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, 1999 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number: 333-61547 CONTINENTAL RESOURCES, INC. (Exact name of registrant as specified in its charter) Oklahoma 73-0767549 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 302 N. Independence, Suite 300, Enid, Oklahoma 73701 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (580) 233-8955 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 report(s), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practible date: As of March 28, 2000, there were 49,041 shares of the registrant's common stock, par value $1.00 per share, outstanding. The common stock is privately held by affiliates of the registrant. Documents incorporated by reference: None CONTINENTAL RESOURCES, INC. Annual Report on Form 10 - K for the Year Ended December 31, 1999 TABLE OF CONTENTS PART I ITEM 1. BUSINESS ITEM 2. PROPERTIES ITEM 3. LEGAL PROCEEDINGS ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ITEM 6. SELECTED FINANCIAL AND OPERATING DATA ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ITEM 11. EXECUTIVE COMPENSATION ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K PART I ITEM 1. BUSINESS OVERVIEW Continental Resources, Inc. and its subsidiaries, Continental Gas, Inc. ("CGI") and Continental Crude Co. ("CCC") (collectively "Continental" or the "Company"), are engaged in the exploration, exploitation, development and acquisition of oil and gas reserves, primarily in the Rocky Mountains and the Mid-Continent, and to a growing extent, in the Gulf Coast region of Texas and Louisiana. In addition to its exploration, development and acquisition activities, the Company owns and operates 750 miles of natural gas pipelines, five gas gathering systems and two gas processing plants in its operating areas exclusive of the sale of two systems in January, 2000. The Company also engages in natural gas marketing, gas pipeline construction and saltwater disposal. Capitalizing on its growth through the drill-bit and its acquisition strategy, the Company has increased its estimated proved reserves from 26.6 million barrels of oil equivalent ("MMBoe") in 1995 to 49.3 MMBoe at year-end 1999, and increased its annual production from 2.2 MMBoe in 1995 to 4.3 MMBoe in 1999. As of December 31, 1999, the Company's reserves had a present value of estimated future net cash flows, discounted at 10% ("PV-10") of $334.4 million calculated in accordance with the Securities and Exchange Commission (the "Commission" or "SEC") guidelines. Approximately 74% of the Company's estimated proved reserves were oil and approximately 94% of its total estimated reserves were classified as proved developed. At December 31, 1999, the Company had interests in 1,119 producing wells of which it operated 960. The Company was originally formed in 1967 to explore, develop and produce oil and gas properties in Oklahoma. The Company acquired interests in the Williston Basin in 1993 and has since focused on the Rocky Mountains, expanding its operations within the Williston Basin and acquiring additional interests in the Big Horn Basin in 1998 and 1999. BUSINESS STRATEGY The Company's business strategy is to increase production, cash flow, and reserves through the exploration, development, exploitation, and acquisition of properties in the Company's core operating areas including the Rocky Mountain and Mid-Continent Regions while increasing the Company's natural gas reserves through exploration on the Company's acreage in the Gulf Coast. Through development activities, the Company seeks to increase production, cash flow, and develop additional reserves through the use of drilling new wells (including horizontal wells), expanding high pressure air injection ("HPAI") technology into the West Medicine Pole Hills Unit and the Cedar Hills Field of the Williston Basin, workovers, recompletions of existing wells, water floods, and the application of other techniques designed to increase production. The Company's acquisition strategy includes seeking properties that have an established production history, have undeveloped reserve potential, and through the use of the Company's technical expertise in horizontal drilling and high pressure air injection allow the company to maximize the utilization of its infrastructure in core operating areas. The Company's exploration strategy includes expanding the existing reserve base by testing new reservoirs in existing fields and capitalizing on existing acreage positions in the Gulf Coast by creating strategic alliances with companies familiar with the Gulf Coast area for the purpose of increasing the Company's natural gas reserves with less risk. On an on-going basis, the Company evaluates and considers divesting of oil and gas properties considered to be non-core to the Company's reserve growth plans for the purpose of assuring that all company assets are contributing to the Company's long-term strategic plan. PROPERTY OVERVIEW The Company's Mid-Continent activities are conducted primarily in the Anadarko Basin of western Oklahoma, in southwestern Kansas and in the Texas Panhandle. At December 31, 1999 the Company's Anadarko Basin properties represented approximately 99% of the PV-10 attributable to the Company's estimated proved reserves in the Mid-Continent and approximately 21% of the Company's total estimated proved reserves. In the Anadarko Basin the Company owns approximately 62,000 net leasehold acres, has interests in 534 gross (319 net) producing wells and has identified 10 potential drilling locations. The Company also owns leasehold interests in the Gulf Coast region of Texas and Louisiana and expects to expand its exploration activities in the Gulf Coast region during 2000. The Company's Gulf Coast activities are located in the Jefferson Island Project, Iberia Parish, Louisiana and in the Pebble Beach Project, Nueces County, Texas. These properties currently provide 10% of the PV10 attributable to the Company's estimated proved reserves of natural gas and 4.5% of the Company's total PV10 . From a combined total of 60 square miles of proprietary 3-D data, the Company has identified 16 development and 11 exploratory locations for drilling. The Company has developed a strategic alliance with a company familiar with the Gulf Coast region for the purpose of reducing the Company's risk and expediting the development of the properties with no substantial capital outlay required by the Company. The Company's Rocky Mountain activities are concentrated in the Williston and Big Horn Basins. The Company's operations in the Williston Basin are focused on the Cedar Hills Field, which the Company believes is, potentially, one of the largest onshore discoveries in the lower 48 states since 1971. The Cedar Hills Field represented approximately 33% of the PV10 attributable to the Company's estimated proved reserves at December 31, 1999. The Company has assigned no secondary reserves for this field, which the Company believes will be three barrels of oil of secondary recovery for one barrel of oil of primary recovery. In the Williston Basin, the Company owns approximately 337,000 net leasehold acres and has interests in 291 gross (226 net) wells, has identified 40 potential drilling locations and conducts both primary and enhanced recovery operations. As of December 31, 1999, the Company operated one-half of the high pressure air injection projects in North America. In 1998 the Company expanded its activities into the Big Horn Basin through the acquisition of producing and non-producing properties in the Worland Field. The Worland Field consists of approximately 75,000 net leasehold acres in which the Company has interests in 243 gross (217 net) producing wells, of which 230 are company operated, and represent approximately 29% of the PV10 attributable to the Company's estimated proved reserves at December 31, 1999. In the Worland Field the Company has identified 162 potential drilling locations which represent significant opportunities. OTHER INFORMATION The Company's subsidiary, Continental Gas, Inc., was formed as a gas marketing company in April 1990. Continental Gas, Inc. has developed into a company specializing in gas marketing, pipeline construction, gas gathering systems and gas plant operations. Continental Crude Co. was incorporated in May 1998. Since its incorporation, Continental Crude Co. has had no operations, has acquired no assets and has incurred no liabilities. Continental Resources, Inc. is headquartered in Enid, Oklahoma, with additional primary offices in Baker, Montana and Buffalo, South Dakota and field offices located within its various operating areas. BUSINESS STRENGTHS The Company believes that it has certain strengths that provide it with significant competitive advantages and provide it with diversified growth opportunities, including the following: PROVEN GROWTH RECORD. Continental has demonstrated consistent growth through a balanced program of development and exploratory drilling and acquisitions. The Company has increased its proved reserves from 26.6 million barrels of oil equivalent ("MMBOE") in 1995 to 49.3 million as of December 31, 1999. SUBSTANTIAL DRILLING INVENTORY. The Company has identified over 228 potential drilling locations based on geological and geophysical evaluations. As of December 31, 1999 the Company held approximately 501,000 net acres, of which approximately 55% were classified as undeveloped. Management believes that its current acreage holdings could support five to ten years of drilling activities depending upon oil and gas prices. LONG-LIFE NATURE OF RESERVES. Continental's producing reserves are primarily characterized by low rate, relatively stable, mature production that is subject to gradual decline rates. As a result of the long-lived nature of its properties, the Company has relatively low reinvestment requirements to maintain reserve quantities, primary and secondary production levels and reserve values. SUCCESSFUL DRILLING AND ACQUISITION RECORD. The Company has maintained a successful drilling record. During the five years ended December 31, 1999, the Company participated in 245 gross (166 net) wells of which 94% were successfully completed resulting in the addition of 29.1 MMBoe of proved developed reserves at an average finding cost of $5.81 per Boe excluding the potential secondary recovery in the Williston Basin. During the same five year period, the Company acquired 24.2 MMBoe at an average cost of $3.08 per Boe. Also, including major revisions of 14.7 MMBoe due primarily to fluctuating prices, the Company added a total of 53.3 MMBoe at an average cost of $4.57 per Boe during the last five years. SIGNIFICANT OPERATIONAL CONTROL. Approximately 92.5% of the Company's PV10 at December 31, 1999 was attributable to wells operated by the Company, giving Continental significant control over the amount and timing of capital expenditures and production, operating and marketing activities. TECHNOLOGICAL LEADERSHIP. The Company has demonstrated significant expertise in the rapidly evolving technologies of 3-D seismic evaluation, directional drilling, and precision horizontal drilling, and is among the few companies in North America to successfully utilize high pressure air injection ("HPAI") enhanced recovery technology on a large scale. Through the use of precision horizontal drilling the Company has experienced a 400% to 700% increase in initial flow rates. From inception, the Company has drilled 172 horizontal wells in the Rocky Mountains and Mid-Continent. Through the combination of precision horizontal drilling and HPAI secondary recovery technology, the Company has significantly enhanced the recoverable reserves underlying its oil and gas properties. Since its inception, Continental has experienced a 300% to 400% increase in recoverable reserves through use of these technologies. EXPERIENCED AND COMMITTED MANAGEMENT. Continental's senior management team has extensive expertise in the oil and gas industry. The Company's Chief Executive Officer, Harold Hamm, began his career in the oil and gas industry in 1967. Seven senior officers have an average of 21 years of oil and gas industry experience. Additionally, the Company's technical staff, which includes ten petroleum engineers and seven geoscientists, has an average of over 21 years experience in the industry. DEVELOPMENT, EXPLOITATION AND EXPLORATION ACTIVITIES DEVELOPMENT AND EXPLOITATION. The Company's development and exploitation activities include the drilling of development wells, precision drilling of horizontal wells, infill drilling, water floods, workovers, recompletions and HPAI projects. During 2000, the Company projects that development drilling will represent 85% of the drilling budget. The development drilling will occur rather evenly with 23% in the Mid Continent and Gulf Coast, 35% in the Williston Basin, and 42% in the Big Horn Basin. Approximately 89% of the Company's development drilling inventory, representing an estimated 202 wells, is located in the Rockies, specifically, the Cedar Hills Field, the Medicine Pole Hills, Buffalo, South Dakota and West Buffalo Units in the Williston Basin and the Worland Field in the Big Horn Basin. The Company will continue to seek opportunities and increase production from its substantial inventory of 116 workovers and recompletions in the Rockies as well as the 16 located in the Mid-Continent and Gulf Coast Regions. The unitization process required to install HPAI in West Medicine Pole Hills Fields will continue with target dates for initial injection to begin in quarter three of 2000. The following table sets forth the Company's development inventory as of December 31, 1999. NUMBER OF DEVELOPMENT PROJECTS ------------------------------ ENHANCED DRILLING WORKOVERS AND RECOVERY LOCATIONS RECOMPLETIONS PROJECTS TOTAL --------- ------------- -------- ----- ROCKY MOUNTAINS: Williston Basin 40 10 2 52 Big Horn Basin 162 106 1 269 MID-CONTINENT: Anadarko Basin 10 42 - 52 GULF COAST 16 - - 16 --- --- --- --- TOTAL 228 158 3 389 === === === === The Company will initiate, on a priority basis, as many projects as available cash allows. Based on forecasted cash flow, the Company anticipates initiating 62 development drilling projects, 21 workover projects and one enhanced recovery project during 2000. The Company expects to expend $31.3 to $37.5 million in capital expenditures related to these projects in 2000. EXPLORATION ACTIVITIES. The Company's exploration projects vary in risk and reward based on their depth, location and geology. The Company routinely uses the latest in technology, including 3-D seismic, horizontal drilling and new completion technologies to enhance its projects. The Company plans to limit its drilling investment in these higher risk exploratory projects to approximately 15% of its drilling budget during 2000 given the projected commodity price environment for the year. The Company will continue to build exploratory inventory throughout the year for future drilling. Currently the Company has 19 exploratory wells in inventory. The following table sets forth information pertaining to the Company's existing exploration project inventory at December 31, 1999: NUMBER OF EXPLORATION PROJECTS DRILLING LOCATION 3-D SEISMIC ----------------- ----------- ROCKY MOUNTAINS: Williston Basin 4 2 Big Horn Basin 2 3 MID-CONTINENT 2 - GULF COAST 11 4 --- --- TOTAL 19 9 === === ACQUISITION ACTIVITIES The Company seeks to acquire properties that have the potential to be immediately accretive to cash flow, have long-lived, lower risk, relatively stable production potential, and provide long-term growth in production and reserves. The Company focuses on acquisitions that complement its existing exploration program, provide opportunities to utilize the Company's technological advantages, have the potential for enhanced recovery activities, and/or provide new core areas for the Company's operations. REGULATION GENERAL. Various aspects of the Company's oil and gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and gas industry and 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. The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation and proposed regulation designed to increase competition within the natural gas industry, to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers and to establish the rates interstate pipelines may charge for their services. Similarly, the Oklahoma Corporation Commission and the Texas Railroad Commission have been reviewing changes to their regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes being considered by these federal and state regulators would affect the Company only indirectly, they are intended to further enhance competition in natural gas markets. The Company cannot predict what further action the FERC or state regulators will take on these matters, however, the Company does 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. Sales of crude oil, condensate and gas liquids by the Company are not currently regulated and are made at market prices. The price the Company receives from the sale of these products may be affected by the cost of transporting the products to market. ENVIRONMENTAL. Extensive federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to the protection of the environment affect the Company's oil and gas operations. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person or entity liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person or entity. Other laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and gas industry increases the Company's cost of doing business and consequently affects the Company's profitability. The Company believes that it is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company's operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon the capital expenditures or competitive position of the Company. The Company currently owns or leases, and has in the past owned or leased, numerous properties that have been used for the exploration and production of oil and gas and for other uses associated with the oil and gas industry. Although the Company followed operating and disposal practices that it considered appropriate under applicable laws and regulations, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where such wastes were taken for disposal. In addition, the Company owns or leases properties that have been operated by third parties in the past. The Company could incur liability under the Comprehensive Environmental Response, Compensation and Liability Act or comparable state statutes for contamination caused by wastes it generated or for contamination existing on properties it owns or leases, even if the contamination was caused by the waste disposal practices of the prior owners or operators of the properties. In addition, it is not uncommon for landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of produced fluids or other pollutants into the environment. The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development or production of oil and gas from regulation as "hazardous waste." A similar exemption is contained in many of the state counterparts to RCRA. Disposal of such oil and gas exploration, development and production wastes usually is regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and gas industry in the future. From time to time legislation has been proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of "hazardous wastes" thereby potentially subjecting such wastes to more stringent handling and disposal requirements. If such legislation were enacted, or if changes to applicable state regulations required the wastes to be managed as hazardous wastes, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. The Company's operations are also subject to the Clean Air Act (the "CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from operations of the Company. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, the Company believes its operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to the Company than to other similarly situated companies involved in oil and gas exploration and production activities or well servicing activities. The Federal Water Pollution Control Act of 1972 (the "FWPCA") imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and gas wastes, into navigable waters. These controls have become more stringent over the years, and it is probable that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA provides for civil, criminal and administrative penalties for unauthorized discharges of oil and other hazardous substances and imposes substantial potential liability for the costs of removal or remediation. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the Environmental Protection Agency has promulgated regulations that require many oil and gas production sites, as well as other facilities, to obtain permits to discharge storm water runoff. The Company believes that compliance with existing requirements under the FWPCA and comparable state statutes will not have a material adverse effect on the Company's financial condition or results of operations. REGULATION OF OIL AND GAS EXPLORATION AND PRODUCTION. Exploration and production operations of the Company are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells, and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and 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 the Company's properties. See "Risk Factors--Laws and Regulations; Environmental Risk." EMPLOYEES As of March 28, 2000, the Company employed 191 people, 69 of which were administrative personnel, 8 of which were geological personnel, 11 of which were engineers and the remaining 103 were field personnel. The Company's future success will depend partially on its ability to attract, retain and motivate qualified personnel. The Company is not a party to any collective bargaining agreements and has not experienced any strikes or work stoppages. The Company considers its relations with its employees to be satisfactory. From time to time the company utilizes the services of independent contractors to perform various field and other services FORWARD LOOKING STATEMENTS Certain of the statements under this Item and elsewhere in this Form 10-K are "forward-looking statements: within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in this Form 10-K, including without limitation statements under "Item 1. Business", "Item 2. Properties" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" regarding budgeted capital expenditures, increases in oil and gas production, the Company's financial position, oil and gas reserve estimates, business strategy and other plans and objectives for future operations, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulation of oil and natural gas that cannot be measured in an exact way, and 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 made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimate and such revisions, if significant, would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Additional important factors that could cause actual results to differ materially from the Company's expectations are disclosed under "Risk Factors" and elsewhere in this form 10-K. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Company's actual results and plans for 2000 and beyond could differ materially from those expressed in forward-looking statements. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors. RISK FACTORS VOLATILITY OF OIL AND GAS PRICES The Company's revenues, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas and natural gas liquids, which are dependent upon numerous factors such as weather, economic, political and regulatory developments and competition from other sources of energy. The Company is affected more by fluctuations in oil prices than natural gas prices, because a majority of its production is oil. The volatile nature of the energy markets and the unpredictability of actions of OPEC members make it particularly difficult to estimate future prices of oil and gas and natural gas liquids. Prices of oil and gas and natural gas liquids are subject to wide fluctuations in response to relatively minor changes in circumstances, and there can be no assurance that future prolonged decreases in such prices will not occur. All of these factors are beyond the control of the Company. Any significant decline in oil and, to a lesser extent, in natural gas prices would have a material adverse effect on the Company's results of operations and financial condition. Although the Company may enter into hedging arrangements from time to time to reduce its exposure to price risks in the sale of its oil and gas, the Company's hedging arrangements are likely to apply to only a portion of its production and provide only limited price protection against fluctuations in the oil and gas markets. See "Management's Discussion and Analysis of Financial Condition and Results of Operations". REPLACEMENT OF RESERVES The Company's future success depends upon its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless the Company successfully replaces the reserves that it produces (through successful development, exploration or acquisition), the Company's proved reserves will decline. There can be no assurance that the Company will continue to be successful in its effort to increase or replace its proved reserves. Approximately 6% of the Company's estimated proved reserves at December 31, 1999 were attributable to undeveloped reserves. Recovery of such reserves will require additional capital expenditures and successful drilling operations. There can be no certainty regarding the results of developing these reserves. To the extent the Company is unsuccessful in replacing or expanding its estimated proved reserves, the Company may be unable to pay the principal of and interest on the Notes and other indebtedness in accordance with their terms, or otherwise to satisfy certain of the covenants contained in the indenture governing, its Notes (the "Indenture") and the terms of its other indebtedness. UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES AND FUTURE NET CASH FLOWS This report contains estimates of the Company's oil and gas reserves and the future net cash flows from those reserves which have been prepared by the Company and certain independent petroleum consultants. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. There are numerous uncertainties inherent in estimating quantities and future values of proved oil and gas reserves, including many factors beyond the control of the Company. Each of the estimates of proved oil and gas reserves, future net cash flows and discounted present values relies upon various assumptions, including assumptions required by the Commission as to constant oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, such estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated in the report. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this annual report on Form 10-K. In addition, the Company's reserves may be subject to downward or upward revision, based upon production history, results of future exploration and development, prevailing oil and gas prices and other factors, many of which are beyond the Company's control. The PV-10 of the Company's proved oil and gas reserves does not necessarily represent the current or fair market value of such proved reserves, and the 10% discount rate required by the Commission may not reflect current interest rates, the Company's cost of capital or any risks associated with the development and production of the Company's proved oil and gas reserves. At December 31, 1999, the estimated future net cash flows and PV-10 of $646.9 million and $334.4 million, respectively, attributable to the Company's proved oil and gas reserves are based on prices in effect at that date ($24.38 per barrel ("Bbl") of oil and $1.76 per thousand cubic feet ("Mcf") of natural gas), which may be materially different than actual future prices. PROPERTY ACQUISITION RISKS The Company's growth strategy includes the acquisition of oil and gas properties. There can be no assurance, however, that the Company will be able to identify attractive acquisition opportunities, obtain financing for acquisitions on satisfactory terms or successfully acquire identified targets. In addition, no assurance can be given that the Company will be successful in integrating acquired businesses into its existing operations, and such integration may result in unforeseen operational difficulties or require a disproportionate amount of management's attention. Future acquisitions may be financed through the incurrence of additional indebtedness to the extent permitted under the Indenture or through the issuance of capital stock. Furthermore, there can be no assurance that competition for acquisition opportunities in these industries will not escalate, thereby increasing the cost to the Company of making further acquisitions or causing the Company to refrain from making additional acquisitions. The Company is subject to risks that properties acquired by it will not perform as expected and that the returns from such properties will not support the indebtedness incurred or the other consideration used to acquire, or the capital expenditures needed to develop, the properties. The addition of the Worland Field properties may result in additional impairment of the Company's oil and gas properties to the extent the Company's net book value of such properties exceeds the projected discounted future net revenues of the related proved reserves. See "--Write down of Carrying Values." In addition, expansion of the Company's operations may place a significant strain on the Company's management, financial and other resources. The Company's ability to manage future growth will depend upon its ability to monitor operations, maintain effective cost and other controls and significantly expand the Company's internal management, technical and accounting systems, all of which will result in higher operating expenses. Any failure to expand these areas and to implement and improve such systems, procedures and controls in an efficient manner at a pace consistent with the growth of the Company's business could have a material adverse effect on the Company's business, financial condition and results of operations. In addition, the integration of acquired properties with existing operations will entail considerable expenses in advance of anticipated revenues and may cause substantial fluctuations in the Company's operating results. There can be no assurance that the Company will be able to successfully integrate the properties acquired and to be acquired or any other businesses it may acquire. SUBSTANTIAL CAPITAL REQUIREMENTS The Company has made, and will continue to make, substantial capital expenditures in connection with the acquisition, development, exploitation, exploration and production of its oil and gas properties. Historically, the Company has funded its capital expenditures through borrowings from banks and from its principal stockholder, and cash flow from operations. Future cash flows and the availability of credit are subject to a number of variables, such as the level of production from existing wells, borrowing base determinations, prices of oil and gas and the Company's success in locating and producing new oil and gas reserves. If revenues were to decrease as a result of lower oil and gas prices, decreased production or otherwise, and the Company had no availability under its bank credit facility (the "Credit Facility") or other sources of borrowings, the Company could have limited ability to replace its oil and gas reserves or to maintain production at current levels, resulting in a decrease in production and revenues over time. If the Company's cash flow from operations and availability under the Credit Facility are not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available. EFFECTS OF LEVERAGE At December 31, 1999, on a consolidated basis, the Company and the Subsidiary Guarantors had $170.6 million of indebtedness (including short term debt and current maturities of long-term indebtedness) compared to the Company's stockholders' equity of $86.6 million. Although the Company's cash flow from operations has been sufficient to meet its debt service obligations in the past, there can be no assurance that the Company's operating results will continue to be sufficient for the Company to meet its obligations. See "Selected Consolidated Financial Data," "Capitalization" and "Management's Discussion and Analysis of Financial Condition and Results of Operations-- Liquidity and Capital Resources." The degree to which the Company is leveraged could have important consequences to the holders of the Notes. The potential consequences could include: o The Company's ability to obtain additional financing for acquisitions, capital expenditures, working capital or general corporate purposes may be impaired in the future o A substantial portion of the Company's cash flow from operations must be dedicated to the payment of principal of and interest on the Notes and the borrowings under the Credit Facility, thereby reducing funds available to the Company for its operations and other purposes o Certain of the Company's borrowings are and will continue to be at variable rates of interest, which expose the Company to the risk of increased interest rates o Indebtedness outstanding under the Credit Facility is senior in right of payment to the Notes, is secured by substantially all of the Company's proved reserves and certain other assets, and will mature prior to the Notes o The Company may be substantially more leveraged than certain of its competitors, which may place it at a relative competitive disadvantage and make it more vulnerable to changing market conditions and regulations. The Company's ability to make scheduled payments or to refinance its obligations with respect to its indebtedness will depend on its financial and operating performance, which, in turn, is subject to the volatility of oil and gas prices, production levels, prevailing economic conditions and to certain financial, business and other factors beyond its control. If the Company's cash flow and capital resources are insufficient to fund its debt service obligations, the Company may be forced to sell assets, obtain additional debt or equity financing or restructure its debt. Even if additional financing could be obtained, there can be no assurance that it would be on terms that are favorable or acceptable to the Company. There can be no assurance that the Company's cash flow and capital resources will be sufficient to pay its indebtedness in the future. In the absence of such operating results and resources, the Company could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations, and there can be no assurance as to the timing of such sales or the adequacy of the proceeds which the Company could realize therefrom. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources" and "Description of Credit Facility." RESTRICTIVE COVENANTS The Credit Facility and the Indenture governing the Notes include certain covenants that, among other things, restrict: o The making of investments, loans and advances and the paying of dividends and other restricted payments o The incurrence of additional indebtedness o The granting of liens, other than liens created pursuant to the Credit Facility and certain permitted liens o Mergers, consolidations and sales of all or a substantial part of the Company's business or property o The hedging, forward sale or swap of crude oil or natural gas or other commodities. o The sale of assets o The making of capital expenditures. The Credit Facility requires the Company to maintain certain financial ratios, including interest coverage and leverage ratios. All of these restrictive covenants may restrict the Company's ability to expand or pursue its business strategies. The ability of the Company to comply with these and other provisions of the Credit Facility may be affected by changes in economic or business conditions, results of operations or other events beyond the Company's control. The breach of any of these covenants could result in a default under the Credit Facility, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under the Credit Facility, together with accrued interest, to be due and payable, and the Company could be prohibited from making payments with respect to the Notes until the default is cured or all Senior Debt is paid or satisfied in full. If the Company were unable to repay such borrowings, such lenders could proceed against their collateral. If the indebtedness under the Credit Facility were to be accelerated, there can be no assurance that the assets of the Company would be sufficient to repay in full such indebtedness and the other indebtedness of the Company, including the Notes. OPERATING HAZARDS AND UNINSURED RISKS; PRODUCTION CURTAILMENTS Oil and gas drilling activities are subject to numerous risks, many of which are beyond the Company's control, including the risk that no commercially productive oil and gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure irregularities in formations, equipment failure or accidents, adverse weather conditions, title problems and shortages or delays in the delivery of equipment. The Company's future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on future results of operations and financial condition. The Company's properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. Industry operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, the Company maintains insurance against the risks described above. There can be no assurance that any insurance will be adequate to cover losses or liabilities. The Company cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase. GAS GATHERING AND MARKETING The Company's gas gathering and marketing operations depend in large part on the ability of the Company to contract with third party producers to purchase their gas, to obtain sufficient volumes of committed natural gas reserves, to replace production from declining wells, to assess and respond to changing market conditions in negotiating gas purchase and sale agreements and to obtain satisfactory margins between the purchase price of its natural gas supply and the sales price for such natural gas. In addition, the Company's operations are subject to changes in regulations relating to gathering and marketing of oil and gas. The inability of the Company to attract new sources of third party natural gas or to promptly respond to changing market conditions or regulations in connection with its gathering and marketing operations could have a material adverse effect on the Company's financial condition and results of operations. SUBORDINATION OF NOTES AND GUARANTEES The Notes are subordinated in right of payment to all existing and future Senior Debt (as described in the Indenture) of the Company and the Company's subsidiaries that have guaranteed payment of the Notes (the "Subsidiary Guarantors") including borrowings under the Credit Facility. In the event of bankruptcy, liquidation or reorganization of the Company or a Subsidiary Guarantor, the assets of the Company, or the Subsidiary Guarantor as the case may be, will be available to pay obligations on the Notes only after all Senior Debt has been paid in full, and there may not be sufficient assets remaining to pay amounts due on any or all of the Notes outstanding. The aggregate principal amount of Senior Debt of the Company and the Subsidiary Guarantors, on a consolidated basis, as of March 28, 2000 was $12.6 million exclusive of $12.4 million of unused commitments under the Credit Facility. The Subsidiary Guarantees are subordinated to Guarantor Senior Debt to the same extent and in the same manner as the Notes are subordinated to Senior Debt. Additional Senior Debt may be incurred by the Company or the Subsidiary Guarantors from time to time, subject to certain restrictions. In addition to being subordinated to all existing and future Senior Debt of the Company, the Notes will not be secured by any of the Company's assets, unlike the borrowings under the Credit Facility. POSSIBLE UNENFORCEABILITY OF SUBSIDIARY GUARANTEES; DEPENDENCE ON DISTRIBUTIONS BY SUBSIDIARIES Historically, the Company has derived approximately 10% of its operating cash flows from its subsidiary, CGI. The Company's other subsidiary, CCC was incorporated in May 1998 and since its incorporation has had no operations, has acquired no assets and has incurred no liabilities. The holders of the Notes have no direct claim against such subsidiaries other than a claim created by one or more of the Subsidiary Guarantees, which may themselves be subject to legal challenge in a bankruptcy or reorganization case or a lawsuit by or on behalf of creditors of a Subsidiary Guarantor. If such a challenge were upheld, such Subsidiary Guarantees would be invalid and unenforceable. To the extent that any of such Subsidiary Guarantees are not enforceable, the rights of the holders of the Notes to participate in any distribution of assets of any Subsidiary Guarantor upon liquidation, bankruptcy, reorganization or otherwise will, as is the case with other unsecured creditors of the Company, be subject to prior claims of creditors of that Subsidiary Guarantor. The Company relies in part upon distributions from its subsidiaries to generate the funds necessary to meet its obligations, including the payment of principal of and interest on the Notes. The Indenture contains covenants that restrict the ability of the Company's subsidiaries to enter into any agreement limiting distributions and transfers to the Company, including dividends. However, the ability of the Company's subsidiaries to make distributions may be restricted by among other things, applicable state corporate laws and other laws and regulations or by terms of agreements to which they are or may become a party. In addition, there can be no assurance that such distributions will be adequate to fund the interest and principal payments on the Credit Facility and the Notes when due. REPURCHASE OF NOTES UPON A CHANGE OF CONTROL AND CERTAIN OTHER EVENTS Upon a Change of Control (as defined in the Indenture), holders of the Notes may have the right to require the Company to repurchase all Notes then outstanding at a purchase price equal to 101% of the principal amount thereof, plus accrued interest to the date of repurchase. In the event of certain asset dispositions, the Company will be required under certain circumstances to use the Excess Cash (as defined in the Indenture) to offer to repurchase the Notes at 100% of the principal amount thereof, plus accrued interest to the date of repurchase (an "Excess Cash Offer"). The events that constitute a Change of Control or require an Excess Cash Offer under the Indenture may also be events of default under the Credit Facility or other Senior Debt of the Company and the Subsidiary Guarantors, the terms of which may prohibit the purchase of the Notes by the Company until the Company's indebtedness under the Credit Facility or other Senior Debt is paid in full. In addition, such events may permit the lenders under such debt instruments to accelerate the debt and, if the debt is not paid, to enforce security interests on substantially all the assets of the Company and the Subsidiary Guarantors, thereby limiting the Company's ability to raise cash to repurchase the Notes and reducing the practical benefit of the offer to repurchase provisions to the holders of the Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-- Liquidity and Capital Assets." There can be no assurance that the Company will have sufficient funds available at the time of any Change of Control or Excess Cash Offer to make any debt payment (including repurchases of Notes) as described above. Any failure by the Company to repurchase Notes tendered pursuant to a Change of Control Offer (as defined herein) or an Excess Cash Offer will constitute an event of default under the Indenture. RISK OF HEDGING AND OIL TRADING ACTIVITIES From time to time the Company may use energy swap and forward sale arrangements to reduce its sensitivity to oil and gas price volatility. If the Company's reserves are not produced at the rates estimated by the Company due to inaccuracies in the reserve estimation process, operational difficulties or regulatory limitations, or otherwise, the Company would be required to satisfy its obligations under potentially unfavorable terms. If the Company enters into financial instrument contracts for the purpose of hedging prices and the estimated production volumes are less than the amount covered by these contracts, the Company would be required to mark-to-market these contracts and recognize any and all losses within the determination period. Further, under financial instrument contracts, the Company may be at risk for basis differential, which is the difference in the quoted financial price for contract settlement and the actual physical point of delivery price. The Company will from time to time attempt to mitigate basis differential risk by entering into physical basis swap contracts. Substantial variations between the assumptions and estimates used by the Company in the hedging activities and actual results experienced could materially adversely affect the Company's anticipated profit margins and its ability to manage risk associated with fluctuations in oil and gas prices. Furthermore, the fixed price sales and hedging contracts limit the benefits the Company will realize if actual prices rise above the contract prices. In July 1998, the Company began entering into oil trading arrangements as part of its oil marketing activities. Under these arrangements, the Company contracts to purchase oil from one source and to sell oil to an unrelated purchaser, usually at disparate prices. Should the Company's purchaser fail to complete the contracts for purchase, the Company may suffer a loss. The Company's realized gains on these arrangements, determined before $.8 million of transportation costs and related expenses, was $6.3 million for twelve months ended December 31, 1999. The Company's current policy is to