ODRC's interest in the properties of the partnership was distributed to us in partial satisfaction of outstanding indebtedness from ODRC to us. ODRC had no other assets. During 1999, ODRC filed a petition pursuant to Chapter 7 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Western District of Oklahoma, which proceeding was fully administered and concluded in 2001. Item 11 Executive Compensation The following table sets forth for the years indicated the cash compensation of our chief executive officer and each of our other four most highly compensated executive officers as of December 31, 2001.

Directors' Compensation We pay our non-employee directors and Dr. Talley an annual fee of $24,000 plus $1,000 for each meeting attended, with a maximum of six meetings per year. Mr. Lee, as our President and Chief Executive Officer, does not receive any director's fee. We reimburse all of our directors for travel and other expenses. Compensation Committee, Interlocks and Insider Participation The Compensation Committee of our board of directors determines the compensation of our executive officers. During 2001, the members of the Compensation Committee were Gerald R. Marshall and John M. Reardon, all of whom are members of our board of directors. In addition, one of our former directors, M. Helen Bennett, resigned as a member of our Compensation Committee, effective March 30, 2001. In August 2001, Dr. Talley became a member of our Compensation Committee. Employment and Severance Agreements We have an employment agreement with Mr. Lee effective January 1, 2002 for an initial term expiring on December 31, 2004, subject to annual extensions of one year, at an annual salary of $321,550 and an annual bonus to be determined by the Board. Under this agreement, Mr. Lee's employment may be terminated by us or Mr. Lee at any time. Upon Mr. Lee's death, his representatives or, upon his disability, Mr. Lee, will receive accrued but unpaid salary, bonus and benefits, a pro rata share of any bonus paid for the immediately preceding year, one year's salary and an amount equal to the highest bonus paid to him during the term of the agreement. In the event of Mr. Lee's disability, he will continue to be entitled to receive benefits for the remainder of the agreement. If Mr. Lee ceases to be an employee other than by reason of death, disability, for cause or by voluntary resignation, he is entitled to receive his accrued but unpaid salary and benefits, an amount equal to a pro rata share of any bonus paid for the immediately preceding year, plus an amount equal to three times his base salary. We have an employment agreement with Dr. Talley under which he serves as Chairman of the Board of Directors of the Company at a salary of $65,000 per year, plus a fee of $1,000 per board meeting up to a maximum of six meetings per year. This agreement may be terminated by Dr. Talley or by us at any time. Upon termination of this employment agreement, we have no obligation to make any severance payment to Dr. Talley. The employment agreement became effective January 1, 2001, upon termination of the special severance agreement between us and Dr. Talley that had been in existence since December 1997. Under that special severance agreement, Dr. Talley received a base salary of $240,000 per year, plus any annual bonus awarded by the Board. Upon termination of the special severance agreement, we agreed to pay Dr. Talley the severance benefits provided in the special severance agreement, totaling $884,000, all of which was treated as an expense in our consolidated financial statements for the year ended December 31, 2000. The sum of $164,000 was paid in December 2000, and the remaining $720,000 was paid during 2001. We had employment and severance agreements with Messrs. Longmire, Rampey and Smiley. Each of these agreements expired December 31, 2001. As a result of the expiration of these agreements, we incurred non-removal payment obligations to Messrs. Longmire, Rampey and Smiley of $225,213, $254,436 and $225,213, respectively. These amounts were paid in January, 2002. Stock Incentive Plan Our 1998 Stock Incentive Plan (the "Plan") authorizes the grant of nonqualified stock options, incentive stock options and restricted stock awards to employees and non-employee directors. The purpose of the Plan is to create incentives designed to motivate our employees and directors to exert maximum efforts toward our success and growth, and to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to our success. The Plan is administered by our Compensation Committee; however, awards under the Plan to members of the Compensation Committee are made by the full Board (whether the Compensation Committee or the Board, the "Committee"). The maximum number of shares of common stock for which options and restricted stock awards may be granted under the Plan is 550,000, subject to adjustment in the event of any stock dividend, stock split, recapitalization or reorganization or certain business combinations. Shares subject to previously expired or terminated options or other forfeited awards which did not result in the issuance of shares become available again for awards under the Plan. The shares to be issued under the Plan may be newly issued shares, treasury shares or shares acquired privately or by open-market purchases. The number of shares and other terms of each grant are determined by the Committee; provided that the shares subject to stock options granted under the Plan and the shares of restricted stock awarded under the Plan in any year to any participant may not exceed an aggregate of 25,000. Awards under the Plan may, in the discretion of the Committee, provide for immediate vesting upon a change of control (as defined in the Plan). The price payable upon the exercise of both incentive and nonqualified stock options may not be less than 100% of the fair market value of the common stock at the time of grant or, in the case of an incentive stock option granted to an employee owning stock possessing more than 10% of the total combined voting power of all of our classes of stock (a "10% Shareholder"), 110% of the fair market value of the common stock on the date of grant. Incentive stock options may be granted only to employees, and the aggregate exercise price of all incentive stock options under all plans becoming exercisable for the first time by an employee during any calendar year may not exceed $100,000. Each option granted under the Plan will expire on the date specified by the Committee, but, with respect to incentive stock options, not more than ten years from the date of grant or, in the case of a 10% Shareholder, not more than five years from the date of grant. Unless the Committee otherwise provides, a stock option will terminate three months (one year in the event of an optionee's disability or three years in the event of an optionee's death) after the optionee's termination of employment or termination as a director. In no event, however, will an option be exercisable after its expiration date. The Committee has the power to accelerate the vesting of options not exercisable on the optionee's termination date. The exercise price of an option granted under the Plan may be paid in cash, shares of common stock having a fair market value equal to the exercise price (either shares then owned by the optionee or to be issued upon exercise of the option) or a combination of cash and common stock. In addition, an optionee may utilize a broker to effect a contemporaneous sale of sufficient shares subject to the option to pay the exercise price by following the procedure set forth in the Plan. Restricted stock awards are subject to such terms, conditions, restrictions and/or limitations as the Committee deems appropriate including, but not limited to, restrictions on transferability and continued employment (or service as a director in the case of non-employee directors). Outstanding options become nonforfeitable and exercisable in full immediately prior to our liquidation, dissolution, merger, consolidation, or the sale of all or substantially all of our assets if provision is not made in such transaction for the assumption by the acquiror of outstanding unvested options granted under the Plan or the substitution for new options. Unexercised outstanding options will terminate upon the consummation of our dissolution, liquidation, merger, consolidation or sale of assets. The Plan may be terminated or amended by our Board of Directors at any time, subject to stockholder approval in the case of amendments to increase the aggregate number of shares of common stock subject to the Plan or to permit options with below-market exercise prices. If not earlier terminated, the Plan expires in 2008. No stock options or restricted stock awards have yet been granted to officers or directors under the Plan. Officer and Director Liability As permitted by the provisions of the Delaware General Corporation Law, our certificate of incorporation, eliminates in certain circumstances the monetary liability of directors of the Company for a breach of their fiduciary duty as directors. These provisions do not eliminate the liability of a director for: o a breach of the director's duty of loyalty to us or our stockholders, acts or omissions by a director not in good faith or which involve intentional misconduct or a knowing violation of law, o liability arising under Section 174 of the Delaware General Corporation Law (relating to the declaration of dividends and purchase or redemption of shares in violation of the Delaware General Corporation Law) or o any transaction from which the director derived an improper personal benefit. In addition, these provisions do not eliminate the liability of a director for violations of federal securities law, nor do they limit our rights or those of our stockholders, in appropriate circumstances, to seek equitable remedies such as injunctive or other forms of non-monetary relief. These remedies may not be effective in all cases. Our certificate of incorporation and bylaws provide that we shall indemnify all of our directors and officers to the full extent permitted by the Delaware General Corporation Law. Under these provisions, any director or officer, who in his capacity as such, is made or threatened to be made a party to any suit or proceeding, may be indemnified if the Board of Directors determines the director or officer acted in good faith and in a manner he reasonably believed to be in or not opposed to our best interest. The certificate of incorporation, bylaws and the Delaware General Corporation Law further provide that such indemnification is not exclusive of any other rights to which such individuals may be entitled under the certificate of incorporation, bylaws, any agreement, vote of stockholders or disinterested directors or otherwise. We entered into indemnity agreements with each of our directors and executive officers. Under each indemnity agreement, we will pay on behalf of the indemnitee, and the indemnitee's executors, administrators and heirs, any amount which he or she is or becomes legally obligated to pay because of: o any claim or claims from time to time threatened or made against him or her by any person because of any act or omission or neglect or breach of duty, including any actual or alleged error or misstatement or misleading statement, which he or she commits or suffers while acting in his or her capacity as our director and/or officer of one of our affiliates. o being a party, or being threatened to be made a party, to any threatened, pending or contemplated action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she is or was our officer, director, employee or agent or one of our affiliates or is or was serving at our request as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise. The payments which we will be obligated to make pursuant to such indemnity agreement include damages, charges, judgments, fines, penalties, settlements and court costs, costs of investigation and costs of defense of legal, equitable or criminal actions, claims or proceedings and appeals therefrom, and costs of attachment, supersedeas, bail, surety or other bonds. We also intend to provide liability insurance for each of our directors and executive officers. Item 12 Security Ownership of Certain Beneficial Owners and Management The following table sets forth certain information regarding the beneficial ownership of our common stock as of December 31, 2001 by: o each of our directors who own common stock, o each of our Named Executive Officers who own common stock, o each person known or believed by us to own beneficially 5% or more of our common stock, and o all directors and executive officers as a group. Unless otherwise indicated, each person has sole voting and dispositive power with respect to such shares.

