-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, WvJT0w8p7YdvHkwZLpe/ERO+hTNT/CP+mz/iid3mY0+TKyRq1KeCJ9wzVZ4JTP63 9fRFdHsRjnKRSj/gWUzsYw== 0000909334-03-000128.txt : 20030331 0000909334-03-000128.hdr.sgml : 20030331 20030331102025 ACCESSION NUMBER: 0000909334-03-000128 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONTINENTAL RESOURCES INC CENTRAL INDEX KEY: 0000732834 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 730767549 STATE OF INCORPORATION: OK FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 333-61547 FILM NUMBER: 03627632 BUSINESS ADDRESS: STREET 1: 302 NORTH INDEPENDENCE, SUITE 1400 CITY: ENID STATE: OK ZIP: 73702 BUSINESS PHONE: 5802338955 10-K 1 criform10k-32803.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2002 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to __________________ Commission File Number: 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, 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 reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ ] No [X] The Registrant is not subject to the filing requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, but files reports required by those sections pursuant to contractual obligation requirements. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.[X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act.) Yes [ ] No [X] As of March 28, 2003, there were 14,368,919 shares of the registrant's common stock, par value $.01 per share, outstanding. The common stock is privately held by affiliates of the registrant. Document incorporated by reference: None CONTINENTAL RESOURCES, INC. Annual Report on Form 10-K for the Year Ended December 31, 2002 TABLE OF CONTENTS PART I ITEM 1. BUSIESS ..........................................................3 ITEM 2. PROPERTIES ......................................................14 ITEM 3. LEGAL PROCEEDINGS ...............................................22 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS .............22 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS..........................................................22 ITEM 6. SELECTED FINANCIAL AND OPERATING DATA ...........................22 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS .......................................24 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ......30 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA .....................32 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE ........................................32 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ..............32 ITEM 11. EXECUTIVE COMPENSATION ..........................................34 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT...35 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ..................36 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.37 PART I SPECIAL NOTE REGARDING 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 estimates 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 plan for 2003 and beyond could differ materially from those expressed in forward-looking statements. All subsequent written and oral forward-looking statements to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors. ITEM 1. BUSINESS OVERVIEW Continental Resources, Inc. and its subsidiaries, Continental Gas, Inc. ("CGI"), Continental Resources of Illinois, Inc. ("CRII") 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 Mountain and Mid-Continent regions of the United States, and to a lesser but growing extent, in the Gulf Coast region of Texas and Louisiana. In addition to its exploration, development, exploitation and acquisition activities, the Company currently owns and operates 700 miles of natural gas pipelines, eight gas gathering systems and three gas processing plants in its operating areas. 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 74.9 MMBoe at year-end 2002, and has increased its annual production from 2.2 MMBoe in 1995 to 5.4 MMBoe in 2002. As of December 31, 2002, the Company's reserves had a present value of estimated future net revenues, discounted at 10% ("PV-10") of $633.4 million calculated in accordance with the Securities and Exchange Commission (the "Commission" or "SEC") guidelines. At that date, approximately 84% of the Company's estimated proved reserves were oil and approximately 60% of its total estimated reserves were classified as proved developed. At December 31, 2002, the Company had interests in 2,385 producing wells of which it operated 1,823. The Company was originally formed in 1967 to explore, develop and produce oil and gas in Oklahoma. Through 1993 the Company's activities and growth remained focused primarily in Oklahoma. In 1993, the Company expanded its activity into the Rocky Mountain and Gulf Coast regions. Through drilling success and strategic acquisitions, 83% of the Company's estimated proved reserves as of December 31, 2002 are now found in the Rocky Mountain region. The Company's growth in the Gulf Coast region during the mid-1990's was slowed due to the rapid growth of the Rocky Mountain region. Since 1999, drilling activity has increased in the Gulf Coast region and it is expected to be another core operating area for the Company. To further expand its Mid-Continent operations, the Company acquired Mt. Vernon, Illinois-based Farrar Oil Company in 2001. Farrar has been a long time partner with the Company and provides the assets and experienced personnel from which the Company can expand its operations into the Illinois and Appalachian basins of the eastern United States. 