limit its exposure from open positions to $1.0 million at any one time. At December 31, 1999 the Company's exposure from open positions on forward crude oil contracts was not material. WRITE DOWN OF CARRYING VALUES The Company periodically reviews the carrying value of its oil and gas properties in accordance with Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of" ("SFAS No. 121"). SFAS No. 121 requires that long-lived assets, including proved oil and gas properties, and certain identifiable intangibles to be held and used by the Company be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for recoverability, the Company estimates the future cash flows expected to result from the use of the asset and its eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying value of the asset, an impairment loss is recognized in the form of additional depreciation, depletion and amortization expense. Measurement of an impairment loss for proved oil and gas properties is calculated on a property-by-property basis as the excess of the net book value of the property over the projected discounted future net cash flows of the impaired property, considering expected reserve additions and price and cost escalations. The Company may be required to write down the carrying value of its oil and gas properties when oil and gas prices are depressed or unusually volatile, which would result in a charge to earnings. Once incurred, a write down of oil and gas properties is not reversible at a later date. LAWS AND REGULATIONS; ENVIRONMENTAL RISK Oil and gas operations are subject to various federal, state and local governmental regulations which may be changed from time to time in response to economic or political conditions. From time to time, regulatory agencies have imposed price controls and limitations on production in order to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations are subject to regulation under federal, state and local laws and regulations. See "Business--Regulation." The Company is subject to a variety of federal, state and local governmental regulations related to the storage, use, discharge and disposal of toxic, volatile or otherwise hazardous materials. These regulations subject the Company to increased operating costs and potential liability associated with the use and disposal of hazardous materials. Although these laws and regulations have not had a material adverse effect on the Company's financial condition or results of operations, there can be no assurance that the Company will not be required to make material expenditures in the future. If such laws and regulations become increasingly stringent in the future, it could lead to additional material costs for environmental compliance and remediation by the Company. The Company's twenty years of experience with the use of HPAI technology has not resulted in any known environmental claims. The Company's saltwater injection operations will pose certain risks of environmental liability to the Company. Although the Company will monitor the injection process, any leakage from the subsurface portions of the wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of operation of the wells, fines and penalties from governmental agencies, expenditures for remediation of the affected resource, and liability to third parties for property damages and personal injuries. In addition, the sale by the Company of residual crude oil collected as part of the saltwater injection process could impose liability on the Company in the event the entity to which the oil was transferred fails to manage the material in accordance with applicable environmental health and safety laws. Any failure by the Company to obtain required permits for, control the use of, or adequately restrict the discharge of, hazardous substances under present or future regulations could subject the Company to substantial liability or could cause its operations to be suspended. Such liability or suspension of operations could have a material adverse effect on the Company's business, financial condition and results of operations. COMPETITION The oil and gas industry is highly competitive. The Company competes for the acquisition of oil and gas properties, primarily on the basis of the price to be paid for such properties, with numerous entities including major oil companies, other independent oil and gas concerns and individual producers and operators. Many of these competitors are large, well established companies and have financial and other resources substantially greater than those of the Company. The Company's ability to acquire additional oil and gas properties and to discover reserves in the future will depend upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. CONTROLLING STOCKHOLDER At March 28, 2000, the principal stockholder, President and Chief Executive Officer and a Director of the Company, beneficially owned 44,496 shares of Common Stock representing, in the aggregate, approximately 91% of the outstanding Common Stock of the Company. As a result, the principal stockholder is in a position to control the Company. The Company is provided oilfield services by several affiliated companies controlled by the principal stockholder. Such transactions will continue in the future and may result in conflicts of interest between the Company and such affiliated companies. There can be no assurance that such conflicts will be resolved in favor of the Company. If the principal stockholder ceases to be an executive officer of the Company, such would constitute an event of default under the Credit Facility, unless waived by the requisite percentage of banks. See "ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT" and "ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS". ITEM 2. PROPERTIES Until 1993, the Company's oil and gas activities were focused in the Mid- Continent. In 1993 the Company made the strategic move to increase oil production and reserves by expanding its development and exploration activities into the Rocky Mountains. The Company currently controls approximately 412,000 net acres in the Rocky Mountains and is ranked among the largest oil producers in the Rocky Mountains. Continental's oil production is characterized by long lived, stable production with high secondary and enhanced oil recovery potential which perpetuates production and cash flow from its properties. Approximately 74% of its estimated proved reserves on a BOE basis at December 31, 1999 were oil. To achieve a more balanced reserve mix, the Company is focusing on generating an increased inventory of natural gas drilling opportunities in the Mid-Continent and Gulf Coast. Currently, 70% of the Company's drilling budget is focused on further expansion and development of its Rocky Mountain oil fields, and the remaining 30% is focused on natural gas projects in the Mid-Continent and Gulf Coast. The Company's Gulf Coast activities are conducted onshore near the Texas and Louisiana coasts and on the shallow shelf of the Gulf of Mexico. In the Gulf Coast, the Company holds approximately 6,000 net leasehold acres and has identified 16 potential drilling locations. The following table provides information with respect to the Company's net proved reserves for its principal oil and gas properties as of December 31, 1999: PERCENT PRESENT OF TOTAL VALUE OF PRESENT OIL FUTURE CASH VALUE OF OIL GAS EQUIVALENT FLOWS(2) FUTURE CASH AREA (MBBL) (MMCF) (MBOE) (M $) FLOWS(2) - ---- ------ ------ ---------- ----------- ----------- ROCKY MOUNTAINS: Williston Basin 20,115 5,264 20,993 $148,149 44.3% Big Horn Basin 14,021 20,955 17,513 98,400 29.4 MID-CONTINENT: Anadarko Basin 2,176 39,426 8,747 70,550 21.1 Arkoma Basin<F1> 2 2,456 411 2,424 .7 GULF COAST 310 7,660 1,586 14,888 4.5 ------ ------ ------ -------- ----- TOTALS 36,624 75,761 49,250 $334,411 100.0% ====== ====== ====== ======== ===== _______________ <FN> <F1> These non-core assets were sold in January 2000 for $5.8 million. <F2> Future estimated net cash flows discounted at 10% </FN> ROCKY MOUNTAINS The Company's Rocky Mountain properties are located primarily in the Williston Basin of North Dakota, South Dakota and Montana and in the Big Horn Basin of Wyoming. Estimated proved reserves for its Rocky Mountains properties at December 31, 1999 totaled 38.5 MMBoe and represented 73.7% of the Company's PV-10. Approximately 94% of these estimated proved reserves are proved developed. During the twelve months ended December 31, 1999, the average net daily production was 7,690 Bbls of oil and 3,399 Mcf of natural gas, or 8,256 Boe per day from the Rocky Mountain properties , excluding the Worland Properties which were contributed by the principal stockholder on December 31, 1999. The addition of the Worland Properties will add approximately 920 Bbls of oil per day and 2,833 Mcf of natural gas, or 1,392 Boe per day. As of December 31, 1999, excluding the contributed properties, the Company is producing approximately 11,857 Boe per day with another 34 Boe per day shut in due to economics or equipment repairs. The Company's leasehold interests include 156,649 net developed and 255,231 net undeveloped acres, which represent 31% and 51% of the Company's total leasehold, respectively. This leasehold is expected to be developed utilizing 3-D seismic, precision horizontal drilling and HPAI, where applicable. As of December 31, 1999, the Company's Rocky Mountain properties included an inventory of 202 development and 6 exploratory drilling locations. WILLISTON BASIN CEDAR HILLS FIELD. The Cedar Hills Field was discovered in November 1994 and is still under development. During the twelve months ended December 31, 1999, the Cedar Hills Field properties produced 4,826 net Boe per day to the Company interests and represented 33% of the PV-10 attributable to the Company's estimated proved reserves as of December 31, 1999. The Cedar Hills Field produces oil from the Red River "B" Formation, a thin (eight feet), non- fractured, blanket-type, dolomite reservoir found at depths of 8,000 to 9,500 feet. All wells drilled by the Company in the Red River "B" Formation were drilled exclusively with precision horizontal drilling technology. The Cedar Hills Field covers approximately 200 square miles and has a known oil column of 1,000 feet. Through December 31, 1999, the Company drilled or participated in 158 gross (108 net) horizontal wells, of which 151 were successfully completed, for a 96% net success rate. The Company believes that the Red River "B" formation in the Cedar Hills Field is well suited for enhanced secondary recovery using HPAI technology. On four nearby HPAI projects operated by the Company, HPAI technology has increased oil recoveries 200% to 300% over primary recovery with ultimate recoveries reaching up to 40% of the original oil in place. The Company intends to initiate installation of HPAI secondary recovery on certain of its Cedar Hills Field properties upon completion of field unitization, which is expected to occur in 2000. The Company believes that HPAI could increase its total recovery from the Cedar Hills Field by as much as 75 million net barrels. On May 15, 1998, the Company and Burlington Resources Oil and Gas Company ("Burlington") entered into a definitive agreement to exchange undivided interests so that effective December 1, 1998 the Company will own working interests ranging from 90% to 92% in approximately 65,000 gross (59,000 net) leasehold acres in the northern half of the Cedar Hills Field. As a result of the agreement, the Company will enhance its ability to unitize all interests in the northern half of the Cedar Hills Field, which is necessary in order for the Company to initiate the planned HPAI enhanced recovery operations in the Cedar Hills Field. On August 19, 1998, the Company instituted a declaratory judgment action against Burlington in the District Court of Garfield County, Oklahoma (Case No. CJ-98-613-03) alleging that Burlington provided false and misleading information regarding certain of Burlington's oil and gas properties to a third party consultant charged with determining the relative values of oil and gas properties owned by the Company and Burlington which served as the basis for the exchange of interests. The Company claimed that the consultant relied on such false and misleading information in determining the relative fair values of the oil and gas interests. The Company sought a declaratory judgment determining that it is excused from further performance under its exchange agreement with Burlington. Burlington denied the Company's allegations and sought specific performance by the Company, plus monetary damages of an unspecified amount. A non-jury trial was held in the case in October 1999. On December 22, 1999, the Court issued an Order requiring the parties to proceed in accordance with terms of the Trade Agreement and instructing them to use their best efforts to finalize the Agreements. Even though Continental is appealing the decision of the Trial Court, it is complying with the Order entered by the Court. As of December 31, 1999, there were 6 horizontal drilling locations in inventory, all of which are development well locations. MEDICINE POLE HILLS, BUFFALO, WEST BUFFALO AND SOUTH BUFFALO UNITS. In 1995, the Company acquired the following interests in four production units in the Williston Basin: Medicine Pole Hills (63%); Buffalo (86%); West Buffalo (82%); and South Buffalo (85%). During the twelve months ended December 31, 1999, these units produced 1,917 Boe per day, net to the Company's interests, and repre- sented 5.8 MMBoe or 8.9% of the PV-10 attributable to the Company's estimated proved reserves as of December 31, 1999. These units are HPAI enhanced recovery projects that produce from the Red River "B" Formation and are operated by the Company. These units were discovered and developed with conventional vertical drilling. The oldest vertical well in these units has been producing for 45 years, demonstrating the long lived production characteristic of the Red River "B" Formation. There are 96 producing wells in these units and current estimates of remaining reserve life range from four to 13 years. As planned, the Company has expanded the Medicine Pole Hills Unit through horizontal drilling and is in the process of forming the West Medicine Pole Hills Unit. The unit encompasses an additional 25 square miles of productive Red River B reservoir and represents first in a two phase expansion of the Medicine Pole Hills Field. Secondary injection is scheduled to begin in the West Medicine Pole Hills Unit during the fourth quarter 2000. The Company will own approximately 80 % of the newly formed unit. During 2000, the Company plans to drill up to 20 horizontal wells as part of phase two to further expand and develop these units. There are currently 28 development drilling locations identified in these units. LUSTRE AND MIDFORK FIELDS. In January 1992, the Company acquired the Lustre and Midfork Fields which, during the twelve months ended December 31, 1999, produced 244 Bbls per day, net to the Company's interests. Wells in both the Lustre and Midfork Fields produce from the Charles "C" dolomite, at depths of 5,500 to 6,000 feet. Historically, production from the Charles "C" has a low daily pro- duction rate and is long lived. There are currently 27 wells producing in the two fields, and no secondary recovery is underway in either field. The Company currently owns 72,000 net acres in the Lustre and Midfork Fields and plans to utilize 3-D seismic combined with horizontal drilling to further exploit the Charles "C" reservoir, and to generate drilling opportunities for deeper objectives underlying the Lustre and Midfork Fields as well as guide exploration for new fields on its substantial undeveloped leasehold. BIG HORN BASIN On May 14, 1998, the Company consummated the purchase for $86.5 million of producing and non-producing oil and gas properties and certain other related assets in the Worland Field, effective as of June 1, 1998. Subsequently, and effective as of June 1, 1998, the Company sold an undivided 50% interest in the Worland Field properties (excluding inventory and certain equipment) to Harold Hamm, the Company's principal stockholder, for $42.6 million. On December 31, 1999 the Company's principal stockholder contributed the undivided 50% interest in the Worland Properties along with debt of $18,600,000. The stockholder contributed $22,461,096 of the properties as additional paid-in-capital and the Company assumed his outstanding debt for the balance of the purchase price. See "Certain Relationships and Related Transactions." The Worland Field properties cover 75,000 net leasehold acres in the Worland Field of the Big Horn Basin in northern Wyoming, of which 30,000 net acres are held by production and 45,000 net acres are non-producing or prospective. Approximately two-thirds of the Company's producing leases in the Worland Field are within five federal units, the largest of which (the Cottonwood Creek Unit) has been producing for over 40 years. All of the units produce principally from the Phosphoria formation, which is the most prolific oil producing formation in the Worland Field. Four of the units are unitized as to all depths, with the Cottonwood Creek Field Extension (Phosphoria) Unit being unitized only as to the Phosphoria formation. The Company is the operator of all five of the federal units. The Company also operates 40 of the 60 producing wells located on non-unitized acreage. The Com- pany's Worland Field properties include interests in 243 producing wells, 230 of which are operated by the Company. As of December 31, 1999, the estimated net proved reserves attributable to the Company's Worland Field properties were approximately 17.5 MMBoe, with an estimated PV-10 of $98.4 million. Approximately 80%, by volume, of these proved reserves consist of oil, principally in the Phosphoria formation. Oil produced from the Company's Worland Field properties is low gravity, sour (high sulphur content) crude, resulting in a lower sales price per barrel than non-sour crude, and is sold into a Marathon pipeline or is trucked from the lease. Gas produced from the Worland Field properties is also sour, resulting in a sale price that is less per Mcf than non-sour natural gas. From the effective date of the Worland Field Acquisition through September 30, 1998, the average price of crude oil produced by the Worland Field properties was $5.19 per Bbl less than the NYMEX price of crude oil. The Company entered into a contract effective October 1, 1998 through March 31, 1999 to sell crude oil produced from its Worland Field properties at an average price of $3.19 per Bbl less than the NYMEX price. Subsequent to these contracts, and effective February 1, 1999 the Company entered into a contract to sell the Worland Field production at a gravity adjusted price of $1.67 per barrel less than the monthly NYMEX average price. The new contract will expire April 1, 2000 and is currently being renegotiated. In addition to the proved reserves, the Company has identified 162 development drilling locations on its Worland Field properties, to further develop and exploit the undeveloped portion of the Worland Field. Over 100 wells have been identified for acid fracture stimulation, most of which have been classified as having proved developed non-producing reserves. The Company believes that secondary and tertiary recovery projects will have significant potential for the addition of reserves. In addition, two exploratory drilling prospects have been identified on the Company's Worland Field properties in which prospects the Company has a majority leasehold position, allowing for further exploration for and exploitation of the Phosphoria, Tensleep, Frontier and Muddy formations and other prospective formations for additional reserves. MID-CONTINENT The Company's Mid-Continent properties are located primarily in the Anadarko Basin of western Oklahoma, southwestern Kansas and the Texas Panhandle, and to a lesser extent, in the Arkoma Basin of southeastern Oklahoma ("Arkoma Basin"). At December 31, 1999, the Company's estimated proved reserves in the Mid-Continent totaled 9.2 MMBoe, representing 21.8% of the Company's PV-10 at such date. At December 31, 1999 approximately 76% of the Company's estimated proved reserves in the Mid-Continent were natural gas. Net daily production from these prop- erties during 1999 averaged 1,113 Bbls of oil and 14,259 Mcf of natural gas, or 3,489 Boe to the Company's interests. The Company's Mid-Continent leasehold position includes 65,454 net developed and 17,439 net undeveloped acres, representing 13% and 3% of the Company's total leasehold, respectively, at December 31, 1999. As of December 31, 1999, the Company's Mid-Continent properties included an inventory of ten development drilling locations, all of them in the Anadarko Basin. ANADARKO BASIN. The Anadarko Basin properties contained 99% of the Company's estimated proved reserves for the Mid-Continent and 21.1% of the Company's total PV-10 at December 31, 1999 and at such date, represented 52% of the Company's estimated proved reserves of natural gas. During the twelve months ended December 31, 1999, net daily production from its Anadarko Basin properties averaged 1,113 Bbls of oil and 13,002 Mcf of natural gas, or 3,280 Boe to the Company's interest from 534 gross (319 net) producing wells, 422 of which are operated by the Company. The Anadarko Basin wells produce from a variety of sands and carbonates in both stratigraphic and structural traps in the Arbuckle, Oil Creek, Viola, Mississippian, Springer, Morrow, Red Ford, Oswego, Skinner and Tonkawa formations, at depths ranging from 6,000 to 12,000 feet. These properties are currently being re-evaluated for further development drilling and workover potential. ARKOMA BASIN. In the Arkoma Basin, the Company was focused on coal bed methane, where it owned approximately 12,000 acres and had 40 producing wells from the Hartshorne coal at depths of 2,500 to 3,500 feet. As part of the Company's strategic plan to divest of non-core assets for the purpose of allocating resources to higher reserve growth projects, all oil and gas properties in the Arkoma Basin, along with the Rattlesnake and Enterprise Gas Gathering System, were sold in January 2000 for $5.8 million. The PV-10 of the reserves on these properties was approximately $2.4 million. GULF COAST The Company's Gulf Coast activities are located primarily in the Pebble Beach Project in Nueces County, Texas and the Jefferson Island Project in Iberia Parish, Louisiana. During 1999 the Company also entered into a joint venture arrangement with Challanger Minerals to expand its drilling activities into the shallow shelf area of the Gulf of Mexico. At December 31, 1999, the Company's estimated proved reserves in the Gulf Coast totaled 1.6 MMBOE (80% gas) representing 4.5% of the Company's total PV10 and 10% of the Company's estimated proved reserves of natural gas. Net daily production from these properties is 56 Bbls of oil and 3200 Mcf of natural gas or 589 Boe to the Company's interest from 11 wells. The Company's leasehold