Item 13 Certain Relationships and Related Transactions We completed the redemption of all of our Series B Preferred Stock in February 1998. The Series B Preferred Stock was issued in 1987 and 1988 for $10.00 per share. Dr. Talley, Mr. Lee, one of our former directors, Mrs. Bennett, and one other person beneficially owned in equal amounts all of the issued and outstanding shares of Series B Preferred Stock. The redemption price for each share of Series B Preferred Stock was $10.00 per share, resulting in the payment of $174,130 to each holder, for an aggregate redemption price of $696,520. PART IV Item 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a)(1) The following financial statements of RAM Energy, Inc. are included in Item 8: Report of Independent Auditors Consolidated Balance Sheets as of December 31, 2000 and 2001. Consolidated Statements of Operations of the Company for the years ended December 31, 1999, 2000, and 2001. Consolidated Statements of Stockholders' Deficiency for the years ended December 31, 1999, 2000, and 2001. Consolidated Statements of Cash Flows of the Company for the years ended December 31, 1999, 2000, and 2001. Notes to Consolidated Financial Statements (2) Not applicable (3) Exhibits Exhibit No. Description of Exhibit ------- ---------------------- 3.1 Company's Amended and Restated Certificate of Incorporation (1) 3.2 Company's Amended and Restated Bylaws (1) 4.1 Indenture dated as of February 24, 1998 among the Company, as issuer, RB Operating Company and RLP Gulf States, L.L.C., as Subsidiary Guarantors, and United States Trust Company of New York, as trustee (1) 4.2 Form of 11-1/2% Senior Notes due 2008 (included in Exhibit 4.1) (1) 4.3 Supplemental Indenture entered into February 24, 1998 by the Registrant, the Subsidiary Guarantors, the Additional Guarantors and United States Trust Company of New York, as Trustee (2) 10.4 RAM Energy 1998 Stock Incentive Plan* (1) 10.5 Special Severance Agreement by and between William W. Talley II and the Company dated as of December 1, 1997* (1) 10.6 Employment Agreement by and between Larry E. Lee and the Company dated as of December 1, 1997* (1) 10.8 Form of the Company's Indemnity Agreement* (1) 10.6.1.1 Amendment of Employment Agreement by and between Larry E. Lee and the Company (3) 10.17 Employment Agreement by and between William W. Talley II and the Company dated January 1, 2001 (3) 10.18 Employment and Severance Agreement by and between John M. Longmire and the Company dated December 1, 2000 (3) 10.19 Employment and Severance Agreement by and between Larry G. Rampey and the Company dated December 1, 2000 (3) 10.20 Employment and Severance Agreement by and between Drake N. Smiley and the Company dated December 1, 2000 (3) 21 Subsidiaries of the Company (3) ---------------- X Management contract or compensatory plan or arrangement. (1) Filed as an exhibit to the Company's Registration Statement on Form S-4 (No. 333-42641) and incorporated by reference herein. (2) Filed as an exhibit to the Company's Current Report on Form 8-K filed on March 10, 1998, as the exhibit number 4.2. (3) Filed as an exhibit to the Company's Annual Report on Form 10-K filed on April 2, 2001 and incorporated by reference herein. (b) During the quarter ended December 31, 2001 the Registrant filed the following reports on 8-K: Date of Report Items Covered -------------- ------------- November 27, 2001 Item 5. Other Material Events December 6, 2001 Item 2. Acquisition or Disposition of Assets ATTACHMENT I CONSOLIDATED FINANCIAL STATEMENTS RAM Energy, Inc. Years ended December 31, 1999, 2000, and 2001 RAM Energy, Inc. Consolidated Financial Statements Years ended December 31, 1999, 2000, and 2001 Contents Report of Independent Auditors..........................................F-1 Consolidated Audited Financial Statements Consolidated Balance Sheets.............................................F-2 Consolidated Statements of Operations...................................F-3 Consolidated Statements of Stockholders' Deficiency.....................F-4 Consolidated Statements of Cash Flows...................................F-5 Notes to Consolidated Audited Financial Statements......................F-7 Report of Independent Auditors The Board of Directors RAM Energy, Inc. We have audited the accompanying consolidated balance sheets of RAM Energy, Inc. as of December 31, 2000 and 2001, and the related consolidated statements of operations, stockholders' deficiency, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of RAM Energy, Inc. at December 31, 2000 and 2001, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As discussed in Note 1 of the notes to the consolidated financial statements, effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. ERNST & YOUNG LLP Tulsa, Oklahoma March 22, 2002 RAM Energy, Inc. Consolidated Balance Sheets (Dollars in Thousands)

See accompanying notes. RAM Energy, Inc. Consolidated Statements of Operations (In Thousands, Except Share Amounts)

See accompanying notes. RAM Energy, Inc. Consolidated Statements of Stockholders' Deficiency (In Thousands)

See accompanying notes. RAM Energy, Inc. Consolidated Statements of Cash Flows (In Thousands)