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. The Company seeks to increase production and cash flow, and develop additional reserves by drilling new wells (including horizontal wells), secondary recovery operations, workovers, recompletions of existing wells 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 use of the Company's technical expertise in horizontal drilling and secondary recovery, allow the Company to maximize the utilization of its infrastructure in core operating areas. The Company's exploration strategy is designed to combine the knowledge of its professional staff with the competitive and technical strengths of the Company to pursue new field discoveries in areas that may be out of favor or overlooked. This strategy enables the Company to build a controlling lease position in targeted projects and to realize the full benefit of any project success. The Company tries to maintain an inventory of three or four new exploratory projects at all times for future growth and development. On an ongoing basis, the Company evaluates and considers divesting of oil and gas properties considered to be non-core to the Company's reserve growth plans with the goal that all Company assets are contributing to its long-term strategic plan. PROPERTY OVERVIEW Rocky Mountain Region. The Company's Rocky Mountain properties are concentrated in the North Dakota, South Dakota and Montana portions of the Williston Basin, and in the Big Horn Basin in Wyoming. These properties represented 83% of the Company's estimated proved reserves and 76% of the PV-10 of the Company's proved reserves as of December 31, 2002. The Company owns approximately 465,000 net leasehold acres, has interests in 710 gross (615 net) producing wells, is the operator of 93% of these wells, and has identified 86 potential drilling locations in the Rocky Mountain region. The Williston Basin properties represented 74% of the Company's estimated proved reserves and 70% of the PV-10 of its proved reserves at December 31, 2002. In the Williston Basin, the Company owns approximately 369,000 net leasehold acres, has interests in 381 gross (328 net) producing wells and has identified 86 potential drilling locations. The Company's principal properties in the Williston Basin include eight high-pressure air injections, or HPAI, secondary recovery units located in the Cedar Hills, Medicine Pole Hills and Buffalo Fields. The Company's extensive experience has demonstrated that its secondary recovery methods have increased the reserves recovered from existing fields by 200% to 300% through the injection and withdrawal of fluids or gases. The combination of injection and withdrawal recovers additional oil from the reservoir that cannot be recovered by primary recovery methods. The Buffalo Field units are the oldest of the Company's secondary recovery projects and have been in operations since 1978. The Cedar Hills Field units are the most recent and largest of the Company's secondary recovery units representing approximately 59% of the proved reserves and 58% of the PV-10 attributable to the Company's proved reserves at December 31, 2002. Combined, the Company's eight HPAI secondary recovery projects represent 80% of the HPAI projects in North America. In the Big Horn Basin, the Company's properties are focused in and around the Worland Field. The Worland Field represents 9% of the Company's estimated proved reserves and 6% of the PV-10 of the Company's proved reserves at December 31, 2002. In the Worland Field, the Company owns approximately 96,000 net leasehold acres and has interests in 329 gross (287 net) producing wells, of which the Company operates 303. In the Worland Field, the Company has identified 70 potential workovers or recompletions and has initiated three pilot secondary recovery projects to increase recovery of known oil in the field. Mid-Continent Region. The Company's Mid-Continent properties are located primarily in the Anadarko Basin of western Oklahoma, southwestern Kansas, Illinois, and in the Texas Panhandle. At December 31, 2002, the Company's estimated proved reserves in the Mid-Continent region represented 16% of the Company's total estimated proved reserves, 66% of the Company's natural gas reserves and 22% of the Company's PV-10. In the Mid-Continent region, the Company owns approximately 162,000 net leasehold acres, has interests in 1,574 gross (956 net) producing wells and has identified 32 potential drilling locations. The Company operates 68% of the gross wells in which it has interests. Gulf Coast Region. The Company's Gulf Coast properties are located primarily onshore, along the Texas and Louisiana coasts, and include the Pebble Beach and Luby projects in Nueces County, Texas and the Jefferson Island project in Iberia Parish, Louisiana. The Company also participates in Gulf of Mexico drilling ventures as part of the