position includes 1,526 net developed and 4,515 net undeveloped acres representing .3% and .9% of the Company's total leasehold respectively. From a combined total of 68 square miles of proprietary 3-D data, 16 development and 11 exploratory locations have been identified for drilling on these projects to date. JEFFERSON ISLAND. The Jefferson Island project is an underdeveloped salt dome that produces from a series of prolific Miocene sands. To date the field has produced 65.2 MMBOE from approximately one quarter of the total dome. The remaining three quarters of the faulted dome complex are essentially unexplored or underdeveloped. The Company has acquired 35 square miles of proprietary 3-D seismic covering the property and has identified 13 development and 5 explora- tory drilling locations to date. The first well drilled off the 3-D data was successful and a second well is scheduled to be drilled in the first quarter 2000. The Company plans to drill one well per quarter to carefully incorporate new well data into the 3-D seismic and allow a third party to complete a 5 well drilling obligation to earn 50% of the project. The third party has drilled two of the five obligation wells to date and will drill the remaining three during 2000. The Company controls 2,393 gross and 1,406 net acres in the project. PEBBLE BEACH. The Pebble Beach project targets the prolific Frio and Vicksburg sands underlying and surrounding the Clara Driscoll field. These sandstones are found at depths ranging from 5000' to 9500' and produce on structures readily defined by seismic. Using 20 square miles of proprietary 3-D seismic, the Company has identified 3 development and 5 exploratory drilling locations. During 1999 the Company established significant production from the project and plans to continue drilling and expanding the project through 2000. The Company has scheduled two wells for the first half of 2000 and the acquisition of additional proprietary 3-D seismic to expand the project. The Company owns 7,685 gross and 4,564 net acres in the project. GULF OF MEXICO. During 1999 the Company elected to expand its drilling program into the shallow waters of the Gulf of Mexico though a joint venture arrangement with Challanger Minerals. This is part of the Company's ongoing strategy to build its opportunity base of high rate of return, natural gas op- portunities in the Gulf Coast region. The Company will not operate and expects to participate only in projects with turnkey drilling contracts. Drilling expenditures in the Gulf of Mexico will be restricted to under $500,000 per project while the Company builds experience in this new area. As of December 31, 1999, the Company has participated in 2 wells which resulted in one excellent producer with added behind pipe pay. The Company currently has one well in inventory and expects it will spend no more than 10% of its drilling budget on Gulf of Mexico drilling opportunities during 2000. NET PRODUCTION, UNIT PRICES AND COSTS The following table presents certain information with respect to oil and gas production, prices and costs attributable to all oil and gas property interests owned by the Company for the periods shown: YEAR ENDED DECEMBER 31 ---------------------------- 1997 1998 1999 ---- ---- ---- NET PRODUCTION DATA: Oil and condensate (MBBL) 3,518 3,981 3,221 Natural gas (MMCF) 5,789 6,755 6,640 Total (MBOE) 4,483 5,107 4,328 UNIT ECONOMICS Average sales price per Bbl $ 18.61 $ 12.38 $ 16.93 Average sales price per Mcf 2.21 1.61 1.72 Average equivalent price (per Boe)<F1> 17.53 11.78 15.24 Lifting cost (per Boe)<F2> 4.63 4.43 4.47 DD&A expense (per Boe)<F2> 6.74 6.78 3.61 General and administrative expense (per Boe)<F3> 1.47 1.40 1.31 ------- ------- ------- Gross margin $ 4.69 $ (0.83) $ 5.85 ======= ======= ======= - -------------- <FN> <F1> Calculated by dividing oil and gas revenues, as reflected in the Consolidated Financial Statements, by production volumes on a Boe basis. Oil and gas revenues reflected in the Consolidated Financial Statements are recognized as production is sold and may differ from oil and gas revenues reflected on the Company's production records which reflect oil and gas revenues by date of production. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." <F2> Related to drilling and development activities. <F3> Related to drilling and development activities, net of operating overhead income. </FN> PRODUCING WELLS The following table sets forth the number of productive wells in which the Company owned an interest as of December 31, 1999: OIL NATURAL GAS ---------------- -------------- GROSS NET GROSS NET ----- --- ----- --- ROCKY MOUNTAINS: Williston Basin 291 226 - - Big Horn Basin<F1> 242 216 1 - MID-CONTINENT: Anadarko Basin 311 217 223 102 Other - - 40 35 GULF COAST 5 3 6 4 --- --- --- --- Total 849 662 270 141 === === === === - --------------- <FN> <F1> Represents Worland Field properties acquired by the Company in the Worland Field Acquisition. </FN> ACREAGE The following table sets forth the Company's developed and undeveloped gross and net leasehold acreage as of December 31, 1999: DEVELOPED UNDEVELOPED ----------------- ----------------- GROSS NET GROSS NET ----- --- ----- --- ROCKY MOUNTAINS: Williston Basin 167,913 126,460 272,334 210,044 Big Horn Basin 30,189 30,189 45,187 45,187 MID-CONTINENT: Anadarko Basin 91,775 53,729 14,909 8,697 Other 12,588 11,725 8,786 8,742 GULF COAST 2,339 1,526 8,460 4,515 ------- ------- ------- ------- Total 304,804 223,629 349,676 277,185 ======= ======= ======= ======= DRILLING ACTIVITIES The following table sets forth the Company's drilling activity on its properties for the periods indicated: YEAR ENDED DECEMBER 31, ---------------------------------------- 1997 1998 1999 ------------ ------------ ----- --- GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- DEVELOPMENT WELLS: Productive 63 42.41 32 22 12 6.90 Non-productive - - - - 1 .16 -- ----- -- ----- -- ----- Total 63 42.41 32 22 13 7.06 == ===== == ===== == ===== EXPLORATORY WELLS: Productive 15 11.29 5 4.23 2 .74 Non-productive 5 1.98 - - 2 1.25 -- ----- -- ----- -- ----- Total 20 13.27 5 4.23 4 1.99 == ===== == ===== == ===== OIL AND GAS RESERVES The following table summarizes the estimates of the Company's net proved oil and gas reserves and the related PV-10 of such reserves at the dates shown. Ryder Scott Company Petroleum Engineers ("Ryder Scott") prepared the reserve and present value data with respect to the Company's oil and gas properties which represented 72% of the PV-10 at December 31, 1997, 83% of the PV-10 at December 31, 1998 and December 31, 1999. The Company prepared the reserve and present value data on all other properties. AS OF DECEMBER 31, ------------------------------ 1997 1998 1999 ---- ---- ---- (DOLLARS IN THOUSANDS) RESERVE DATA: Proved developed reserves: Oil (MBBL) 19,411 19,097 34,432 Natural gas (MMCF) 47,676 54,905 65,723 Total (MBOE) 27,357 28,248 45,386 Proved undeveloped reserves: Oil (MBBL) 5,308 833 2,192 Natural gas (MMCF) 1,702 314 10,038 Total (MBOE) 5,592 885 3,865 Total proved reserves: Oil (MBBL) 24,719 19,930 36,624 Natural gas (MMCF) 49,378 55,219 75,761 Total (MBOE) 32,949 29,133 49,251 PV-10<F1> $ 241,625 $ 107,670 $ 334,411 - ---------------- <FN> <F1> PV-10 represents the present value of estimated future net cash flows before income tax discounted at 10% using prices in effect at the end of the respective periods presented and including the effects of hedging activities. In accordance with applicable requirements of the Commission, estimates of the Company's proved reserves and future net cash flows are made using oil and gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). The prices used in calculating PV-10 as of December 31, 1997, 1998 and 1999 were $18.06 per Bbl of oil and $2.25 per Mcf of natural gas, $10.84 per Bbl of oil and $1.64 per Mcf of natural gas, $24.38 per Bbl of oil and $1.76 per Mcf of natural gas, respectively. </FN> Estimated quantities of proved reserves and future net cash flows therefrom are affected by oil and gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the control of the producer. The reserve data set forth in this annual report on Form 10-K represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers, including those used by the Company, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and gas prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. In general, the volume of production from oil and gas properties declines as reserves are depleted. Except to the extent the Company acquires properties containing proved reserves or conducts successful exploitation and development activities, the proved reserves of the Company will decline as reserves are produced. The Company's future oil and gas production is, therefore, highly dependent upon its level of success in finding or acquiring additional reserves. GAS GATHERING SYSTEMS The Company's gas gathering systems are owned by CGI. Natural gas and casinghead gas are purchased at the wellhead primarily under either market- sensitive percent-of-proceeds-index contracts or keep-whole gas purchase contracts or of fee based contracts. Under percent-of-proceeds-index contracts, CGI receives a fixed percentage of the monthly index posted price for natural gas and a fixed percentage of the resale price for natural gas liquids. CGI generally receives between 20% and 30% of the posted index price for natural gas sales and from 20% to 30% of the proceeds received from natural gas liquids sales. Under keep-whole gas purchase contracts, CGI retains all natural gas liquids recovered by its processing facilities and keeps the producers whole by returning to the producers at the tailgate of its plants an amount of residue gas equal on a BTU basis to the natural gas received at the plant inlet. The keep-whole component of the contract permits the Company to benefit when the value of natural gas liquids is greater as a liquid than as a portion of the residue gas stream. Under the fee based contracts, CGI receives a fixed rate per MMBTU of gas purchased. This rate per MMBTU remains fixed regardless of commodity prices. OIL AND GAS MARKETING The Company's oil and gas production is sold primarily under market sensitive or spot price contracts. The Company sells substantially all of its casinghead gas to purchasers under varying percentage-of-proceeds contracts. By the terms of these contracts, the Company receives a fixed percentage of the resale price received by the purchaser for sales of natural gas and natural gas liquids recovered after gathering and processing the Company's gas. The Company normally receives between 80% and 100% of the proceeds from natural gas sales and from 80% to 100% of the proceeds from natural gas liquids sales received by the Company's purchasers when the products are resold. The natural gas and natural gas liquids sold by these purchasers are sold primarily based on spot market prices. The revenues received by the Company from the sale of natural gas liquids is included in natural gas sales. As a result of the natural gas liquids contained in the Company's production, the Company has historically improved its price realization on its natural gas sales as compared to Henry Hub or other natural gas price indexes. For the year ended December 31, 1999, purchases of the Company's natural gas production by GPM Gas Corporation accounted for 12% of the Company's total gas sales for such period and for the same period purchases of the Company's oil production by EOTT Energy Corp. accounted for 65% and Plains Marketing and Transportation accounted for 12% of the Company's total produced oil sales. Due to the availability of other markets, the Company does not believe that the loss of any crude oil or gas customer would have a material effect on the Company's results of operations. Periodically the Company utilizes various hedging strategies to hedge the price of a portion of its future oil and gas production. The Company does not establish hedges in excess of its expected production. These strategies customarily emphasize forward-sale, fixed-price contracts for physical delivery of a specified quantity of production or swap arrangements that establish an index-related price above which the Company pays the hedging partner and below which the Company is paid by the hedging partner. These contracts allow the Company to predict with greater certainty the effective oil and gas prices to be received for its hedged production and benefit the Company when market prices are less than the fixed prices provided in its forward-sale contracts. However, the Company does not benefit from market prices that are higher than the fixed prices in such contracts for its hedged production. In August 1998, the Company began engaging in oil trading arrangements as part of its oil marketing activities. Under these arrangements, the Company contracts to purchase oil from one source and to sell oil to an unrelated purchaser, usually at disparate prices. ITEM 3. LEGAL PROCEEDINGS From time to time, the Company is party to litigation or other legal pro- ceedings that it considers to be a part of the ordinary course of its business. The Company is not involved in any legal proceedings nor is it party to any pending or threatened claims that could reasonably be expected to have a material adverse effect on its financial condition or results of operations. However, the Company is engaged in litigation with Burlington with respect to the agreement to exchange interests in the Cedar Hills Field. See ITEM 2. PROPERTIES. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS There is no established trading market for the Company's common stock. As of March 28, 2000, there were 3 record holders of the Company's common stock. The Company issued no equity securities during 1999. ITEM 6. SELECTED FINANCIAL AND OPERATING DATA SELECTED CONSOLIDATED FINANCIAL DATA The following table sets forth selected historical consolidated financial data for the periods ended and as of the dates indicated. The statements of opera- tions and other financial data for the years ended December 31, 1995, 1996, 1997, 1998 and 1999, and the balance sheet data as of December 31, 1995, 1996, 1997, 1998 and 1999 have been derived from, and should be reviewed in con- junction with, the consolidated financial statements of the Company, and the notes thereto, which have been audited by Arthur Andersen LLP, independent public accountants. The balance sheets as of December 31, 1998, and 1999 and the statements of operations for the years ended December 31, 1997, 1998 and 1999 are included elsewhere in this annual report on Form 10-K. The data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and the related notes thereto included elsewhere in this Report. YEAR ENDED DECEMBER 31, ------------------------------------------------ 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- (DOLLARS IN THOUSANDS) STATEMENT OF OPERATIONS DATA: Revenue: Oil and gas sales $ 30,576 $ 75,016 $ 78,599 $ 60,162 $ 65,949 Crude oil marketing - - - 232,216 241,630 Gathering, marketing and processing 20,639 25,766 25,021 17,701 21,563 Oil and gas service operations 6,148 6,491 6,405 6,689 6,319 -------- -------- -------- -------- -------- Total revenues 57,363 107,273 110,025 316,768 335,461 Operating costs and expenses: Production expenses and taxes 7,611 19,338 20,748 22,611 19,368 Exploration expenses 6,184 4,512 6,806 7,106 7,750 Crude oil marketing purchases and expenses - - - 228,797 236,135 Gathering, marketing and processing 13,223 21,790 22,715 15,602 17,850 Oil and gas service operations 3,680 4,034 3,654 3,664 3,420 Depreciation, depletion and amortization 9,614 22,876 33,354 38,716 20,385 General and administrative 8,260 9,155 8,990 10,002 8,627 -------- -------- -------- -------- -------- Total operating costs and expenses 48,572 81,705 96,267 326,498 313,535 -------- -------- -------- -------- -------- Operating income (loss) 8,791 25,568 13,758 (9,730) 21,926 Interest income 137 312 241 967 310 Interest expense (2,396) (4,550) (4,804) (12,248) (16,534) Change in accounting principle 0 0 0 0 (2,048) Other revenue (expense), net(1) (411) 233 8,061 3,031 266 -------- -------- -------- -------- -------- Income before income taxes 6,121 21,563 17,256 (17,980) 3,920 Federal and state income taxes (benefit)(2) 2,252 8,238 (8,941) - - -------- -------- -------- -------- -------- Net income (loss) $ 3,869 $ 13,325 $ 26,197 $(17,980) $ 3,920 ======== ======== ======== ======== ======== OTHER FINANCIAL DATA: Adjusted EBITDA(3) $ 24,315 $ 53,502 $ 54,721 $ 40,090 $ 48,589 Net cash provided by operations 18,985 41,724 51,477 25,190 23,904 Net cash used in investing (58,022) (50,619) (78,359) (112,050) (13,698) Net cash provided by (used in) financing 37,994 10,494 24,863 101,376 (15,602) Capital expenditures(4) 58,226 50,341 80,937 92,782 55,255 RATIOS: Adjusted EBITDA to interest expense 10.1x 11.8x 11.4x 3.3x 3.0x Total debt to Adjusted EBITDA 1.8x 1.0x 1.5x 4.2x 3.5x Earnings to fixed charges(5) 3.6x 5.7x 4.6x N/A 1.2x BALANCE SHEET DATA (AT PERIOD END): Cash and cash equivalents $ 1,722 $ 3,320 $ 1,301 $ 15,817 $ 10,421 Total assets 107,825 145,693 188,386 253,739 282,559 Long-term debt, including current maturities 44,265 54,759 79,632 167,637 170,637 Stockholders' equity 38,752 52,077 78,264 60,284 86,666 See Notes to Selected Consolidated Financial Data. NOTES TO SELECTED CONSOLIDATED FINANCIAL DATA (1) In 1997, other income includes $7.5 million resulting from the settlement of certain litigation matters. (2) Effective June 1, 1997, the Company elected to be treated as an S-Corpo- ration for federal income tax purposes. The conversion resulted in the elimination of the Company's deferred income tax assets and liabilities existing at May 31, 1997 and, after being netted against the then exist- ing tax provision, resulted in a net income tax benefit to the Company of $8.9 million. (3) Adjusted EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization and exploration expense, excluding proceeds from litigation settlements. Adjusted EBITDA is not a measure of cash flow as determined in accordance with GAAP. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. The Company's computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. The Company believes that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure the Company's ability to meet future debt service requirements, if any. Even though the volume of oil and gas produced by the Company during 1999 was less than in the comparable period in 1998, the Company's Adjusted EBITDA for the 1999 period was greater than in 1998. The increase in Adjusted EBITDA for the 1999 period was attributable to increases in oil and gas prices. Adjusted EBITDA does not give effect to the Company's exploration expenditures, which are largely discretionary by the Company and which, to the extent expended, would reduce cash available for debt service, repayment of indebtedness and dividends. (4) Capital expenditures include costs related to acquisitions of producing oil and gas properties and includes the contribution of the Worland properties by the principal stockholder of $22.4 million. (5) For purposes of computing the ratio of earnings to fixed charges, earnings are computed as income before taxes from continuing operations, plus fixed charges. Fixed charges consist of interest expense and amortization of costs incurred in the offering of the Notes. For the year ended December 31, 1998, earnings were insufficient to cover fixed charges by $18.0 million. (6) Cumulative effect represents the impact of adopting EITF 98-10 "Accounting for Energy Trading and Risk Management Activities." ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with the Company's consolidated financial statements and notes thereto and the Selected Consoli- dated Financial Data included elsewhere herein. OVERVIEW The Company's revenue, profitability and cash flow are substantially dependent upon prevailing prices for oil and gas and the volumes of oil and gas it pro- duces. Although the Company produced less oil and gas in 1999 than in 1998, it experienced a significant increase in revenues, net income and Adjusted EBITDA in 1999 compared to 1998 because of higher prevailing oil and gas prices. Average well head prices as of December 31, 1999, were $24.38 per Bbl of oil and $1.76 per Mcf of natural gas compared to $10.84 per Bbl of oil and $1.64 per Mcf of natural gas as of December 31, 1998. In addition, the Company's proved reserves and oil and gas production will decline as oil and gas are produced unless the Company is successful in acquiring producing properties or conducting successful exploration and development drilling activities. The Company uses the successful efforts method of accounting for its invest- ment in oil and gas properties. Under the successful efforts method of account- ing, costs to acquire mineral interests in oil and gas properties, to drill and provide equipment for exploratory wells that find proved reserves and to drill and equip development wells are capitalized. These costs are amortized to operations on a unit-of-production method based on petroleum engineering estimates. Geological and geophysical costs, lease rentals and costs associated with unsuccessful exploratory wells are expensed as incurred. Maintenance and repairs are expensed as incurred, except that the cost of replacements or renewals that expand capacity or improve production are capitalized. Significant downward revisions of quantity estimates or declines in oil and gas prices that are not offset by other factors could result in a write down for impairment of the carrying value of oil and gas properties. Once incurred, a write down of oil and gas properties is not reversible at a later date, even if oil or gas prices increase. The Company is an S-Corporation for federal income tax purposes. The Company currently anticipates it will pay periodic dividends in amounts sufficient to enable the Company's stockholders to pay their income tax obligations with respect to the Company's taxable earnings. Based upon funds available to the Company under its Credit Facility and the Company's anticipated cash flow from operating activities, the Company does not currently expect these distributions to materially impact the Company's liquidity. RESULTS OF OPERATIONS The following tables set forth selected financial and operating information for each of the three years in the period ended December 31, 1999: YEAR ENDED DECEMBER 31, ---------------------------------- 1997 1998 1999 ---- ---- ---- (Dollars in Thousands, Except Average Price Data) Revenues $ 110,025 $ 316,768 $ 335,461 Operating expenses 96,267 326,498 313,535 Non-Operating income (expense) 3,498 (8,250) (15,958) Change in accounting principle (2,048) Net income after tax 26,197 (17,980) 3,920 Adjusted EBITDA<F1> 54,721 40,090 48,589 Production Volumes<F2>: Oil and condensate (MBBL) 3,518 3,981 3,221 Natural gas (MMCF) 5,789 6,755 6,640 Oil equivalents (MBOE) 4,483 5,107 4,328 Average Prices<F3>: Oil and condensate (per Bbl) $ 18.61 $ 12.52 $ 16.93 Natural gas (per Mcf) 2.21 1.61 1.72 Oil equivalents (per Boe) 17.53 11.78 15.24 - --------------- <FN> <F1> Adjusted EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization and exploration expense, excluding proceeds from litigation settlements. Adjusted EBITDA is not a measure of cash flow as determined in accordance with GAAP. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. The Company's computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. The Company believes that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure the Company's ability to meet future debt service requirements, if any. Even though the volume of oil and gas produced by the Company during 1999, on an actual basis, was less than in the comparable period in 1998, the Company's Adjusted EBITDA for the 1999 period was greater than in 1998. The increase in Adjusted EBITDA for the 1999 period was attributable to increases in oil and gas prices. Adjusted EBITDA does not give effect to the Company's exploration expenditures, which are largely discretionary by the Company and which, to the extent expended, would reduce cash available for debt service, repayment of indebtedness and dividends. <F2> Production volumes of oil and condensate, and natural gas, are derived from the Company's production records and reflect actual quantities produced without regard to the time of receipt of proceeds from the sale of such production. Production volumes of oil equivalents (on a Boe basis) are determined by dividing the total Mcfs of natural gas produced by six and by adding the resultant sum to barrels of oil and condensate produced. <F3> Average prices of oil and condensate, and of natural gas, are derived from the Company's production records which are maintained on an "as produced" basis, which give effect to gas balancing and oil produced and in the tanks, and, accordingly, may differ from oil and gas revenues for the same periods as reflected in the Financial Statements. Average prices of oil equivalents were calculated by dividing oil and gas revenues, as reflected in the Financial Statements, by production volumes on a per Boe basis. Average sale prices per Boe realized by the Company, according to its production records which are maintained on an "as produced" basis, for the years ended December 31, 1997, 1998 and 1999, were $17.53, $11.88 and $15.31, respectively. </FN> YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998 REVENUES OIL AND GAS SALES Oil and gas sales revenue for 1999 increased $5.8 million, or 10%, to $65.9 million from $60.1 million in 1998. Oil prices increased from an average of $12.38/Bbl in 1998 to $16.93/Bbl in 1999 which resulted in a $14.7 million increase in revenues. The effects of the price increase were partially offset by a 760 Mbbl decrease in oil production in 1999 compared to 1998. The decreased production was due to the natural production declines for new wells and to low drilling activities in 1999. During 1999 the Company chose to reduce debt rather than drill due to the instability of oil prices. The Company's average gas sales prices increased from $1.61 per Mcf in 1998 to $1.72 per Mcf in 1999. CRUDE OIL MARKETING The Company recognized an increase in revenues on crude oil purchased for resale for 1999 of $9.4 million, or 4% to $241.6 million from $232.2 million for 1998. This was caused by increases in oil prices and was also due to only a partial year of activity in 1998 compared to a full year in 1999 and is offset by a decrease in monthly volumes traded. GATHERING, MARKETING AND PROCESSING The 1999 gathering, marketing and processing revenues increased $3.9 million, or 22%, to $21.6 million compared to $17.7 million for 1998. $1.7 million of the increase was attributable to operations from the Eagle Chief Plant in Oklahoma and $0.9 million was from the addition of the Matli gas gathering system and $0.7 million from the Badlands Gas Processing Plant. OIL AND GAS SERVICE OPERATIONS Oil and gas service operations revenues decreased $.4 million, or 6%, to $6.3 in 1999 from $6.7 million in 1998. The decrease was primarily attributable to reduced sales of inventory caused by lower drilling activity in 1999. COSTS AND EXPENSES PRODUCTION EXPENSES & TAXES Production expense and taxes were $19.4 million for 1999, a $3.2 million, or 14% decrease, over the 1998 expenses of $22.6 million, primarily as a result of lower production volumes and greater operating efficiencies. The decrease was seen in all areas of direct costs associated with the Company's operations, ex- cept for taxes. Taxes increased by $0.9 million due to higher prices and the expiration of drilling tax credits primarily in the Cedar Hills area of North Dakota. EXPLORATION EXPENSE Exploration expenses increased $0.6 million, or 8%, to $7.7 million in 1999 from $7.1 million in 1998. The increase was attributable to a $3.2 million increase in expired leases partially offset by a decrease in dry hole costs and other expenses of $2.6 million. CRUDE OIL MARKETING Expense for the purchases of crude oil purchased for resale increased $7.2 million, or 3%, to $235.3 million in 1999 from $228.1 million in 1998. Marketing expenses increased $0.1 million, or 22%, to $0.8 million in 1999 from $0.7 million in 1998. This increase was caused by increased crude oil prices and was also due to only a partial year of activity in 1998 compared to a full year in 1999 and is offset by a decrease in monthly volumes traded. GATHERING, MARKETING AND PROCESSING Gathering, Marketing and Processing expense for 1999 was $17.8 million, a $2.2 million, or 14%, increase from the $15.6 million incurred in 1998 due to higher natural gas and liquid prices and the addition of the Matli gas gathering system and the increase in the Badlands system in North Dakota. DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A) For the year ended December 31, 1999, total DD&A Expense was $20.4 million, a $18.3 million, or 47%, decrease over the 1998 expense of $38.7 million. In 1999, lease and well DD&A was $15.6 million, a decrease of $19 million from $34.6 million in 1998. The decrease is due to favorable adjustments to reserve volumes caused by higher oil and gas prices resulting in a decline in the DD&A rate per Boe and due to the non recurring $7.9 million write-down associated with FASB 121 in 1998. There was no FASB 121 write-down in 1999. In 1998, the FASB 121 write-down contributed $1.55 per Boe , or 23%, of the lease and well DD&A expense of $6.78 per Boe. For 1999 DD&A expense amounted to $3.61 per Boe. GENERAL AND ADMINISTRATIVE (G&A) G&A expense for 1999 was $8.6 million, net of overhead reimbursement of $2.9 million, or $5.7 million, a decrease of $1.4 million, or 21%, from G&A expenses for 1998 of $10.0 million, net of overhead reimbursement of $2.9 million, or $7.1 million. The decrease is primarily attributable to a decrease in employment expenses, including a temporary decrease in payroll and benefit costs as described below. On January 6, 1999, as part of its objective of focusing on cash margins and profitability, the Company initiated a cost restructuring plan which included personnel cost reductions which were included in G&A expense. This reduction was accomplished through a combination of personnel and payroll reductions and the temporary suspension of the Company's contribution to the Company 401K plan. Permanent savings due to staff reductions was approximately $0.5 million in 1999. An additional $0.3 million in savings was recognized in other employee expenses. Various other office expenses decreased by $0.7 million. The Company reinstated its contribution to the company 401K plan effective April 1, 1999, and salaries were returned to their previous level effective May 1, 1999. INTEREST INCOME Interest income for 1999 was $0.3 million compared to $1.0 million for 1998, a $0.7 million, or 68% decrease. The decrease in the 1999 period is attributable to lower levels of cash invested during 1999. INTEREST EXPENSE Interest expense for 1999 was $16.5 million, an increase of $4.3 million, or 35%, from $12.2 million in 1998. The increase in the 1999 expense is attributable primarily to the interest on the Senior Subordinated notes which had only accrued five months of interest expense in 1998 compared to 12 months in 1999. In May 1998, the Company entered into a forward interest rate swap contract to hedge its exposure to changes in the prevailing interest rates in connection with its planned debt offering. Due to the change in treasury note rates, the Company paid $3.9 million to settle the forward interest rate swap contract, which will result in an effective increase of approximately 0.5% to the Com- pany's interest costs on the Notes, or an increase in interest expense of approximately $0.4 million for the term of the Notes. OTHER INCOME Other income decreased $2.7 million, or 91%, to $0.3 million for the year ended December 31, 1999 from $3.0 million for 1998. This decrease in other income compared to 1998 is attributed primarily to the recognition in 1998 of a $2.5 million gain on the sale of the Illinois properties. INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE Net income before income taxes and change in accounting principle for the year ended December 31, 1999 was a gain of $5.9 million, an increase in net income before taxes of $23.8 million from a $17.9 million loss before taxes and cumulative effect of change in accounting principle for 1998. This increase was primarily due to the increased revenues caused by higher oil and gas sales prices and lower operating and general and administrative costs. NET INCOME The 1999 Net Income after taxes was $3.9 million, including a charge result- ing from a cumulative effect of change in accounting principle of $2.0 million, an increase in net income of $21.9 million compared to a loss of $17.9 million in 1998. The Company adopted EITF 98-10 effective January 1, 1999. As a result, the Company recorded an expense for the cumulative effect of change in account- ing principle of $2,048,000. YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 OIL AND GAS SALES Oil and gas sales revenue for 1998 decreased $18.4 million, or 23.5%, to $60.2 million from $78.6 million in 1997. Oil prices decreased from an average of $18.61/Bbl in 1997 to $12.38/Bbl in 1998 which resulted in a $21.9 million re- duction in revenues. The effects of the price reduction was partially offset by a 463 Mbbl increase in oil production in 1998 compared to 1997. The increased production was realized from the acquisition of the Worland Field properties which contributed 234 MBBL of oil production after the June 1, 1998 acquisition date and from the further development of the Cedar Hills and Midfork/Lustre fields through drilling which contributed an additional 384 MBBL of oil pro- duction. Company production volumes decreased by 20 MBBL with the fourth quarter sale of its Illinois properties and by 120 MBbls due to the natural decline in production rates in the Company's existing HPAI units. The net increase in production resulted in additional revenues of $5.7 million for the period. Gas revenues for 1998 increased by $1.6 million due to the sale of an additional 966 MMCF of production. The revenue due to the increase in pro- duction was partially offset by a $3.5 million reduction in revenues due to lower gas sales prices realized during the year when compared to 1997. The Company's average gas sales prices decreased from $2.21 per Mcf in 1997 to $1.61 per Mcf in 1998 on a company average. CRUDE OIL MARKETING The Company began marketing crude oil purchased from third parties in July, 1998. The Company recognized revenues on crude oil purchased for resale of $232.2 million for 1998. GATHERING, MARKETING AND PROCESSING As a result of the elimination of gas sales associated with purchases of gas to be sold for marketing purposes unrelated to gas processing, 1998 gathering, marketing and processing revenues decreased $7.3 million, or 29%, to $17.7 mil- lion compared to $25.0 million for 1997. OIL AND GAS SERVICE OPERATIONS Oil and gas service operations revenues increased $.3 million, or 4.4%, to $6.7 in 1998 from $6.4 million in 1997. Revenues in 1998 increased due to an increase in administrative income compared to the 1997 period because of increased overhead reimbursement associated with the increased maintenance activities performed on company operated properties during 1998. COSTS AND EXPENSES PRODUCTION EXPENSE AND TAXES Production expense and taxes were $22.6 million for the twelve months ended December 31, 1998, a $1.9 million, or 9% increase, over the 1997 expenses of $20.7 million, primarily as a result of the Worland Field Acquisition. For the year, the Company has incurred $1.7 million in operating costs on the Worland Field properties. The Company also incurred $0.7 million in non-recurring charges to repair several air injection and producing wells in the High Pres- sure Air Injection Units. EXPLORATION EXPENSE Exploration expenses increased $0.3 million, or 4%, to $7.1 million in 1998 from $6.8 million in 1997. The Company recognized expense on the expiration of $2.0 million in leasehold associated with non-core areas which was $0.8 million greater than the leasehold expiration expense of $1.2 million recognized in 1997. During 1998 leases on 40,000 net acres in which the Company has an invest- ment of $2.2 million will expire. The Company has not determined if these leases will be drilled, renewed, or allowed to expire. CRUDE OIL MARKETING The Company began marketing crude oil purchased from third parties during 1998. For the year ended December 31, 1998, the Company recognized expense for the purchases of crude oil purchased for resale of $228.1 million and marketing expenses of $0.7 million. GATHERING, MARKETING AND PROCESSING Gathering, Marketing and Processing expense for 1998 was $15.6 million, a $7.1 million, or 31%, decrease from the $22.7 million incurred in 1997. This de- crease is mainly due to the elimination of purchases of third party gas not used for gas plant supply, but sold as part of the Company's gas marketing activities which have been reduced to minimal volumes. DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A) For the year ended December 31, 1998, DD&A Expenses were $38.7 million, a $5.4 million, or 16%, increase over the 1997 expense of $33.4 million. Lease and Well depletion and depreciation increased $4.0 million mainly due to the $7.9 million write-down associated with FASB 121 in 1998 compared to the $5.0 million write- down recognized in 1997. In 1998, the FASB 121 write-down contributed $1.55 per Boe , or 23%, of the total DD&A expense of $6.78 per Boe produced. The FASB 121 write-down in 1997 contributed $1.12 per Boe, or 17%, to the $6.74 per Boe of DD&A expense. The 1998 write-down included the impairment of $3.6 million on ten step out properties on the fringes of the Cedar Hills Field in North Dakota. The Company has excluded these wells from the exchange agreement with Burlington and does not expect them to be included in future unitization plans. Because of these factors, the reserves associated with these wells are low and provide minimal future cash flow. The 1998 DD&A expense also included $0.6 million of amortization expense associated with the capitalized costs related to the Company's $150 million debt offering. GENERAL AND ADMINISTRATIVE (G&A) G&A expense for 1998 was $10.0 million, net of overhead reimbursement of $2.9 million, an increase of $0.5 million, or 9%, to $7.1 million from $9.0 million, net of overhead reimbursement of $2.4 million, or $6.6 million for 1997. The increase is attributable to increased employment and benefits costs of $1.5 million which was partially offset by a reduction of $0.9 million in consulting and contract services expenses. INTEREST INCOME Interest income for 1998 was $1.0 million compared to $0.2 million for 1997, a $0.8 million, or 300% increase. The increase in the 1998 period is attributable primarily to higher levels of cash invested during 1998, which was partially generated by the sale of the Illinois properties. INTEREST EXPENSE Interest expense for 1998 was $12.2 million, an increase of $7.4 million, or 155%, from $4.8 million in 1997. The increases in the 1998 expense are attributable primarily to higher levels of indebtedness outstanding during 1998 with the acquisition of the Worland Field Properties and continued drilling associated with the development of the Cedar Hills Field. In May 1998, the Company entered into a forward interest rate swap contract to hedge its exposure to changes in the prevailing interest rates in connection with its planned debt offering. Due to the change in treasury note rates, the Company paid $3.9 million to settle the forward interest rate swap contract, which will result in an effective increase of approximately 0.5% to the Com- pany's interest costs on the Notes, or an increase in interest expense of ap- proximately $0.4 million for the term of the Notes. OTHER INCOME Other income decreased $5.0 million, or 62%, to $3.0 million for the year ended December 31, 1998 from $8.1 million for 1997. The 1997 other income included $7.5 million from the settlement of certain litigation issues. This decrease in other income from 1997 was partially offset by the recognition in 1998 of a $2.5 million gain on the sale of the Illinois properties. INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE Net income before income taxes for the year ended December 31, 1998 was a loss of $18.0 million, a decrease in net income before taxes of $35.2 million, or 204%, from $17.3 million of net income before taxes for 1997. This decrease was due to the reduced revenues caused by lower oil and gas sales prices, increased interest expense caused by higher levels of indebtedness and the recognition of certain litigation settlements in 1997. These reductions to income were partially offset by the income generated by the crude oil marketing activities begun in 1998 and the gain on the sale of the Illinois properties which took place in 1998. NET INCOME The 1998 Net Income after taxes was a loss of $18.0 million, a decrease in net income of $44.2 million, or 169%, compared to 1997. In addition to the items related to income before income taxes previously discussed, net income for 1997 also included $8.9 million in income tax benefits recognized in connection with the Company's conversion to an S-corporation effective June 1, 1997. LIQUIDITY AND CAPITAL ASSETS The Company's primary sources of liquidity have been its cash flow from operating activities, financing provided by its Credit Facility and by the Company's principal stockholder and a private debt offering. The Company's cash requirements, other than for operations, are for acquisition, exploration and development of oil and gas properties, and interest payments. CASH FLOW FROM OPERATIONS Net cash provided by operating activities was $23.9 million for 1999 a 5% decrease from the $25.2 million in 1998. Cash decreased to $10.4 million at December 31, 1999, from $15.8 million at year-end 1998 primarily due to repay- ment in January 1999 of the short term note to the principal stockholder out- standing at December 31, 1999. RESERVES AND ADDED FINDING COSTS During 1998 and 1999, the Company spent $85.2 and $32.5, respectively on acquisitions, exploration, exploitation and development of oil and gas prop- erties. The 1998 amount includes the acquisition of the Worland Field prop- erties, net of the sale of an undivided 50% interest of the Worland properties to the principal stockholder for $42.6 million. The 1999 amount includes the assumption of the loan of $18.6 million from the principal stockholder. Total estimated proved reserves of natural gas increased from 55.2 Bcf at year-end 1998 to 75.8 Bcf at December 31, 1999, and estimated total proved oil reserves increased from 19.9 MMBbls at year-end 1998 to 36.6 MMBbls at December 31, 1999. The Company sold reserves of approximately 2.4 Bcf and 2,000 Bbls in January 2000 related to the sale of properties in the Arkoma Basin. FINANCING Long-term debt at December 31, 1998 and December 31, 1999 was $157.3 million and $170.2 million, respectively. The $12.9 million, or 8% increase was mainly due to the assumption of the principal stockholder's note of $18.6 million re- lated to the principal stockholder's contribution of his interest in the Worland Field properties offset by a reduction in the Company's bank debt of $4.0 million and other debt by $1.7 million. CREDIT FACILITY Long-term debt outstanding at December 31, 1998 included $4.0 million of revolving debt under the Credit Facility. The Company has no outstanding debt balance under the Credit Facility at December 31, 1999. The effective rate of interest under the Credit Facility was 7.75% at December 31, 1998 and was 8.5% at December 31, 1999. This Credit Facility has available borrowings of $25 million and bears interest at either Bank One prime adjusted LIBOR, which includes the LIBOR rate as determined on a daily basis by the bank adjusted for a facility fee % and non-use fee %. The LIBOR rate can be locked in for thirty, sixty or ninety days as determined by the Company through the use of various principal tranches; or the Company can elect to leave the interest rate based on the prime interest rate. Interest is payable monthly with all outstanding principal and interest due at maturity on May 14, 2001. In January 2000, the Company utilized proceeds from the Credit Facility to pay off the outstanding balance of the principal stockholder's note assumed in 1999. As of March 28, 2000 the Company has borrowed $12.6 million against this Credit Facility. SENIOR NOTES On July 24, 1998, the Company consummated a private placement of $150.0 million of its 10 1/4% Senior Subordinated Notes due August 1, 2008, in a private placement. Interest on the Notes is payable semi annually on each February 1 and August 1. In connection with the issuance of the Notes, the Company incurred debt issuance costs of approximately $4.7 million, which has been capitalized as other assets and is being amortized on a straight- line basis over the life of the Notes. In May 1998 the Company entered into a forward interest rate swap contract to hedge exposure to changes in prevailing interest rates on the Notes. Due to changes in treasury note rates, the Company paid $3.9 million to settle the forward interest rate swap contract. This payment resulted in an increase of approximately 0.5% to the Company's effective interest rate or an increase of approximately $0.4 million per year over the term of the Notes. On February 29, 2000, the Company purchased $3,000,000 of the Notes for $2,880,000 plus accrued interest and commissions and on March 10, 2000, the Company purchased $1,000,000 of the Notes for $950,000 plus accrued interest and no commission. CAPITAL EXPENDITURES In 1999, the Company incurred $12.9 million of capital expenditures, exclusive of acquisitions. The Company will initiate, on a priority basis, as many pro- jects as cash flow allows. It is anticipated that approximately 84 projects will be initiated in 2000 for projected capital expenditures of $31.3 million. The Company expects to