See accompanying notes. RAM Energy, Inc. Notes to Consolidated Financial Statements December 31, 2000 and 2001 1. Summary of Significant Accounting Policies, Organization, and Basis of Financial Statements Nature of Operations and Organization RAM Energy, Inc. (the Company) operates exclusively in the upstream segment of the natural gas and oil industry with activities including drilling, completion and operation of natural gas and oil wells. The Company conducts the majority of its operations in the states of Oklahoma, Texas, and New Mexico. Additionally, the Company owns and operates a natural gas and oil pipeline system and a saltwater disposal operation in north central Oklahoma (the pipeline system). The pipeline system purchases, transports and markets natural gas and oil production and disposes of salt water from properties owned by the Company and other natural gas and oil companies. On December 1, 2001, the Company sold a substantial portion of its natural gas and oil properties (see Note 3). Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions have been eliminated. Properties and Equipment The Company follows the full cost method of accounting for natural gas and oil operations. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of natural gas and oil reserves are capitalized. No gains or losses are recognized upon the sale or other disposition of natural gas and oil properties except in transactions which would substantially alter the amortization base of the capitalized costs. With the exception of the plugging and abandonment obligation further described in Note 13, the Company does not believe that future costs related to dismantlement, site restoration, and abandonment costs, net of estimated salvage values, will have a significant effect on its results of operations or financial position because the salvage value of equipment and related facilities is expected to approximate or exceed any future expenditures for dismantlement, restoration, or abandonment. The Company has not incurred any net expenditures for costs of this nature during the last three years. Under the full cost method, the net book value of natural gas and oil properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved natural gas and oil properties, discounted at 10% per year (the ceiling limitation). In arriving at estimated future net revenues, estimated lease operating expenses, development costs, abandonment 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 which 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 discounted future net revenues at December 31, 2001, include approximately $20 million related to undeveloped and nonproducing properties on which estimated discounted capital expenditures of approximately $8.4 million will be required to develop and produce the reserves. The funding for these projects is expected by the Company to be provided from existing available cash, future cash flows from operations and from proceeds received from property sales (see Note 3). The Company has capitalized internal costs of $600,000, $613,000 and $657,000 for the years ended December 31, 1999, 2000, and 2001, 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. The Company assesses the recoverability of the book value of the pipeline system on a quarterly basis, or when events occur which indicate an impairment in value may exist. Impairment is recorded for the excess of the book value over the fair value of the pipeline system if the book value of the pipeline system is in excess of the expected future cash flows from the pipeline system. Accumulated depreciation related to the pipeline system is $5,525,000 and $7,569,000 at December 31, 2000 and 2001, respectively. 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 which extend the useful life of property and equipment are treated as capital additions. Accumulated amortization and depreciation of other property and equipment at December 31, 2000 and 2001, is $3,445,000 and $3,443,000, respectively. Amortization and Depreciation Amortization of natural gas and oil properties and equipment is computed based on the unit-of-production method using total proved reserves. Depreciation of pipeline system is computed on a straight-line method over twenty years. Depreciation on other equipment is computed based on an accelerated 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. Amortization of deferred loan origination and debt issuance costs is computed based on the straight-line method over the term of the related debt. Natural Gas and Oil Sales and Gas Imbalances The Company follows the entitlements method of accounting for natural gas and oil sales, recognizing only its net share of all production sold as revenues. Any amount received in excess of or less than the Company's revenue interest is recorded in the net gas balancing liability. At December 31, 2000 and 2001, the Company's net overproduced position was 1,483,000 mcf and 167,000 mcf, respectively, with an associated liability of $2,178,000 and $235,000, respectively. Charges for gathering and transportation are included in natural gas and oil production expenses. Cash Equivalents All highly liquid unrestricted investments with a maturity of three months or less when purchased are considered to be cash equivalents. Credit and Market Risk The Company sells natural gas and oil to various customers and participates with other parties in the drilling, completion and operation of natural gas and oil wells. Joint interest and natural gas and oil sales receivables related to these operations are generally unsecured. In 2001, approximately 74% of total revenues were to four customers (68% to four customers in 2000 and 53% to two customers in 1999), with sales to each comprising 34%, 17%, 12%, and 11% (30%, 15%, 12%, and 11% in 2000 and 29% and 24% in 1999) of total revenues. For the years ended December 31, 1999, 2000, and 2001, the provisions for doubtful accounts receivable were approximately $116,000, $60,000, and none, respectively, while charge-offs of the allowance in those years were approximately $15,000, none, and none, respectively. The Company has established joint interest operations accounts receivable allowances which management believes are adequate for uncollectible amounts at December 31, 2000 and 2001. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Fair Value of Financial Instruments The carrying amounts reported in the balance sheets for cash and cash equivalents, trade receivables and payables, installment notes and variable rate long-term debt approximate their fair values. The carrying value of the Senior Notes exceeded the fair value at December 31, 2000 and 2001, by approximately $23.2 million and $23.9 million, respectively, based on quoted market prices. Accounting Policy for Derivatives On January 1, 2001, the Company adopted Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (SFAS No. 133). 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 accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company formally documents its hedging relationships at inception of the hedge, however redesignation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. The ineffective portion of a derivative's change in fair value is recognized currently in earnings. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring, and if the forecasted transaction is no longer probable of occurring, any gain or loss deferred in accumulated other comprehensive income is recognized in earnings currently. All of the Company's derivative contracts have been designated as cash flow hedges. The adoption of SFAS No. 133 on January 1, 2001, resulted in a pre-tax reduction to accumulated other comprehensive income of $7.4 million ($4.6 million after-tax) as a result of losses indicated on the Company's cash flow hedges based on the Company's derivative positions and market prices at January 1, 2001. Earnings Per Common Share Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if dilutive stock options and warrants were exercised, calculated using the treasury stock method. The outstanding stock options (see Note 10) were not considered in the diluted earnings per share calculations for 1999, 2000, and 2001, as the effect would be antidilutive. As a result, basic earnings per share and diluted earnings per share are the same. Recently Issued Accounting Pronouncements In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations. SFAS No. 141 addresses financial accounting and reporting for business combinations. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001, and for all business combinations accounted for under the purchase method initiated before but completed after June 30, 2001. In addition, in June 2001 the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001, and applies to all goodwill and other intangibles recognized in the financial statements at that date. The adoption of these standards is not expected to have an impact on the Company's current financial position or results of operations. However, any business combinations initiated from this point forward will be impacted by these two standards. In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, and in October 2001, issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the impact of SFAS No. 143 and No. 144; however, at this time does not believe the impact of these standards will be material to the Company's financial condition or results of operations. 2. Investment in RVC Energy, Inc. In August 1998, RVC Energy, Inc. (RVC), a Delaware corporation, was formed and, concurrent with the formation, the Company invested $2.0 million in RVC in exchange for 49.5% of RVC's voting common stock and all of RVC's non-voting common stock. RVC was an unrestricted affiliate of the Company accounted for under the equity method of accounting. The Company recognized an impairment charge of approximately $200,000 in 1999 to reduce its recorded investment in RVC to $0 at December 31, 1999. As of December 31, 2000, RVC had divested substantially all assets such that the Company is not expecting any future recovery of this investment. 3. Property Sales In a transaction that closed December 4, 2001, effective December 1, 2001, the Company sold to Carmen Acquisition Corp. (Carmen), a wholly owned subsidiary of Chesapeake Energy Corporation, all of Company's producing and non-producing natural gas and oil properties located in seventeen counties in the states of Oklahoma, Texas, and New Mexico. Such properties contained proved reserves of approximately 85.8 billion cubic feet of natural gas equivalent. The base sales price of $76 million (before the settlement of the net overproduced gas balancing status of the properties for $2.0 million and customary post-closing adjustments) was comprised of approximately 85% cash and 15% in the Company's 11.5% Senior Notes due 2008 valued at par. At December 31, 2001, $6,375,000 of cash and $1,125,000 of the Company's Senior Notes were being held in an escrow account pending determination of any post-closing adjustments. Subsequent to December 31, 2001, Carmen identified potential post-closing adjustments related to title defects as well as other issues related to certain remaining unpaid obligations of the Company, on the sold properties. Management of the Company believes that all material title and environmental defects will be cured such that no material adjustments will be made to the escrow amounts. The Company has accrued liabilities recorded at December 31, 2001 for the unpaid obligations identified by Carmen. Management expects to receive the escrow amounts during April 2002. The sale of these properties, which represented approximately 66% of the Company's proved reserves, significantly altered the relationship between capital costs and proved reserves. As a result, the Company recognized a gain of approximately $17.3 million, net of transaction costs of approximately $1.1 million, on the sale under full cost accounting. At the time of the closing, Carmen Acquisition Corp. was the owner of 49.5% of the outstanding common stock of the Company. Immediately following the closing, Carmen Acquisition sold all of its stock in the Company directly to the Company's remaining stockholders and their affiliates. As allowed by the provisions of the indenture under which the Company's Senior Notes were issued, the Company utilized $28.8 million of the proceeds to pay in full the amounts outstanding under the credit facility with Foothill Capital Corporation (see Note 6). The indenture requires that the remaining net proceeds of $16.4 million, net of estimated tax effects of the transaction of $16.2 million before consideration of tax attributes unrelated to the sale, be used within 365 days either for additional capital expenditures or for the acquisition of natural gas and oil assets. To the extent that the net cash proceeds that are not applied for such expenditures by the end of the 365-day period, such amounts are defined as excess cash under the indenture. In the event that such excess cash exceeds $10 million, the Company must make an irrevocable and unconditional offer to the holders of the Company's Senior Notes to purchase the maximum amount of the Senior Notes which could be acquired by the application of the excess cash at a purchase price equal to 100% of the principal amount of the Senior Notes. Based on the Company's capital expenditures budget for 2002, the excess cash balance at the end of the 365-day period is expected to be below $10 million such that no Senior Notes will be required to be purchased. 4. Volumetric Production Payment On September 28, 1999, the Company entered into a nonrecourse volumetric production payment agreement (the Production Payment) with Duke Energy Corporation (Duke), pursuant to which the Company was required to deliver to Duke 2.8 billion cubic feet of natural gas produced from certain of the Company's properties over a five-year period. Such volumes have been excluded from the Company's proved reserves at December 31, 1999 and 2000. Effective December 1, 2001, the Company's remaining obligation under the Production Payment was assigned to Carmen Acquisition Corp. in connection with the sale discussed in Note 3. 5. Related Party Transactions Since its formation, the Company acted as manager of RVC and owned the operating rights of RVC's natural gas and oil properties. The Company received monthly management fees of $50,000 and overhead reimbursements from RVC from its inception through March 2000 at which time RVC had divested substantially all of its assets. During 1999 and 2000, the Company received $600,000 and $150,000, respectively, in management fees as well as $309,000 and $43,000, respectively, in overhead reimbursements from RVC. Management fees are reflected in other income while overhead reimbursements have been netted against general and administrative expenses in the accompanying consolidated statements of operations. In February 2000, the Company sold the operating rights of certain RVC natural gas and oil properties resulting in cash proceeds of $1.7 million. Such proceeds have been recorded as a reduction in the carrying value of natural gas and oil properties. 6. Long-Term Debt Long-term debt at December 31 consists of the following:

(A) In February 1998, the Company completed the sale of $115 million of 11.5% Senior Notes Due 2008 in a public offering of which $92.0 million remain outstanding at December 31, 2001. 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 111.50% to 103.84% of face amount to their scheduled maturity in 2008. The indenture under which the Senior Notes are issued contains certain covenants, including covenants that limit (i) incurrences 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. In August 2000, the Company recognized an extraordinary after-tax gain (net of unamortized deferred offering and original issue discount costs and income taxes) of $916,000 or $.34 per share as a result of the purchase of an additional $5.0 million face amount of the Senior Notes. The Senior Notes were purchased at 66% of face amount and have been canceled by the Company. The Company utilized borrowings under its revolving credit agreement to purchase the Senior Notes. In December 2001, the Company recognized an extraordinary after-tax loss (net of unamortized deferred offering and original issue discount costs) of $247,000 or $.09 per share as a result of the retirement of the $11.0 million of Senior Notes received from Chesapeake Energy Corporation (see Note 3). At December 31, 2000 and 2001, the unamortized issue discount associated with the Notes totaled $1,073,000 and $825,795, respectively. (B) In connection with the sale of natural gas and oil properties to Carmen Acquisition Corp. (see Note 3), the Company repaid the outstanding borrowings under its credit facility with Foothill Capital Corporation (Foothill) and terminated the agreement. As a result of the early termination of the credit facility, the Company was required to pay a fee of $785,000 to Foothill. Such amount, combined with the unamortized loan origination fees and net of income taxes, resulted in an extraordinary loss of $851,000 or $.31 per share. Subsequent to year-end, the Company purchased a $1.5 million certificate of deposit with BancFirst which serves as collateral for a three-year $1.5 million standby letter of credit issued to Carmen Acquisition Corp., as required by the provisions of the sales agreement (see Note 3). The amount of required principal payments for the next five years and thereafter, as of December 31, 2001, are as follows: 2002-$135,000; 2003-$229,000; 2004-$-; 2005-$-; 2006-$-; thereafter-$92.0 million. Interest paid in the years ended December 31, 1999, 2000, and 2001 totaled $14,701,000, $13,946,000 and $12,545,000, respectively. 7. Subsidiary Guarantors The Company's Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of the Company's current and future subsidiaries (the Subsidiary Guarantors). The following table sets forth condensed consolidating financial information of the Subsidiary Guarantors after their acquisition or formation in 1998. There are currently no restrictions on the ability of the Subsidiary Guarantors to transfer funds to the Company in the form of cash dividends, loans or advances. The following represents the condensed consolidating balance sheets for the Company and its subsidiaries for the years ended December 31, 2000 and 2001:

The following represents the condensed consolidating statements of operations and statements of cash flows for the Company and its subsidiaries for the years ended December 31, 1999, 2000, and 2001:

The Company has not allocated any portion of its long-term debt or related accounts, including accrued interest payable, unamortized debt issue costs and unamortized issue discount to its subsidiaries. In addition, the Company has not allocated general and administrative expenses, interest charges or income taxes to its subsidiaries. Accordingly, the above condensed consolidating information is not intended to present the Company's subsidiaries on a stand-alone basis. 8. Operating Leases The Company leases office space under a noncancelable operating lease agreement that expires on December 31, 2006. Future minimum lease payments for this operating lease at December 31, 2001, are as follows: 2002 $ 157,000 2003 160,000 2004 163,000 2005 166,000 2006 168,000 ----------- $ 814,000 =========== Rent expense of $449,000, $324,000 and $254,000 was incurred under operating leases in the years ended December 31, 1999, 2000, and 2001, respectively. 9. Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees. The plan allows eligible employees to contribute up to 17.5% of their annual compensation, not to exceed approximately $10,500 in 2001. Employer contributions to the plan are discretionary. Company contributions to the plan in 1999, 2000, and 2001 were none, $80,000, and $341,000, respectively. 10. Capital Stock Common Stock Pursuant to a Special Retainer Agreement effective July 1, 1998, as amended, the Board of Directors granted an outside counsel an option to purchase 50,000 shares of the Company's common stock. Pursuant to the terms of the Stock Option Agreement, 16,666 shares vested on August 1, 1998, 1999, and 2000, respectively, or become fully vested upon occurrence of certain specified events, and are exercisable through June 30, 2008. On March 5, 1999, the Board of Directors set the exercise price at $7.33, an amount which management believes approximates the per common share value of the Company at the grant date and December 31, 1998 and 1999 and August 1, 2000. Consequently, no compensation expense related to the grant has been recognized in the statements of operations. Additionally, the Board of Directors approved the 1998 Stock Incentive Plan and reserved 550,000 shares of Common Stock which may be granted under the plan. No grants have been made at December 31, 2001. Preferred Stock The Company has an authorized class of Preferred Stock consisting of 5,000,000 shares, none of which are issued and outstanding. The Board of Directors is authorized, subject to any limitations prescribed by law, without further stockholder approval, to issue shares of Preferred Stock from time to time. The Board of Directors may designate one or more series of Preferred Stock. Each such series of Preferred Stock shall have such number of shares, designations, preferences, voting powers, qualifications and special or relative rights or privileges as shall be determined by the Board of Directors, which may include, among others, dividend rights, voting rights, redemption and sinking fund provisions, liquidation preferences and conversion rights. 11. Income Taxes Deferred income taxes of the Company 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 as of December 31 are as follows:

The reconciliation of income taxes computed at the U.S. Federal statutory tax rates to the Company's income tax benefit based on loss before income taxes and extraordinary item for the years ended December 31 is as follows:

At December 31, 2001, the Company has federal income tax net operating loss carryforwards of approximately $3.5 million which begin expiring in 2006. 12. Contract Termination and Severance Payments In 2000, the Company closed its Oklahoma City accounting and Midland, Texas operations offices and outsourced its accounting function as well as elected to terminate its Special Severance Agreement with the Chairman of the Board and to execute a new Employment Contract with him. A total charge of $1,221,000 is reflected in the consolidated statement of operations, consisting of $230,000 in severance payments to affected employees, $107,000 related to the termination of certain operating lease contracts and $884,000 in connection with the severance agreement termination. In December 2001, following the sale of certain natural gas and oil properties to Carmen Acquisition Corp. (see Note 3), the Company reduced its work force and elected to terminate employment contracts with certain senior officers of the Company. A total charge of approximately $1,104,000 has been reflected in the consolidated statements of operations. Such charge consists of $374,000 in severance payments made to affected employees during 2001 and $730,000 related to the termination of the employment contracts with the senior officers. The amounts owed to the senior offices were included accrued compensation at December 31, 2001 and were paid in 2002. 13. Commitments and Contingencies In 1996, the Company's predecessor sold an natural gas and oil property located in Louisiana state waters in Plaquemines Parish. The property included several uneconomical wells for which the Company estimated the plugging and abandonment (P&A) obligation to be approximately $1,020,000. The purchaser provided a letter of credit and a bond totaling $420,000 to ensure funding of a portion of the P&A obligation. The P&A obligation would revert to the Company in the event the purchaser does not complete the required P&A activities. As a result, in connection with the sale the Company recorded a contingent liability of $600,000, which is included in the accompanying consolidated balance sheets. The Company has established a severance agreement for the President and CEO of the Company. This agreement provides for severance benefits to be paid upon involuntary separation as a result of actions taken by the Company or its successors. At December 31, 2001, the severance benefits under this agreement were approximately $1.0 million. A provision for these benefits would not be made unless an involuntary termination was probable. Pursuant to a Special Retainer Agreement effective July 1, 1998, as amended, the Company is obligated to pay an outside counsel approximately $308,700 in the event that the agreement is terminated by reason of expiration of term, by counsel for good reason, by reason of change in control, or by the Company at will. A provision for the payment would not be made unless termination of the agreement was probable. The Company is currently involved in litigation with the Commissioners of the Land Office (CLO) over alleged improper royalty payments made to the State on gas purchased by the Company's pipeline system. The Company purchased the pipeline system from Carlton Resources Corporation (Carlton) in 1998. The alleged improper payments occurred primarily prior to the time that the Company owned the pipeline system. The amount of damages claimed by the CLO is believed to approximate $600,000. The Company has denied all of the substantive allegations made by the CLO and plans to vigorously defend the case. No loss accrual has been reflected in the financial statements at December 31, 2001, as management does not believe that a loss is probable. In the event that the Company is unsuccessful in defending the allegations made by the CLO, the Company believes that the former stockholders of Carlton and a former joint venture partner of Carlton are contractually obligated to indemnify the Company for all material amounts assessed against the Company, including legal fees incurred. 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. 14. Hedging Strategy During 1999, 2000, and 2001, the Company utilized a cash flow hedging program to reduce its exposure to unfavorable changes in natural gas prices that are subject to significant and often volatile fluctuation. Under this program, the Company hedges portions of its forecasted natural gas production by utilizing fixed-price natural gas swap contracts. Under the swap contracts, the Company receives a fixed price for natural gas and pays a floating price (generally NYMEX futures prices) to a counterparty. When market prices for natural gas decline, the decline in the value of the cash flows from the Company's forecasted natural gas production designated as being hedged is substantially offset by gains in the value of the fixed price swap contracts. Conversely, when market prices increase, the increase in the value of the cash flows from the Company's forecasted natural gas production designated as being hedged is substantially offset by losses in the value of the fixed price swap contracts. As of December 31, 2001, the Company had no contracts in place to hedge the price received for its future forecasted natural gas production, however such contracts may be utilized in the future. 15. Natural Gas and Oil Producing Activities Capitalized costs relating to natural gas and oil producing activities and related accumulated depreciation and amortization at December 31 are summarized as follows:

Costs incurred in natural gas and oil producing activities for the years ended December 31 are as follows:

16. Supplementary Natural Gas and Oil Reserve Information (Unaudited) The Company has interests in natural gas and oil properties that are principally located in Oklahoma, Texas, and New Mexico. The Company does not own or lease any natural gas and oil properties outside the United States. The Company retains independent engineering firms to provide year-end estimates of the Company's future net recoverable natural gas, oil, 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 recompletion. Net quantities of proved developed and undeveloped reserves of natural gas and oil, including condensate and natural gas liquids, are summarized as follows:

The following is a summary of a standardized measure of discounted net cash flows related to the Company's proved natural gas and oil reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves were computed using natural gas and oil 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 natural gas and oil reserves, less the tax basis of the properties involved. The Company cautions against using this data to determine the fair value of its natural gas and oil properties. To obtain the best estimate of fair value of the natural gas and oil properties, forecasts of future economic conditions, varying discount rates, and consideration of other than proved reserves would have to be incorporated into the calculation. In addition, there are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production that impair the usefulness of the data. The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves at December 31 are summarized as follows:

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, 2001:

Prices used in computing these calculations of future cash flows from estimated future production of proved reserves were $22.76, $23.75, and $19.78 per barrel of oil at December 31, 1999, 2000, and 2001, respectively, and $2.07, $9.98, and $2.72 per thousand cubic feet of natural gas at December 31, 1999, 2000, and 2001, respectively. Such prices do not include the effect of the Company's fixed price contracts designated as hedges. SIGNATURES Pursuant to the requirements of Section 13 and 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. March 29, 2002 RAM ENERGY, INC. By LARRY E. LEE Larry E. Lee President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in capacities and on the dates indicated.

Supplemental Information to be Furnished With Reports Pursuant to Section 15(d) of the Act by Registrants Which have Not Registered Securities Pursuant to Section 12 of the Act. The Company has not sent, and does not intend to send, an annual report to security holders covering its last fiscal year, nor has the Company sent a proxy statement, form of proxy or other proxy soliciting material to its security holders with respect to any annual meeting of security holders. EXHIBIT INDEX Exhibit No. Description of Exhibit Method of Filing ------- ---------------------- -------------------------------- 3.1 Company's Amended and Incorporated herein by reference Restated Certificate of Incorporation 3.2 Company's Amended and Incorporated herein by reference Restated Bylaws 4.1 Indenture dated as of Incorporated herein by reference February 24, 1998 among the Company, as issuer, RB Operating Company and RLP Gulf States, L.L.C., as Subsidiary Guarantors, and United States Trust Company of New York, as trustee 4.2 Form of 11-1/2% Senior Incorporated herein by reference Notes due 2008 4.3 Supplemental Indenture Incorporated herein by reference entered into February 24, 1998 by the Registrant, the Subsidiary Guarantors, the Additional Guarantors and United States Trust Company of New York, as Trustee 10.4 RAM Energy 1998 Stock Incorporated herein by reference Incentive Plan 10.5 Special Severance Agreement Incorporated herein by reference by and between William W. Talley II and the Company dated as of December 1, 1997 10.6 Employment Agreement by and Incorporated herein by reference between Larry E. Lee and the Company dated as of December 1, 1997 10.8 Form of the Company's Incorporated herein by reference Indemnity Agreement 10.15 Amended and Restated Loan Incorporated herein by reference and Security Agreement by and between the Company, as Borrower, the Financial Institutions named therein and Foothill Capital Corporation, as Agent, dated December 27, 1999 10.16 Employment and Severance Incorporated herein by reference Agreement by and between John M. Longmire and the Company dated December 13, 1999 10.16.1 Employment and Severance Incorporated herein by reference Agreement by and between Larry G. Rampey and the Company dated December 13, 1999 10.16.2 Employment and Severance Incorporated herein by reference Agreement by and between Drake N. Smiley and the Company dated December 13, 1999 10.6.1 Amendment of Employment Incorporated herein by reference Agreement by and between Larry E. Lee and the Company 10.17 Employment Agreement by and Incorporated herein by reference between William W. Talley II and the Company dated January 1, 2001 10.18 Employment and Severance Incorporated herein by reference Agreement by and between John M. Longmire and the Company dated December 1, 2000 10.19 Employment and Severance Incorporated herein by reference Agreement by and between Larry G. Rampey and the Company dated December 1, 2000 10.20 Employment and Severance Incorporated herein by reference Agreement by and between Drake N. Smiley and the Company dated December 1, 2000 21 Subsidiaries of the Company Filed herewith electronically

RAM ENERGY INC/OK 10-K