Company's ongoing expansion in the Gulf Coast region. During 2002, the Company's Gulf Coast producing wells represented only 4% of the Company's total producing well count, but produced 21% of the Company's total gas production for the year. As of December 31, 2002, the Company's Gulf Coast properties represented 1% of the Company's total estimated proved reserves, 4% of its estimated proved gas reserves and 2% PV-10 of the Company's proved reserves. In the Gulf Coast, the Company owns approximately 24,000 net leasehold acres; has interests in 101 gross (83 net) producing wells and has identified 53 potential drilling locations from 95 square miles of proprietary 3-D data and several hundred miles of non-proprietary 2-D and 3-D seismic data. The Company operates 79% of the gross wells in which it has interests. OTHER INFORMATION The Company's subsidiary, Continental Gas, Inc., was formed as a gas marketing company in April 1990. Currently, Continental Gas, Inc. specializes in gas marketing, pipeline construction, gas gathering systems and gas plant operations. On June 19, 2001, the Company formed a new subsidiary, Continental Resources of Illinois, Inc., or CRII. On July 9, 2001, the Company, through CRII, purchased the assets of Farrar Oil Company and Har-Ken Oil Company, oil and gas operating companies in Illinois and Kentucky, respectively. The Company's remaining subsidiary, Continental Crude Co., has been inactive since its formation in 1998. Continental Resources, Inc. and its subsidiaries are headquartered in Enid, Oklahoma, and Mt. Vernon, Illinois, with additional offices in Baker, Montana; 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 competitive advantages and provide it with diversified growth opportunities, including the following: PROVEN GROWTH RECORD. The Company has demonstrated consistent growth through a balanced program of development, exploitation and exploratory drilling and acquisitions. The Company has increased its proved reserves 182% from 26.6 MMBoe in 1995 to 74.9 MMBoe as of December 31, 2002. SUBSTANTIAL AND DIVERSIFIED DRILLING INVENTORY. The Company is active in seven different geologic basins in 11 states and has identified more than 171 potential drilling locations based on geological and geophysical evaluations. As of December 31, 2002, the Company held approximately 651,000 net acres, of which approximately 57% were classified as undeveloped. Management believes that its current inventory and acreage holdings could support three to five years of drilling activities depending upon oil and gas prices. LONG-LIFE NATURE OF RESERVES. The Company's producing reserves are primarily characterized by 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 and primary and secondary production levels. The Company's properties have an average reserve life of approximately 14 years. SUCCESSFUL DRILLING AND ACQUISITION RECORD. The Company has maintained a successful drilling record. During the five years ended December 31, 2002, the Company participated in 239 gross wells of which 83% were completed as producers. During this time, reserves added from drilling, workovers and related activities totaled 34.4 MMBoe of proved developed reserves at an average finding cost of $7.36 per barrel of oil equivalent ("Boe"). During 2002, the Company spent $57.0 million on the development of the Cedar Hills field. $32.4 million was spent drilling injection wells and $24.6 million was spent on infrastructure, including compressors and pipelines, which resulted in no additional reserves in 2002. Excluding these costs, our 5year average finding cost would be $5.71. During the same period, the Company acquired 21.2 MMBoe at an average cost of $4.60 per Boe. Including major revisions of 12.0 MMBoe due primarily to fluctuating prices, the Company added a total of 67.7 MMBoe at an average cost of $5.19 per Boe during the last five years. SIGNIFICANT OPERATIONAL CONTROL. Approximately 97.4% of the Company's PV-10 at December 31, 2002, 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 continually evolving technologies of 3-D seismic, directional drilling, and precision horizontal drilling, and is among the few companies in North America to successfully utilize high pressure air injection 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 243 horizontal wells in the Rocky Mountains and Mid-Continent regions. Through the combination of precision horizontal drilling and 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. Eight senior officers have an average of 24 years of oil and gas industry experience. Additionally, the Company's technical staff, which includes 14 petroleum engineers and 11 geoscientists, have an average of more than 25 years experience in the industry. DEVELOPMENT, EXPLORATION AND EXPLOITATION ACTIVITIES CAPITAL EXPENDITURES. The Company's projected capital expenditures for development, exploitation and exploration activities in 2003 total $105.9 million. Approximately $74.0 million (69%) is targeted for drilling, $8.3 million (8%) for lease acquisitions and seismic, $4.0 million (4%) for workovers and recompletions, $3.3 million (3%) for acquisitions, and $16.4 million (16%) for secondary recovery projects and facilities. Funding