fund the 2000 capital budget through cash flow from operations and its Credit Facility. PURCHASE OF WORLAND FIELD On May 18, 1998, the Company consummated the purchase for approximately $86.5 million of producing and non-producing oil and gas properties and certain other related assets in the Worland Properties effective as of June 1, 1998, which the Company funded through borrowings on its Credit Facility. Subsequently, and effective June 1, 1998, the Company sold an undivided 50% interest in the Worland Properties (excluding inventory and certain equipment) to the Company's principal stockholder for approximately $42.6 million. Of the total sale price to the stockholder, approximately $23.0 million plus interest of approximately $0.3 million was offset against the outstanding balance of notes payable to the stockholder and approximately $19.6 million was applied to the outstanding bal- ance on the Credit Facility on July 24, 1998. In December 1999, the principal stockholder contributed his interest in the purchased properties to the Company, subject to debt of $18.6 million. The contribution was recorded based on the stockholder's cost less DD&A from the date acquired to the date contributed which was $41.4 million. STOCKHOLDER DISTRIBUTION The Company has not made any dividend distributions to its stockholders. However, the Company may be required to dividend the stockholders an amount sufficient to cover the taxes on the taxable income passed through to the stockholders of record. HEDGING From time to time, the Company may use energy swap and forward sale arrangements to reduce its sensitivity to oil and gas price volatility. In July, 1998, the Company began engaging in oil trading arrangements as part of its oil and gas marketing activities. The Company has only limited involvement with derivative financial instru- ments, as defined in SFAS No. 119 "Disclosure About Derivative Financial Instruments and Fair Value of Financial Instruments" and does not use them for trading purposes. The Company's objective is to hedge a portion of its exposure to price volatility from producing oil and natural gas. These arrangements expose the Company to the credit risk of its counterparties and to basis risk. In connection with the offering of the Notes, the Company entered into an interest rate hedge on which it experienced a $3.9 million loss. The loss that was incurred will result in an effective increase of approximately 0.5% to the Company's interest costs on the Notes, or an increase in interest expense of approximately $0.4 million over the term of the Notes. The Company has no present plans to engage in further interest rate hedges. OTHER The Company follows the "sales method" of accounting for its gas revenue, whereby the Company recognizes sales revenue on all gas sold, regardless of whether the sales are proportionate to the Company's ownership in the property. A liability is recognized only to the extent that the Company has a net im- balance in excess of its share of the reserves in the underlying properties. The Company's historical aggregate imbalance positions have been immaterial. The Company believes that any future periodic settlements of gas imbalances will have little impact on its liquidity. The Company has sold a number of non-strategic oil and gas properties and other properties over the past three years, recognizing pre-tax gains of approximately $674,000, $2,614,000 and $151,400 in 1997, 1998 and 1999 respectively. Total amounts of oil and gas reserves associated with these dispositions during 1997 and 1998 were 471 Bbls of oil and 2,463 Mmcf of natural gas. The reserves associated with the few properties sold in 1999 were insignificant. August 19, 1998, the Company instituted a declaratory judgment action against Burlington in the District Court of Garfield County, Oklahoma (Case No. CJ-98-613-03) alleging that Burlington provided false and misleading information regarding certain of Burlington's oil and gas properties to a third party consultant charged with determining the relative values of oil and gas properties owned by the Company and Burlington which served as the basis for the exchange of interests. The Company claimed that the consultant relied on such false and misleading information in determining the relative fair values of the oil and gas interests. The Company sought a declaratory judgment determining that it is excused from further performance under its exchange agreement with Burlington. Burlington denied the Company's allegations and sought specific performance by the Company, plus monetary damages of an unspecified amount. A non-jury trial was held in the case in October, 1999. On December 22, 1999, the Court issued an Order requiring the parties to proceed in accordance with terms of the Trade Agreement and in- structing them to use their best efforts to finalize the Agreements. Even though Continental is appealing the decision of the Trial Court, it is complying with the Order entered by the Court. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to market risk in the normal course of its business operations. Management believes that the Company is well positioned with its mix of oil and gas reserves to take advantage of future price increases that may occur. However, the uncertainty of oil and gas prices continues to impact the domestic oil and gas industry. Due to the volatility of oil and gas prices, the Company, from time to time, has used derivative hedging and may do so in the future as a means of controlling its exposure to price changes. During 1998, the Company had no oil or gas hedging transactions for its production, however, the company did begin marketing crude oil. Most of the Company's purchases are made at either a NYMEX based price or a fixed price. During the third quarter of 1999, the Company entered into forward fixed price sales contracts in accordance with its hedging policy, to mitigate its exposure to the price volatility associated with its crude oil production. The monthly contracts total 80,000 barrels through February 2000 at $20.43 per barrel and an additional 320,000 barrels from May to December 2000 at $22.04 per barrel. At December 31, 1999, the Company had open hedging contracts totaling approximately 400,000 barrels with unrealized deferred losses of approximately $61,668. The Company accounts for changes in the market value of its hedging instruments as deferred gains or losses until the production month of the hedged transaction, at which time the realized gain or loss is recognized in the results of opera- tions. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX OF FINANCIAL STATEMENTS Report of Independent Public Accountants Consolidated Balance Sheets as of December 31, 1998 and 1999 Consolidated Statements of Operations for the Years Ended December 31, 1997, 1998 and 1999 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1997, 1998 and 1999 Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1998 and 1999 Notes to Consolidated Financial Statements REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Continental Resources, Inc.: We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries as of December 31, 1998 and 1999 and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1999. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Continental Resources, Inc. and subsidiaries as of December 31, 1998 and 1999 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Oklahoma City, Oklahoma, February 18, 2000 CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except per share information) ASSETS December 31, -------------------- 1998 1999 ---- ---- CURRENT ASSETS: Cash $ 15,817 $ 10,421 Accounts receivable- Oil and gas sales 7,255 11,508 Joint interest and other, net 7,734 8,517 Inventories 4,627 4,112 Prepaid expenses 168 1,690 ---------- --------- Total current assets 35,601 36,248 ---------- --------- PROPERTY AND EQUIPMENT: Oil and gas properties (successful efforts method)- Producing properties 241,358 293,467 Nonproducing leaseholds 47,583 43,083 Gas gathering and processing facilities 24,709 25,740 Service properties, equipment and other 15,989 14,884 ---------- --------- Total property and equipment 329,639 377,174 Less--Accumulated depreciation, depletion and amortization (121,061) (138,872) ---------- --------- Net property and equipment 208,578 238,302 ---------- --------- OTHER ASSETS: Debt issuance costs 9,023 7,847 Other assets 537 162 ---------- --------- Total other assets 9,560 8,009 ---------- --------- Total assets $ 253,739 $ 282,559 ========== ========= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable $ 10,532 $ 8,448 Current portion of long-term debt 337 356 Revenues and royalties payable 5,855 6,865 Accrued liabilities and other 9,224 9,776 Short-term debt - stockholder 10,000 0 ---------- --------- Total current liabilities 35,948 25,445 ---------- --------- LONG-TERM DEBT, net of current portion 157,302 170,281 OTHER NONCURRENT LIABILITIES 205 167 COMMITMENTS AND CONTINGENCIES (Note 6) STOCKHOLDERS' EQUITY: Common stock, $1 par value, 75,000 shares authorized, 49,041 shares issued and outstanding at December 31, 1998 and 1999 49 49 Additional paid-in capital 2,721 25,182 Retained earnings 57,514 61,435 ---------- --------- Total stockholders' equity 60,284 86,666 ---------- --------- Total liabilities and stockholders' equity $ 253,739 $ 282,559 ========== ========= The accompanying notes are an integral part of these consolidated balance sheets. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share information) December 31, --------------------------------------- 1997 1998 1999 ---- ---- ---- REVENUES: Oil and gas sales $ 78,599 $ 60,162 $ 65,949 Crude oil marketing - 232,216 241,630 Gas gathering, marketing and processing 25,021 17,701 21,563 Oil and gas service operations 6,405 6,689 6,319 --------- --------- --------- Total revenues 110,025 316,768 335,461 --------- --------- --------- OPERATING COSTS AND EXPENSES: Production expenses 16,825 19,028 14,796 Production taxes 3,923 3,583 4,572 Exploration expenses 6,806 7,106 7,750 Crude oil marketing purchases and expenses - 228,797 236,135 Gas gathering, marketing and processing 22,715 15,602 17,850 Oil and gas service operation 3,654 3,664 3,420 Depreciation, depletion and amortization 33,354 38,716 20,385 General and administrative 8,990 10,002 8,627 --------- --------- --------- Total operating costs and expenses 96,267 326,498 313,535 OPERATING INCOME (LOSS) 13,758 (9,730) 21,926 --------- --------- --------- OTHER INCOME AND EXPENSES: Interest income 241 967 310 Interest expense (4,804) (12,248) (16,534) Other income, net 8,061 3,031 266 --------- --------- --------- Total other income and (expenses) 3,498 (8,250) (15,958) --------- --------- --------- INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 17,256 (17,980) 5,968 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE - - (2,048) INCOME TAX BENEFIT 8,941 - - --------- --------- --------- NET INCOME (LOSS) $ 26,197 $ (17,980) $ 3,920 ========= ========= ========= EARNING (LOSS) PER COMMON SHARE $ 534.18 $ (366.63) $ 79.94 ========= ========= ========= The accompanying notes are an integral part of these consolidated financial statements. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999 (in thousands) Total Additional Stock- Common Paid-In Treasury Retained holders Stock Capital Stock Earnings Equity ------- ------- ------- ------- ------- Balance, December 31, 1996 $ 49 $ 2,731 $ (10) $49,298 $52,068 Net income - - - 26,197 26,197 ------- ------- ------- ------- ------- Balance, December 31, 1997 49 2,731 (10) 75,495 78,265 Retirement of treasury stock (10) 10 - - Net loss - - - (17,980) (17,980) ------- ------- ------- ------- ------- Balance, December 31, 1998 49 2,721 0 57,515 60,285 Contribution of interest in oil and gas properties and associated debt by principal stockholder - 22,461 - - 22,461 Net income - - - 3,920 3,920 ------- ------- ------- ------- ------- Balance, December 31, 1999 $ 49 $25,182 $ 0 $61,435 $86,666 ======= ======= ======= ======= ======= The accompanying notes are an integral part of these consolidated financial statements. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999 (in thousands) 1997 1998 1999 ---- ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ 26,197 $ (17,980) $ 3,920 Adjustments to reconcile net income (loss) to net cash provided by operating activities- Depreciation, depletion and amortization 33,354 38,716 20,385 Gain on sale of assets (674) (2,539) (151) Dry hole costs and impairment of undeveloped leases 1,468 2,880 5,978 Deferred income taxes (11,979) - - Other noncurrent assets and liabilities - (3) 338 Changes in current assets and liabilities- Decrease(increase) in accounts receivable (3,971) 9,645 (5,037) Decrease(increase) in inventories 8 (1,078) 515 Decrease(increase) in prepaid expenses 3,454 215 (1,522) Increase(decrease) in accounts payable 1,979 (9,082) (2,084) Increase(decrease) in revenues and royalties payable 689 (1,642) 1,010 Increase(decrease) in accrued liabilities and other 952 6,059 552 ---------- --------- ---------- Net cash provided by operating activities 51,477 25,191 23,904 ---------- --------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Exploration and development (63,702) (42,715) (12,233) Gas gathering and processing facilities and service properties, equipment and other (16,760) (7,517) (266) Purchase of producing properties (475) (85,100) (1,695) Cash received on note receivable - stockholder - 19,582 - Proceeds from sale of assets 2,177 3,641 496 Advances from (to) affiliates 401 58 - ---------- --------- ---------- Net cash used in investing activities (78,359) (112,051) (13,698) ---------- --------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from line of credit and other 33,493 266,515 4,600 Repayment of line of credit and other (30,570) (165,539) (10,202) Debt issuance costs - (9,600) - Proceeds from short-term debt due to stockholder 21,950 10,000 - Repayment of short-term debt due to stockholder - - (10,000) Purchase of treasury stock (10) - - ---------- --------- ---------- Net cash provided by financing activities 24,863 101,376 (15,602) ---------- --------- ---------- CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999 (in thousands) 1997 1998 1999 ---- ---- ---- NET INCREASE (DECREASE) IN CASH $ (2,019) $ 14,516 $ (5,396) CASH, beginning of year 3,320 1,301 15,817 ---------- --------- ---------- CASH, end of year $ 1,301 $ 15,817 $ 10,421 ========== ========= ========== SUPPLEMENTAL CASH FLOW INFORMATION: Interest paid $ 4,302 $ 12,248 $ 16,583 Income taxes paid $ 300 $ - $ - NONCASH INVESTING AND FINANCING ACTIVITIES: Sale of 50% interest in oil and gas properties to principal stockholder: Satisfaction of note payable $ - $ 22,969 $ - Issuance of note receivable $ - $ 19,582 $ - Conversion of account receivable to note receivable $ - $ 510 $ - Contribution of interest in oil and gas properties by stockholder Oil and gas properties $ - $ - $ 41,371 Assumption of note payable $ - $ - $ 18,600 Paid-in capital $ - $ - $ 22,461 The accompanying notes are an integral part of these consolidated financial statements. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION: Continental Resources, Inc. ("CRI") was incorporated in Oklahoma on November 16, 1967, as Shelly Dean Oil Company. On September 23, 1976, the name was changed to Hamm Production Company. In January 1987, the Company acquired all of the assets and assumed the debt of Continental Trend Resources, Inc. Affiliated entities, J.S. Aviation and Wheatland Oil Co. were merged into Hamm Production Company, and the corporate name was changed to Continental Trend Resources, Inc. at that time. In 1991, the Company's name was changed to Continental Resources, Inc. CRI has two wholly-owned subsidiaries, Continental Gas, Inc. ("CGI") and Continental Crude Co. ("CCC"). CGI was incorporated in April 1990. CCC was incorporated in May 1998. Since its incorporation, CCC has had no operations, has acquired no assets and has incurred no liabilities. CRI's principal business is oil and natural gas exploration, development and production. CRI has interests in approximately 1,120 wells and serves as the operator in the majority of such wells. CRI's operations are primarily in Oklahoma, North Dakota, South Dakota, Montana, Wyoming, Texas and Louisiana. In July 1998, CRI began entering into third party contracts to purchase and resell crude oil at prices based on current month NYMEX prices, current posting prices or at a stated contract price. CGI is engaged principally in natural gas marketing, gathering and processing activities and currently operates five gas gathering systems and two gas processing plants in its operating areas. In addition, CGI participates with CRI in certain oil and natural gas wells. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Basis of Presentation The accompanying consolidated financial statements include the accounts and operations of CRI, CGI and CCC (collectively the "Company"). All significant intercompany accounts and transactions have been eliminated in the consolidated financial statements. Accounts Receivable The Company operates exclusively in the oil and natural gas exploration and production, gas gathering and processing and gas marketing industries. The Company's joint interest receivables at December 31, 1998 and 1999, are recorded net of an allowance for doubtful accounts of approximately $400,000 and $387,000, respectively, in the accompanying consolidated balance sheets. Inventories Inventories consist primarily of tubular goods, production equipment and crude oil in tanks, which are stated at the lower of average cost or market. At December 31, 1998 and 1999, tubular goods and production equipment totaled approximately $3,913,000 and $3,620,000, respectively and crude oil in tanks totaled approximately $714,000 and $491,000, respectively. Property and Equipment The Company utilizes the successful efforts method of accounting for oil and gas activities whereby costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. These costs are amortized to operations on a unit-of-production method based on proved developed oil and gas reserves, allocated property by property, as estimated by petroleum engineers. Geological and geophysical costs, lease rentals and costs associated with unsuccessful exploratory wells are expensed as incurred. Nonproducing leaseholds are periodically assessed for impairment, based on exploration results and planned drilling activity. Maintenance and repairs are expensed as incurred, except that the cost of replacements or renewals that expand capacity or improve production are capitalized. Gas gathering systems and gas processing plants are depreciated using the straight-line method over an estimated useful life of 14 years. Service properties and equipment and other is depreciated using the straight-line method over estimated useful lives of 5 to 40 years. Income Taxes The Company filed a consolidated income tax return based on a May 31 fiscal tax year end through May 31, 1997, and deferred income taxes were provided for temporary differences between financial reporting and income tax bases of assets and liabilities. Effective June 1, 1997, the Company converted to an "S-corporation" under Subchapter S of the Internal Revenue Code. As a result, income taxes attributable to Federal taxable income of the Company after May 31, 1997, if any, will be payable by the stockholders of the Company. The effect of eliminating the deferred tax assets and liabilities were recognized in the results of operations for the year ended December 31, 1997, the year of adoption. Earnings per Common Share Earnings per common share includes no dilution and is computed by dividing income available to common stockholders by the weighted-average number of shares outstanding for the period. There are no common stock equivalents or securities outstanding which would result in material dilution. The weighted- average number of shares used to compute earnings per common share was 49,042 in 1997, 49,041 in 1998 and 49,041 in 1999. Futures Contracts CGI, in the normal course of business, enters into fixed price contracts for either the purchase or sale of natural gas at future dates. Due to fluctuations in the natural gas market, CGI buys or sells natural gas futures contracts to hedge the price and basis risk associated with the specifically identified purchase or sales contracts. CGI accounts for changes in the market value of futures contracts as a deferred gain or loss until the production month of the hedged transaction, at which time the gain or loss on the natural gas futures contracts is recognized in the results of operations. At December 31, 1998 and 1999, there were no open natural gas futures contracts. Net gains and losses on futures contracts are included in gas gathering, marketing and processing revenues in the accompanying consolidated statements of operations and were immaterial for the years ended December 31, 1997, 1998 and 1999. Crude Oil Marketing During 1998, CRI began trading crude oil, exclusive of its own production, with third parties, under fixed and variable priced physical delivery contracts extending out less than one year. CRI accounted for these contracts utilizing the settlement method of accounting in the month of physical delivery through December 31, 1998. In December 1998, the Emerging Issues Task Force ("EITF") released their consensus on EITF 98-10 "Accounting for Energy Trading and Risk Management Activities." This statement requires that contracts for the purchase and sale of energy commodities which are entered into for the purpose of speculating on market movements or otherwise generating gains from market price differences to be recorded at their market value, as of the balance sheet date, with any corresponding gains or losses recorded as income from operations. The Company adopted EITF 98-10 effective January 1, 1999. As a result, the Company recorded an expense for the cumulative effect of change in accounting principle of $2,048,000. At December 31, 1999, the market value of the Company's open energy trading contracts resulted in an unrealized gain of $1.5 million which is recorded in crude oil marketing revenues in the accompanying consolidated statement of operations and prepaid expenses in the accompanying consolidated balance sheet. Crude Oil Hedging During the third quarter of 1999, the Company entered into forward fixed price sales contracts in accordance with its hedging policy, to mitigate its exposure to the price volatility associated with its crude oil production. The monthly contracts total 80,000 barrels through February 2000 at $20.43 per barrel and an additional 320,000 barrels from May to December 2000 at $22.04 per barrel. At December 31, 1999, the Company had open hedging contracts totaling approximately 400,000 barrels with unrealized deferred losses of approximately $61,668. The Company accounts for changes in the market value of its hedging instruments as deferred gains or losses until the production month of the hedged transaction, at which time the realized gain or loss is recognized in the results of operations. Gas Balancing Arrangements The Company follows the "sales method" of accounting for its gas revenue whereby the Company recognizes sales revenue on all gas sold to its purchasers, regardless of whether the sales are proportionate to the Company's ownership in the property. A liability is recognized only to the extent that the Company has a net imbalance in excess of their share of the reserves in the underlying properties. The Company's aggregate imbalance positions at December 31, 1998 and 1999 were not material. Significant Customer During 1997, 1998 and 1999, approximately 46.6%, 24.2% and 25.2%, respectively, of the Company's total revenues were derived from sales made to a single customer. Fair Value of Financial Instruments The Company's financial instruments consist primarily of cash, trade receivables, trade payables and bank debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values, due to the short maturity of these instruments. The fair value of bank debt approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. Presentation Certain information has been reclassified to conform to the 1999 presentation. 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. Of the estimates and assumptions that affect reported results, the estimate of the Company's oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment on producing oil and gas properties, is the most significant. Accounting Principles In June 1998, the Financial accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, , "Accounting for Derivative Instruments and for Hedging Activities", with an effective date for periods beginning after June 15, 1999. In July, 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB No. 133." Adoption of SFAS No. 133 is now required for financial statements for periods beginning after June 15, 2000. The Company will adopt this new standard effective January 1, 2001. Management has not yet determined whether the adoption of this new standard will have a material impact on its consolidated financial position or results of operations. 3. ACQUISITION OF PRODUCING PROPERTIES: On May 18, 1998, the Company consummated the purchase for approximately $86.5 million of producing and non-producing oil and gas properties and certain other related assets in the Worland Properties effective as of June 1, 1998, which the Company funded through borrowings on its line of credit. Subsequently, and effective June 1, 1998, the Company sold an undivided 50% interest in the Worland Properties (excluding inventory and certain equipment) to the Company's principal stockholder for approximately $42.6 million. Of the total sale price to the stockholder, approximately $23.0 million plus interest of approximately $0.3 million was offset against the outstanding balance of notes payable to the stockholder and approximately $19.6 million was recorded as an increase in advances to affiliates. This acquisition has been recorded using the purchase method of accounting. The following presents unaudited pro forma results of operations for the years ended December 31, 1997 and 1998 as if these acquisitions had been consummated as of January 1, 1997. These pro forma results are not necessarily indicative of future results. (in thousands, except per share data) Pro Forma (Unaudited) --------------------- 1997 1998 ---- ---- Revenues $ 120,151 $ 318,895 ========= ========= Net income (loss) $ 19,618 $ (21,184) ========= ========= Earnings (loss) available to common stock $ 19,618 $ (21,184) ========= ========= Earnings (loss) per common share $ 400.03 $(431.97) ========= ========= On December 31, 1999 the Company's principal stockholder contributed the undivided 50% interest in the Worland Properties along with debt with an outstanding balance of $18.6 million. The Company recorded the properties at the stockholder's cost less amortization of such cost on a unit -of-production method from the stockholder's acquisition date through December 31, 1999. The contribution resulted in an addition to paid in capital of $22.4 million. The following presents unaudited pro forma results of operations for the years ended December 31, 1997, 1998, and 1999 as if the contribution had been consummated as of January 1, 1997. These pro forma results are not necessarily indicative of future results. (In thousands, except per share data) Pro Forma (Unaudited) --------------------- 1997 1998 1999 ---- ---- ---- Revenues $130,277 $321,023 $341,796 ======== ======== ======== Net income (loss) $ 21,837 $(22,931) $ 6,052 ======== ======== ======== Earnings (loss) available to common stock $ 21,837 $(22,931) $ 6,052 ======== ======== ======== Earnings (loss) per common share $ 445.28 $ 431.97 $ 123.41 ======== ======== ======== 4. LONG-TERM DEBT: Long-term debt as of December 31, 1998 and 1999, consists of the following (in thousands): 1998 1999 ---- ---- Senior Subordinated Notes (a) $150,000 $150,000 Line of credit agreement (b) 4,000 - Notes payable to principal stockholder (c) - 18,600 Note payable to General Electric Capital Corporation (d) 3,582 2,017 Capital lease agreements (e) 57 20 -------- -------- Outstanding debt 157,639 170,637 Less-Current portion 337 356 -------- -------- Total long-term debt $157,302 $170,281 ======== ======== (a) On July 24, 1998, the Company consummated a private placement of $150.0 million of 10 1/4% Senior Subordinated Notes ("the Notes") due August 1, 2008, in a private placement under Securities Act Rule 144A. Interest on the Notes is payable semi-annually on each February 1 and August 1. In connection with the issuance of the Notes, the Company incurred debt issuance costs of approximately $4.7 million, which has been capitalized as other assets and is being amortized on a straight-line basis over the life of the Notes. In May 1998 the Company entered into a forward interest rate swap contract to hedge exposure to changes in prevailing interest rates on the Notes. Due to changes in treasury note rates, the Company paid $3.9 million to settle the forward interest rate swap contract. This payment results in an increase of approximately 0.5% to the Company's ef- fective interest rate or an increase of approximately $0.4 million per year over the term of the Notes. Effective November 14, 1998, the Company registered the Notes through a Form S-4 Registration Statement under the Securities Exchange Act of 1933. (b) In August, 1998, the Company amended its previous line of credit with a bank to allow borrowings up to $75.0 million with semi-annual redetermi- nation dates as of November 1 and May 1. Effective November 1, 1998, the borrowing base was lowered to $25.0 million. The Company has collateralized the line of credit with substantially all of its oil and natural gas interests, and gathering, marketing and processing properties. This loan bears interest at either Bank One prime or adjusted LIBOR, which includes the LIBOR rate as determined on a daily basis by the bank adjusted for a facility fee percentage and non-use fee percentage. The LIBOR rate can be locked in for thirty or sixty days as determined by the Company through the use of various principal tranches; or the Company can elect to leave the interest rate based on the prime interest rate. At December 31, 1998 interest was based on prime (7.75%). The Bank One prime interest rate at December 31, 1999, was 8.5%. Interest is payable monthly with all outstanding principal and interest due at maturity on May 14, 2001. The Company has no outstanding debt on its line of credit at December 31, 1999. (c) During 1997, CRI and CGI entered into various notes with the principal stockholder of the Company. These notes bear interest at 8.25% with inter- est payments due monthly or quarterly for twenty-four to thirty-six months. On December 31, 1997, the notes between CRI and the principal stockholder were combined into one note totaling $21,750,000 bearing interest at 8.25% with interest payments due on a quarterly basis for twenty-four months with the balance to be paid in full by December 31, 2002. The outstanding bal- ance of notes was paid in full in connection with the sale of the undivided 50% interest in the Worland Properties to the principal stockholder in 1998, as discussed above. On December 31, 1999, the Company's principal stockholder contributed the undivided 50% interest in the Worland Properties and the Company assumed his loan of $18,600,000. The loan is at the prime interest rate which was 8.5% at December 31, 1999. Interest is payable monthly with all outstanding principal and interest due at maturity on May 1, 2001. However, on February 5, 2000 the Company drew on it's line of credit and paid this loan in full. (d) In July 1997, the Company borrowed $4,000,000 from General Electric Capital Corporation to finance the purchase of an airplane. The note accrues interest at 7.91% to be paid in one hundred nineteen (119) consecutive monthly installments of principal and interest of $48,341 each and a final installment of approximately $48,000. It is secured by the airplane. As of December 31, 1999 the outstanding principal balance was $2,016,819. (e) During 1997, the Company entered into two capital lease agreements to purchase a copier and computer equipment. The agreements require monthly payments of principal and interest totaling $559.13 and $2,080.67 for forty-two and sixty months, respectively. The Company's line of credit agreement contains certain negative financial and certain information reporting covenants. The Company was in compliance with the covenants at December 31, 1999 and expects to be in compliance through the date the agreement terminates. The annual maturities of long-term debt subsequent to December 31, 1999, are as follows (in thousands): 2000 $ 356 2001 18,958 2002 387 2003 419 2004 and thereafter 150,517 -------- Total maturities $170,637 ======== At December 31, 1999, the Company had $853,750 of outstanding letters of credit which expire during 2000. 5. INCOME TAXES: The Company follows Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." As mentioned in Note 2, effective June 1, 1997, the Company converted to an S-Corporation resulting in the taxable income or loss of the Company from that date being reported to the stockholders and included in their respective Federal and state income tax returns. Accordingly, the deferred income tax assets and liabilities at May 31, 1997, were eliminated through recording a provision for income tax benefit. The components of income tax expense (benefit) for the year ended December 31, 1997 is as follows (in thousands): 1997 ---- Current $ 3,038 Deferred (11,979) -------- Income tax expense (benefit) $ (8,941) ======== The provision for income taxes differs from an amount computed at the statutory rates at December 31, 1997 as follows (in thousands): 1997 ---- Federal income tax at statutory rates $ 6,040 State income taxes 518 Nondeductible expenses 30 Conversion to S-Corporation (15,529) ---------- Income tax benefit $ (8,941) ========== 6. COMMITMENTS AND CONTINGENCIES: The Company maintains a defined contribution pension plan for its employees under which it makes discretionary contributions to the plan based on a percentage of eligible employees compensation. During 1997, 1998 and 1999, contributions to the plan were 4%, 5% and 5%, respectively, of eligible employees' compensation. However, the Company suspended its 5% contribution from January 1, 1999 to April 1, 1999 due to low commodity prices. Pension expense for the years ended December 31, 1997, 1998 and 1999, was approximately $242,000, $374,000 and $252,000, respectively. The Company and other affiliated companies participate jointly in a self- insurance pool (the "Pool") covering health and workers' compensation claims made by employees up to the first $50,000 and $500,000, respec- tively, per claim. Any amounts paid above these are reinsured through third-party providers. Premiums charged to the Company are based on estimated costs per employee of the Pool. No additional premium assess- ments are anticipated for periods prior to December 31, 1999. Property and general liability insurance is maintained through third-party providers with a $50,000 deductible on each policy. The Company is involved in various legal proceedings in the normal course of business, none of which, in the opinion of management, will have a material adverse effect on the financial position or results of operations of the Company. The Company has been successful in Federal courts in its lawsuit against a gas purchaser arising from tortious interference with business relations. A judgment was awarded for actual and punitive damages under the Federal lawsuit totaling $30,269,000 plus accrued interest. In May 1996, this decision was remanded by the U.S. Supreme Court back to the Tenth Circuit Court of Appeals for further consideration. During 1997, this lawsuit was settled with an aggregate judgment of $9,500,000 of which the Company's share was approximately $7,500,000. This amount is included in other income in the accompanying consolidated statement of operations for the year ended December 31, 1997. On May 15, 1998, the Company and an unrelated third party entered into a definitive agreement to exchange undivided interests in approximately 65,000 gross (59,000 net) leasehold acres in the northern half of the Cedar Hills Field. On August 19, 1998, the Company instituted a declara- tory judgment action against the unrelated third party in the Oklahoma District Court. The Company sought a declaratory judgment determining that it is excused from further performance under its exchange agreement with the third party. The third party denied the Company's allegations and sought specific performance by the Company, plus monetary damages of an unspecified amount. A non-jury trial was held in the case in October, 1999. On December 22, 1999, the Court issued an Order re- quiring the parties to proceed in accordance with terms of the Trade Agreement and instructing them to use their best efforts to finalize the Agreements. Even though Continental is appealing the decision of the Trial Court, it is complying with the Order entered by the Court. Due to the nature of the oil and gas business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environ- mental contamination. The Company is not aware of any material potential environmental issues or claims. 7. RELATED PARTY TRANSACTIONS: In December 1998, the Company borrowed $10,000,000 from their principal stockholder. The note bears interest at 8.5% and is payable on demand. The note was repaid in January 1999. The Company, acting as operator on certain properties, utilizes affiliated companies to provide oilfield services such as drilling and trucking. The total amount paid to these companies, a portion of which is billed to other interest owners, was approximately $11,852,000, $12,842,000 and $7,418,000 during the years ended December 31, 1997, 1998 and 1999, respectively. These services are provided at amounts which management believes approxi- mate the costs which would have been paid to an unrelated party for the same services. At December 31, 1998 and 1999, the Company owed approxi- mately $876,000 and $448,000, respectively, to these companies which is included in accounts payable and accrued liabilities in the accompanying consolidated balance sheets. These companies and other companies owned by the Company's principal stockholder also own interests in wells operated by the Company and provide oilfield related services for the Company. At December 31, 1998 and 1999, approximately $1,371,000 and $875,000, respectively, from affiliated companies is included in accounts receivable in the accompanying consolidated balance sheets. During 1998, approximately $5,692,000 and $1,522,000 of the Company's crude marketing revenues and purchases, respectively, were transacted with Independent Trading and Transportation Company ("ITT") an affiliate of the Company. There were no transactions with ITT in 1999. CRI and CGI advance certain amounts to affiliates primarily for operating expenditures. The advances outstanding to affiliates at December 31, 1998, totaled approximately $700 and none were outstanding at December 31, 1999. Interest income earned during the years ended December 31, 1997, 1998 and 1999, was approximately $33,000, $296,000 and $0, respectively, on advances to affiliates. The Company leases office space under operating leases directly or in- directly from the principal stockholder. Rents paid associated with these leases totaled approximately $294,000, $363,000 and $369,000 for the years ended December 31, 1997, 1998 and 1999, respectively. During the years ended December 31, 1998, advances were made to the Company from the principal stockholder. Interest expense related to these advances totaled approximately $721,000 in 1998. Effective June 1, 1998, The Company sold an undivided 50% interest in the 70,000 net leasehold acres it acquired in the Worland Field Acquisition to its principal stockholder. The Worland Field sale did not include inventory and certain items of equipment which the Company had acquired in the Worland Field Acquisition. The $42.6 million purchase price paid by the principal stockholder equals the Company's cost basis in such leasehold acres. In December 1999 the principal stockholder contributed his interests in the purchased properties along with debt of $18,600,000. The properties were recorded at the stockholder's cost less amortization of such cost on a unit-of-production method from the stockholder's acquisition date through the date contributed to the Company. The contribution was recorded as an addition to paid-in capital. 8. IMPAIRMENT OF LONG-LIVED ASSETS: The Company accounts for impairment of long-lived assets in accordance with Financial Accounting Standards Board issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." During 1997, 1998 and 1999 the Company reviewed its oil and gas properties which are maintained under the successful efforts method of accounting, to identify properties with excess of net book value over projected future net revenue of such properties. Any such excess net book values identified were evaluated further considering such factors as future price escalation, probability of additional oil and gas reserves and a discount to present value. If an impairment was determined appropriate an additional charge was added to depreciation, depletion and amortization ("DD&A") expense. The Company recognized additional DD&A impairment in 1997 and 1998 of approximately $5,000,000 and $7,900,000, respectively. No impairment was required in 1999. 9. GUARANTOR SUBSIDIARIES: The Company's wholly owned subsidiaries have guaranteed the Notes discussed in Note 4. The following is a summary of the financial information of CGI for 1997, 1998 and 1999 (in thousands): 1997 1998 1999 ---- ---- ---- AS OF DECEMBER 31 Current assets $ 3,094 $ 2,493 $ 3,392 Noncurrent assets 20,263 22,263 21,643 --------- --------- --------- Total assets 23,357 24,756 25,035 ========= ========= ========= Current liabilities 11,043 13,503 13,188 Noncurrent liabilities 200 616 - Stockholder's equity 12,114 10,637 11,847 --------- --------- --------- Total liabilities and stockholder's equity 23,357 24,756 25,035 ========= ========= ========= FOR THE YEAR ENDED DECEMBER 31 Total revenues $ 29,656 $ 20,859 $ 25,037 Operating costs and expenses 29,122 21,703 24,185 --------- --------- --------- Operating income (loss) 534 (844) 852 Other expenses (17) (633) (758) Income tax benefit 2,028 - - --------- --------- --------- Net income (loss) $ 2,545 $ (1 ,477) $ 94 ========= ========= ========= At December 31, 1998 and 1999, current liabilities payable to CRI totaled approximately $10,000,000 and $9,500,000, respectively. For the years ended December 31, 1997, 1998 and 1999, depreciation, depletion and amortization, included in operating costs, totaled approximately $1,560,000, $2,178,000 and $2,063,000, respectively. Since its incorporation, CCC has had no operations, has acquired no assets and has incurred no liabilities. 10. SUBSEQUENT EVENTS: On January 2000, the Company sold for $5.8 million all of its oil and gas properties in the Arkoma Basin, along with the Rattlesnake and Enterprise Gas Gathering systems. The standardized measure of discounted future net cash flows at December 31, 1999 attributable to the oil and gas properties was approxi- mately $2.4 million and the Company's net book carrying value of the oil and gas properties and the gathering systems was approximately $2.5 million. On February 29, 2000, the Company purchased $3,000,000 of the Notes for $2,880,000 plus accrued interest and commissions and on March 10, 2000, the Company purchased $1,000,000 of the Notes for $950,000 plus accrued interest and no commission. 11. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED): Proved Oil and Gas Reserves (Unaudited) The following reserve information was developed from reserve reports as of December 31, 1996, 1997, 1998 and 1999, prepared by independent reserve engineers and by the Company's internal reserve engineers and set forth the changes in estimated quantities of proved oil and gas reserves of the Company during each of the three years presented. Crude Oil and Natural Gas Condensate (MMCF) (BBLS in thousands) ----------- ------------------- Proved reserves as of December 31, 1996 50,535 19,492 Revisions of previous estimates 3,640 6,731 Extensions, discoveries and other additions 2,903 2,072 Production (5,789) (3,518) Sale of minerals in place (1,911) (58) ------- ------- Proved reserves as of December 31, 1997 49,378 24,719 Revisions of previous estimates 262 (8,065) Extensions, discoveries and other additions 2,878 1,011 Production (6,755) (3,981) Sale of minerals in place (165) (177) Purchase of minerals in place 9,621 6,423 ------- ------- Proved reserves as of December 31, 1998 55,219 19,930 Revisions of previous estimates 14,602 12,462 Extensions, discoveries and other additions 2,174 326 Production (6,640) (3,221) Sale of minerals in place (97) (3) Purchase of minerals in place 10,503 7,130 ------- ------- Proved reserves as of December 31, 1999 75,761 36,624 ======= ======= Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be precisely measured, and estimates of engineers other than the Company's might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quanti- ties of oil and gas that are ultimately recovered. Gas imbalance receivables and liabilities for each of the three years ended December 31, 1997, 1998 and 1999, were not material and have not been included in the reserve estimates. Proved Developed Oil and Gas Reserves (Unaudited) The following reserve information was developed by the Company and set forth the estimated quantities of proved developed oil and gas reserves of the Company as of the beginning of each year. Crude Oil and Natural Gas Condensate Proved Developed Reserves (MMCF) (BBLS in thousands) - ------------------------- ----------- ------------------- January 1, 1997 49,082 15,265 January 1, 1998 47,676 19,411 January 1, 1999 54,901 19,095 January 1, 2000 65,723 34,432 Proved developed reserves are proved reserves which are expected to be recovered through existing wells with existing equipment and operating methods. Costs Incurred in Oil and Gas Activities Costs incurred in connection with the Company's oil and gas acquisition, exploration and development activities during the year are shown below (in thousands of dollars). Amounts are presented in accordance with SFAS No. 19, and may not agree with amounts determined using traditional industry definitions. 