for these expenditures will come from a combination of cash flow and the Company's credit facility. Top priority will be given to completing installation of secondary recovery facilities at the Cedar Hills Field by year-end 2003. This will account for $52.6 million or 50% of the Company's projected capital expenditures for 2003. This includes $40.2 million for drilling injector wells and $12.4 million for compressors, equipment and facilities. Approximately $33.8 million will be spent on development and exploration drilling outside of the Cedar Hills unit. Expenditures on projects outside of Cedar Hills are discretionary and may vary from projections in response to commodity prices and available cash flow. DEVELOPMENT AND EXPLOITATION. The Company's development and exploitation activities are designed to maximize the value of existing properties. Activities include the drilling of vertical, directional and horizontal development wells, workover and recompletions in existing wellbores, and secondary recovery water flood and HPAI projects. During 2003, the Company expects to invest $52.0 million drilling 59 development-drilling projects, representing 70% of the Company's total 2003 drilling budget. Within the development drilling budget, 77% will be spent drilling injector wells within the Cedar Hills units, 5% on other projects in the Williston and Big Horn Basins, 10% in the Gulf Coast region and 8% in the Mid-Continent region. The Company also expects to invest $4.0 million during 2003 on workovers and recompletions, $3.3 million for acquisitions, and $16.4 million on secondary recovery projects and related facilities. EXPLORATION ACTIVITIES. The Company's exploration projects are designed to locate new reserves and fields for future growth and development. 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 will continue to build exploratory inventory throughout the year for future drilling. The Company will initiate, on a priority basis, as many projects as cash flow prudently justifies. The Company anticipates investing $21.9 million drilling 36 exploratory projects during 2003, representing 30% of the Company's total 2003 drilling budget with 14% to be spent in the Mid-Continent region, 50% in the Rocky Mountain region and 36% in the Gulf Coast region. The following table summarizes the number of projects Continental expects to complete in 2003.
Drilling Secondary 3-D Locations Workovers Recovery Seismic TOTAL -------------------- ----------------- ------------------ ------------ ---------- DEVELOPMENT MID CONTINENT Anadarko 10 14 0 0 24 Black Warrior 0 0 0 0 0 Illinois 3 32 3 0 38 ------------------------------------------------------------------------------------- Total 13 46 3 0 62 ROCKY MOUNTAIN Williston 2 2 4 0 8 Cedar Hills 37 10 0 0 47 Big Horn 0 10 3 0 13 ------------------------------------------------------------------------------------- Total 39 22 7 0 68 GULF COAST Texas 7 0 0 0 7 Louisiana 0 0 0 0 0 Gulf of Mexico 0 0 0 0 0 ------------------------------------------------------------------------------------- Total 7 0 0 0 7 TOTAL DEV 59 68 10 0 137 ===================================================================================== EXPLORATORY MID CONTINENT Anadarko 1 0 0 1 2 Black Warrior 5 0 0 3 8 Illinois 10 0 0 3 13 ------------------------------------------------------------------------------------- Total 16 0 0 7 23 ROCKY MOUNTAIN Williston 11 0 0 8 19 Cedar Hills 0 0 0 0 0 Big Horn 0 0 0 0 0 ------------------------------------------------------------------------------------- Total 11 0 0 8 19 GULF COAST Texas 6 0 0 2 8 Louisiana 1 0 0 1 2 Gulf of Mexico 2 0 0 3 5 ------------------------------------------------------------------------------------- Total 9 0 0 6 15 TOTAL EXPL 36 0 0 21 57 ===================================================================================== GRAND TOTAL 95 68 10 21 194 =====================================================================================
ACQUISITION ACTIVITIES The Company seeks to acquire properties, which have the potential to be immediately positive 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. 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, 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 makes it particularly difficult to estimate future prices of oil, 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 price risk management arrangements from time to time to reduce its exposure to price risks in the sale of its oil and gas, the Company's price risk management 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 more discussion in "Management's Discussion and Analysis of Financial Condition and Results of Operations". REPLACEMENTS 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 would decline. There can be no assurance that the Company will continue to be successful in its effort to increase or replace its proved 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 its Senior Subordinated Notes (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 rely 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 in 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, 2002, the estimated future net cash flow of $1,304 million and PV-10 of $633.4 million attributable to the Company's proved oil and gas reserves are based on prices in effect at the date ($29.04 per barrel ("Bbl") of oil and $3.33 per thousand cubic feet ("Mcf") of natural gas), which may be materially different from 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 integration acquired business 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 or 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. 