1997 1998 1999 ---- ---- ---- Property acquisition costs: Proved Purchased $ 476 $ 85,100 $ 19,745 Proved Contributed - - 22,461 Unproved 4,641 3,770 1,274 -------- -------- -------- Total property acquisition costs 5,117 88,870 43,480 Exploration costs 9,792 4,801 379 Development costs 49,268 34,144 10,945 -------- -------- -------- Total $ 64,177 $127,815 $ 54,804 ======== ======== ======== Aggregate Capitalized Costs Aggregate capitalized costs relating to the Company's oil and gas producing activities, and related accumulated DD&A, as of December 31 (in thousands of dollars): 1998 1999 ---- ---- Proved oil and gas properties $270,708 $322,452 Unproved oil and gas properties 18,233 13,733 -------- -------- Total 288,941 336,185 Less- Accumulated DD&A 111,618 126,995 -------- -------- Net capitalized costs $177,323 $209,190 ======== ======== Oil and Gas Operations (Unaudited) Aggregate results of operations for each period ended December 31, in connection with the Company's oil and gas producing activities are shown below (in thousands of dollars): 1997 1998 1999 ---- ---- ---- Revenues $ 78,599 $ 60,162 $ 65,949 Production costs 20,748 22,611 19,368 Exploration expenses 6,806 7,106 7,750 DD&A and valuation provision<F1> 30,202 34,662 16,778 -------- -------- -------- Income (loss) 20,843 (4,217) 22,053 Income tax expense<F2> 3,300 - - -------- -------- -------- Results of operations from producing activities (excluding corporate overhead and interest costs) $ 17,543 $ (4,217) $ 22,053 ======== ======== ======== ______________________ <FN> <F1> Includes $5.0 million, $7.9 million in 1997 and 1998, respectively, of additional DD&A as a result of SFAS No. 121 impairments. <F2> The 1997 income tax provision was computed based on estimated oil and gas operations income for the five months ended March 31, 1997, times the estimated effective income tax rate. The Company's S-Corporation status was effective June 1, 1997. </FN> Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following information is based on the Company's best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 1997, 1998 and 1999 as required by Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 69. The Standard requires the use of a 10% discount rate. This in- formation is not the fair market value nor does it represent the expected present value of future cash flows of the Company's proved oil and gas reserves (in thousands of dollars). 1997 1998 1999 ---- ---- ---- Future cash inflows $ 576,330 $ 328,333 $1,069,436 Future production and development costs (189,520) (157,003) (422,558) Future income tax expenses - - - ---------- ---------- ---------- Future net cash flows 386,810 171,330 646,878 10% annual discount for estimated timing of cash flows (145,185) (63,660) (312,467) ---------- ---------- ---------- Standardized measure of discounted future net cash flows $ 241,625 $ 107,670 $ 334,411 ========== ========== ========== Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves. The year-end weighted average oil price utilized in the computa- ion of future cash inflows was approximately $18.06, $10.84, and $24.38 per BBL at December 31, 1997, 1998, and 1999, respectively. The year-end weighted average gas price utilized in the computation of future cash inflows was approximately $2.25, $1.64, and $1.76 per MCF at December 31, 1997,1998, and 1999, respectively. Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company's proved oil and gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions. Income taxes were not computed at December 31, 1997, 1998 or 1999, as the Company elected S-Corporation status effective June 1, 1997. Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company's proved oil and gas reserves at year-end are shown below (in thousands of dollars): 1997 1998 1999 ---- ---- ---- Standardized measure of discounted future net cash flows at the beginning of the year $177,133 $241,625 $107,670 Extensions, discoveries and improved recovery, less related costs 16,352 7,088 5,370 Revisions of previous quantity estimates 58,001 (34,228) 128,280 Changes in estimated future development costs (36,901) 2,506 (25,914) Purchases(sales) of minerals in place (3,233) 11,815 49,984 Net changes in prices and production costs (51,456) (116,458) 135,803 Accretion of discount 17,713 24,163 10,767 Sales of oil and gas produced, net of production costs (57,851) (37,551) (46,581) Development costs incurred during the period 32,474 22,960 1,246 Net change in income taxes 89,915 - - Change in timing of estimated future production, and other (522) (14,250) (32,214) -------- -------- -------- Standardized measure of discounted future net cash flows at the end of the year $241,625 $107,670 $334,411 ======== ======== ======== ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The following table sets forth names, ages and titles of the directors and executive officers of the Company. NAME AGE POSITION Harold Hamm(1)(2) 54 Chairman of the Board of Directors, President, Chief Executive Officer and Director Jack Stark(1)(3) 45 Senior Vice President--Exploration and Director Jeff Hume(1)(4) 49 Senior Vice President--Drilling Operations and Director Randy Moeder(1)(2) 39 Senior Vice President, General Counsel, Secretary and Director Roger Clement(1)(3) 55 Senior Vice President, Chief Financial Officer, Treasurer and Director Tom Luttrell 42 Senior Vice President--Land Jeff White(5) 33 Senior Vice President--Business Development Tom Myers 54 Manager of Production Operations - ------------------ (1) Member of the Executive, Compensation and Audit Committees. (2) Term expires in 2002. (3) Term expires in 2001. (4) Term expires in 2000. (5) Son-in-law of Harold Hamm HAROLD HAMM, LL.M. has been President and Chief Executive Officer and a Director of the Company since its inception in 1967. Mr. Hamm has served as President of the Oklahoma Independent Petroleum Association Wildcatter's Club since 1989 and was the founder and is Chairman of the Oklahoma Natural Gas Industry Task Force. He has served as a member of the Interstate of Oil and Gas Compact Commission and is a founding board member of the Oklahoma Energy Resources Board. Mr. Hamm serves on the Tax Steering Committee of the Independent Petroleum Association of America and is a director of the Rocky Mountain Oil and Gas Association. The Oklahoma Independent Petroleum Association named Mr. Hamm Member of the Year in 1992. JACK STARK joined the Company as Vice President of Exploration in June 1992 and was promoted to Senior Vice President in May 1998. Mr. Stark has been a Director of the Company since September 1996. He holds a Masters degree in Geology from Colorado State University and has 20 years of exploration experience in the Mid-Continent, Gulf Coast and Rocky Mountain regions. Prior to joining the Company, Mr. Stark was the exploration manager for the Western Mid-Continent Region for Pacific Enterprises from August 1988 to June 1992. From 1978 to 1988, he held various staff and middle management positions with Cities Service Co. and TXO Production Corp. Mr. Stark is a member of the American Association of Petroleum Geologists, Oklahoma Independent Petroleum Association, Rocky Mountain Association of Geologists, Houston Geological Society and Oklahoma Geological Society. JEFF HUME has been Vice President of Drilling Operations and a Director of the Company since September 1996 and was promoted to Senior Vice President in May, 1998. From May 1983 to September 1996, Mr. Hume was Vice President of Engineering and Operations. Prior to joining the Company, Mr. Hume held various engineering positions with Sun Oil Company, Monsanto Company and FCD Oil Corporation. Mr. Hume is a Registered Professional Engineer and member of the Society of Petroleum Engineers, Oklahoma Independent Petroleum Association, and the Oklahoma and National Professional Engineering Societies. RANDY MOEDER has been Vice President, General Counsel and a Director of the Company since November 1990 and has served as Secretary of the Company since February 1994 and as President of Continental Gas, Inc. since January 1995 and was Vice President of Continental Gas, Inc. from November 1990 to January 1995. Mr. Moeder was promoted to Senior Vice President of the Company in May, 1998. From January 1988 to summer 1990, Mr. Moeder was in private law practice. From 1982 to 1988, Mr. Moeder held various positions with Amoco Corporation. Mr. Moeder is a member of the Oklahoma Independent Petroleum Association, the Oklahoma and American Bar Associations. Mr. Moeder is also a Certified Public Accountant. ROGER CLEMENT became Vice President, Chief Financial Officer and Treasurer and a Director of the Company in March 1989 and was promoted to Senior Vice President in May, 1998. Prior to joining the Company, Mr. Clement was a partner in the accounting firm of Hunter and Clement in Oklahoma City, Oklahoma. Mr. Clement is a Certified Public Accountant. TOM LUTTRELL has been Vice President--Land of the Company since February 1997 and was promoted to Senior Vice President in May, 1998. From 1991 to February 1997, Mr. Luttrell was Senior Landman of the Company. Prior to joining the Company, Mr. Luttrell served as a landman for Terra Resources, Inc., Pacific Enterprises Oil & Gas Company and Alexander Energy Corporation, all independent oil and gas exploration companies. Mr. Luttrell is a member of the American Association of Petroleum Landmen. JEFF WHITE has been Vice President--Business Development of the Company since July 1996 and was promoted to Senior Vice President--Business Development in May, 1998. From 1993 to July 1996, Mr. White served as Special Assistant to the Chairman of the Federal Deposit Insurance Corporation and also served as a Financial Analyst for the Federal Deposit Insurance Corporation. From July, 1990 to December, 1992, Mr. White served as a financial/budget analyst on issues relating to Resolution Trust Corporation funding. Prior to 1990, Mr. White served as an analyst to the Banking Committee of the House of Representatives. TOM MYERS has been Manager of Production Operations since January, 1997. He was formerly with Sonat Exploration from 1990 to 1996 serving in the capacity of Operations Manager in West Virginia, Arkansas/Eastern Oklahoma, South Texas and the Permian Basin. He was also the Corporate Director of Operations from 1993 to 1994. From 1980 until 1990 he was with Texas Oil and Gas Corp. in West Texas, Mississippi, Alabama, Arkansas, and Eastern Oklahoma in the capacity of District Drilling and Production Manager. Mr. Myers is a Registered Professional Engineer and a member of the Society of Petroleum Engineers and the Oklahoma Independent Petroleum Association. ITEM 11. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE Securities Other Underlying Annual Compensation Annual Option All Other ------------------- Compensation Awards Compensation Name Year Salary($) Bonus($) ($)(1) (# of shares) ($)(2) - ---- ---- --------- -------- ------ ------------- ------ Harold Hamm 1999(3) $ - $ - $ - $ - $ - 1998 250,000 - - - 857 1997 187,506 - - - - Jack Stark 1999 131,616 5,000 - - 8,942 1998 139,964 - - - 12,831 1997 116,550 10,249 - - 9,815 Jeff Hume 1999 125,456 5,000 - - 12,094 1998 123,584 - - - 17,226 1997 113,350 10,249 - - 11,162 Tom Myers 1999 106,928 1,300 - - 8,519 1998 105,513 - - - 11,942 1997 102,679 7,289 - - 346 Roger Clement 1999 106,008 5,000 - - 3,756 1998 98,476 - - - 4,823 1997 89,968 9,718 - - 3,118 Randy Moeder 1999 102,313 20,000 - - 8,200 1998 91,333 - - - 19,566 1997 90,743 10,436 - - 18,666 - ----------------- (1) Represents the value of perquisites and other personal benefits in excess of 10% of annual salary and bonus. For the year ended December 31, 1999, the Company paid no other annual compensation to its named Executive Officers. (2) Represents contributions made by the Company to the accounts of executive officers under the Company's profit sharing plan and under the Company's nonqualified compensation plan. (3) Received no compensation during the calendar year 1999. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Harold Hamm, Chairman of the board, President and Chief Executive Officer and a director of the Company beneficially owns 44,496 shares (90.7%) of the Company's outstanding common stock. The remaining 4,545 shares (9.3%) of the outstanding common stock is beneficially owned by the Harold Hamm HJ Trust (1,818 shares) and the Harold Hamm DST Trust (2,727 shares). These trusts are irrevocable trusts over which Harold Hamm has no voting or investment power. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Set forth below is a description of transactions entered into between the Company and certain of its officers, directors, employees and stockholders during 1999. Certain of these transactions will continue in the future and may result in conflicts of interest between the Company and such individuals, and there can be no assurance that conflicts of interest will always be resolved in favor of the Company. OIL AND GAS OPERATIONS. In its capacity as operator of certain oil and gas properties, the Company obtains oilfield services from related companies, including Hamm & Phillips Service Company, Stride Well Service Inc., Oil Tool Rentals, Inc. and Catworks, Inc. These services include leasehold acquisition, well location, site construction and other well site services, saltwater trucking, use of rigs for completion and workover of oil and gas wells and the rental of oil field tools and equipment. Harold Hamm is the chief executive officer and principal stockholder of each of these related companies. The aggregate amounts paid by Continental to these related companies during 1999 was $7.4 million and at December 31, 1999 the Company owed these companies approximately $0.4 million in current accounts payable. The services discussed above were provided at costs and upon terms that management believes are no less favorable to the Company than could have been obtained from unrelated parties. In addition, Harold Hamm and certain companies controlled by him own interests in wells operated by the Company. At December 31, 1999, the Company owed such persons an aggregate of $1,239,000, representing their shares of oil and gas production sold by the Company. STOCKHOLDER LOANS AND ADVANCES. During 1999, the Company made no loans or advances to the principal stockholder or affiliates. OFFICE LEASE. The Company leases office space under operating leases directly or indirectly from the principal stockholder and Continental Management Company, L.L.C., a Company owned in part by the principal stockholder. In 1999, the Company paid rents associated with these leases of approximately $369,000. The Company believes that the terms of its lease are no less favorable to the Company than those which would be obtained from unaffiliated parties. PARTICIPATION IN WELLS. Certain officers and directors of the Company have participated in, and may participate in the future in, wells drilled by the Company, or as in the principal stockholder's case the acquisition of prop- erties. At December 31, 1999, the aggregate unpaid balance owed to the Company by such officers and directors was $768,000, none of which was past due. Of the amount due from directors and officers at December 31, 1999, $767,000 is associated with the principal stockholder's ownership in the Worland field. Currently, the December 31, 1999 balance has been paid and the amount due from the principal stockholder is approximately $11,000. WORLAND FIELD. Effective June 1, 1998, the Company sold an undivided 50% interest in the 70,000 net leasehold acres it acquired in the Worland Field Acquisition to its principal stockholder, Harold Hamm. The Worland Field sale did not include inventory and certain items of equipment which the Company had acquired in the Worland Field Acquisition. The $42.6 million purchase price paid by the principal stockholder equals the Company's cost basis in such leasehold acres. The principal stockholder paid $19.3 million of the purchase price in cash and the balance of $23.3 million by the cancellation of indebtedness owed to the principal stockholder by the Company. The principal stockholder is subject to the applicable unit agreements in place with respect to his interests in the Worland Field. In December 1999, the principal stockholder contributed his interest in the purchased properties of approximately $41.4 million along with debt of $18.6 million. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) 1. FINANCIAL STATEMENTS: The following financial statements of the Company and the Report of the Company's Independent Public Accountants thereon are included in PART II, ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Report of Independent Public Accountants Consolidated Balance Sheet as of December 31, 1998 and 1999 Consolidated Statement of Operations for the three years in the period ended December 31, 1999 Consolidated Statement of Cash Flows for the three years in the period ended December 31, 1999 Consolidated Statement of Changes in Equity for the three years in the period ended December 31, 1999 Notes to the Consolidated Financial Statements 2. FINANCIAL STATEMENT SCHEDULES: All schedules are omitted because the required information is inapplicable or the information is presented in the Financial Statements or the notes thereto. (b) REPORTS ON FORM 8-K None (c) EXHIBITS: 3.1 Amended and Restated Certificate of Incorporation of Continental Resources, Inc. [3.1] (1) 3.2 Amended and Restate Bylaws of Continental Resources, Inc. [3.2] (1) 3.3 Certificate of Incorporation of Continental Gas, Inc. [3.3] (1) 3.4 Bylaws of Continental Gas, Inc., as amended and restated. [3.4] (1) 3.5 Certificate of Incorporation of Continental Crude Co. [3.5] (1) 3.6 Bylaws of Continental Crude Co. [3.6] (1) 4.1 Restated Credit Agreement dated May 12, 1998 among Continental Resources, Inc. and Continental Gas, Inc., as Borrowers and Bank One, Oklahoma, N.A. and the Institutions named therein as Banks and Bank One, Oklahoma, N.A. as Agent (the "Credit Agreement") [4.1] (1) 4.1.1 First Amendment to the Credit Agreement between Registrant, the financial institutions named therein and Bank One, Oklahoma, N.A., as Agent dated February 10, 1999 (2) 4.2 Form of Revolving Note under the Credit Agreement [4.2] (1) 4.3 Indenture dated as of July 24, 1998 between Continental Resources, Inc., as Issuer, the Subsidiary Guarantors named therein and the United States Trust Company of New York, as Trustee [4.3] (1) 10.4* Conveyance Agreement of Worland Area Properties from Harold G. Hamm, Trustee of the Harold G. Hamm Revocable Intervivos Trust dated April 23, 1984 to Continental Resources, Inc. 10.5* Purchase Agreement signed January 2000, effective October 1, 1999 by and between Patrick Energy Corporation as Buyer and Continental Resources, Inc. as Seller 12.1* Statement re computation of ratio of debt to Adjusted EBITDA 12.2* Statement re computation of ratio of earning to fixed charges 12.3* Statement re computation of ratio of Adjusted EBITDA to interest expense 21.0 Subsidiaries of Registrant incorporated by reference to page 1 of 1999 Annual Report 27* Financial Data Schedule _________________________ * Filed herewith (1) Filed as an exhibit to the Company's Registration Statement on Form S-4, as amended (No. 333-61547) which was filed with the Securities and Exchange Commission. The exhibit number is indicated in brackets and is incorporated by reference herein. (2) Incorporated by reference to Annual Report on Form 10-K for the fiscal year ended December 31, 1998. 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 28, 2000 Continental Resources, Inc. HAROLD HAMM Harold Hamm Chairman of the Board, President And Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in capacities and on the dates indicated. Signatures Title Date HAROLD HAMM Harold Hamm Chairman of the Board, March 28, 2000 President, Chief Executive Officer (principal executive officer) and Director Roger V. Clement Senior Vice President and March 28, 2000 Chief Financial Officer (Principal financial officer and principal accounting officer), Treasurer, and Director Jack Stark Senior Vice President and March 28, 2000 Director Randy Moeder Senior Vice President, March 28, 2000 Secretary and Director Jeff Hume Senior Vice President and March 28, 2000 Director 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 Method of Filing - ------- ----------- ---------------- 3.1 Amended and Restated Certificate of Incorporated herein by reference Incorporaiton of Continental Resources, Inc. 3.2 Amended and Restated Bylaws of Incorporated herein by reference Continental Resources, Inc. 3.3 Certificate of Incorporation of Incorporated herein by reference Continental Gas, Inc. 3.4 Bylaws of Continental Gas, Inc., as Incorporated herein by reference amended and restated 3.5 Certificate of Incorporation of Incorporated herein by reference Continental Crude Co. 3.6 Bylaws of Continental Crude Co. Incorporated herein by reference 4.1 Restated Credit Agreement dated May, Incorporated herein by reference 12, 1998 among Continental Resources, Inc. and Continental Gas, Inc., as Borrowers and Bank One, Oklahoma, N.A. and the Institutions named therein as Bank and Bank One, Oklahoma, N.A. as Agent 4.1.1 First Amendment to the Credit Incorporated herein by reference Agreement between Registrant, the financial institutions named therein and Bank One, Oklahoma, N.A., as Agent dated February 10, 1999 4.2 Form of Revolving Note under the Incorporated herein by reference Credit Agreement 4.3 Indenture dated as of July 24, 1998 Incorporated herein by reference between Continental Resources, Inc., as Issuer, the Subsidiary Guarantors named therein and the United States Trust Company of New York, as Trustee 10.4 Conveyance Agreement of Worland Filed herewith electronically Area Properties from Harold G. Hamm, Trustee of the Harold G. Hamm Revocable Intervivos Trust dated April 23, 1984 to Continental Resources, Inc. as Seller 10.5 Purchase Agreement signed Filed herewith electronically January 2000, effective October 1, 1999 by and between Patrick Energy Corporation as Buyer and Continental Resources, Inc. as Seller 12.1 Statement re computation of ratio Filed herewith electronically of debt to Adjusted EBITDA 12.2 Statement re computation of Filed herewith electronically earnings to fixed charges 12.3 Statement re computation of Filed herewith electronically ratio of Adjusted EBITDA to interest expense 21.0 Subsidiaries of Registrant Incorporated herein by reference incorporated by reference to page 1 of 1999 Annual Report 27 Financial Data Schedule Filed herewith electronically