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 expend 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 not 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, 2002, on a consolidated basis, the Company and the Subsidiary Guarantors (defined below) had $247.1 million in indebtedness (including short-term indebtedness and current maturities of long-term indebtedness) compared to the Company's stockholder's equity of $115.0 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 Financial and Operating Data" 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 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; and o The Company may be substantially more leveraged than certain of its competitors, which may place it a relative competitive disadvantage and make it more vulnerable to change 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 that the Company could realize there from. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." 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 that liens created pursuant to the Credit Facility and certain permitted liens; o Mergers, consolidations and sales of all or 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; and 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 there under 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 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 (consisting of commitments under the Credit Facility) 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 Guarantors 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, 2003, was $126.5 million. The Subsidiary Guarantees are subordinated to the guarantor's senior debt to the same extent and in the same manner as the Notes are subordinated to senior debt. The Company or the Subsidiary Guarantors may incur additional senior debt 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 are not 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 The Company has derived approximately 29% of its operating cash flows from its subsidiaries, Continental Gas and Continental Resources of Illinois, Inc. The holders of the Notes have no direct claim against the Company's subsidiaries other that 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 holder of the Notes to participate in any distribution of assets of any Subsidiary Guarantor upon liquidation, bankruptcy, reorganization or otherwise will, as is that 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 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 of 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 dates 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 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 Resources." 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 or an Excess Cash Offer will constitute an event of default under the Indenture. RISK OF 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. 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. Beginning January 1, 2001, all derivatives must be marked to market under the provisions of statement of Financial Accounting Standards No. 133, "Accounting for Derivatives" ("SFAS No. 133"). If the Company enters into qualifying derivative instruments for the purpose of hedging prices and the derivative instruments are not perfectly effective in hedging the underlying risk, all ineffectiveness will be recognized currently in earnings. The effective portion of the gain or loss on qualifying derivative instruments will be reported as other comprehensive income and reclassified to earnings in the same period as the hedged production takes place. Physical delivery contracts, which are deemed to be normal purchases or normal sales, are not accounted for as derivatives. 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 effect 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. WRITE DOWN OF CARRYING VALUES The Company periodically reviews the carrying value of its oil and gas properties in accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets". SFAS No. 144 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 the assets 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 changes) is less that 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 that 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--Regulations." 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 of 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 ground water resources, potentially resulting in suspension of operation of the wells, fine 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 a 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 that 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, 2003, Harold Hamm, the Company's principal stockholder, President and Chief Executive Officer and a Director, beneficially owned 13,037,328 shares of Common Stock representing, in the aggregate, approximately 91% of the outstanding common stock of the Company. The Harold Hamm DST Trust and Harold Hamm HJ Trust together own the remaining 9.3% of Common Stock. An independent third party is the trustee for both of these trusts and Harold Hamm has no beneficial ownership in them. As a result, Mr. Hamm 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". REGULATIONS 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 to statue to issue, and have issued, rules and regulations binding upon the oil and gas industry and its individual members. REGULATIONS OF SALES AND TRANSPORTATION OF NATURAL GAS. The Federal Energy Regulatory Commission (the "FERC") regulates the transportation and sale of 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 us 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 from the effect on other natural gas producers with whom the Company 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. The Company's sales of crude oil, condensate and gas liquids 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. The Company's oil and gas operations are subject to pervasive federal, state and local laws and regulations concerning the protection and preservation of the environment (e.g., ambient air, and surface and subsurface soils and waters), human health, worker safety, natural resources, and wildlife. These laws and regulations affect virtually every aspect of the Company's oil and gas operations, including its exploration for, and production, storage, treatment, and transportation of, hydrocarbons and the disposal of wastes generated in connection with those activities. These laws and regulations increase the Company's costs of planning, designing, drilling, installing, operating, and abandoning oil and gas wells and appurtenant properties, such as gathering systems, pipelines, and storage, treatment and salt water disposal facilities. The Company has expended and will continue to expend significant financial and managerial resources to comply with applicable environmental laws and regulations, including permitting requirements. The Company's failure to comply with these laws and regulations can subject it to substantial civil and criminal penalties, claims for injury to persons and damage to properties and natural resources, and clean up and other remedial obligations. Although the Company believes that the operation of its properties generally complies with applicable environmental laws and regulations, the risk of incurring substantial costs and liabilities are inherent in the operation of oil and gas wells and appurtenant properties. The Company could also be subject to liabilities related to the past operations conducted by others at properties now owned by it, without regard to any wrongful or negligent conduct by the Company. The Company cannot predict what effect future environmental legislation and regulation will have upon its oil and gas operations. The possible legislative reclassification of certain wastes generated in connection with oil and gas operations as "hazardous wastes" would have a significant impact on the Company's operating costs, as well as the oil and gas industry in general. The cost of compliance with more stringent environmental laws and regulations, or the more vigorous administration and enforcement of those laws and regulations, could result in material expenditures by the Company to remove, acquire, modify, and install equipment, store and dispose of waters, remediate facilities, employ additional personnel, and implement systems to ensure compliance with those laws and regulations. These accumulative expenditures could have a material adverse effect upon the Company's profitability and future capital expenditures. REGULATION OF OIL AND GAS EXPLORATION AND PRODUCTION. The Company's exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells, and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and 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. EMPLOYEES As of March 28, 2003, the Company employed 288 people, including 97 administrative personnel, 11 geoscientists, 14 engineers and 166 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 employee to be satisfactory. From time to time the Company utilizes the services of independent contractors to perform various field and other services. ITEM 2. PROPERTIES The Company's oil and gas properties are located in selected portions of the Mid-Continent, Rocky Mountains and Gulf Coast regions. Through 1993, most of the Company's activity and growth was focused in the Mid-Continent region. In 1993 the Company expanded its drilling and acquisition activities into the Rocky Mountain and Gulf Coast regions seeking added opportunity for production and reserve growth. The Rocky Mountain region was targeted for oil reserves with good secondary recovery potential and therefore, long life reserves. The Gulf Coast region was targeted for natural gas reserves with shorter reserve life but high current cash flow. As of December 31, 2002, the Company's estimated net proved reserves from all properties totaled 74.9 MMBoe with 83% of the reserves located in the Rocky Mountains, 16% in the Mid-Continent and 1% in the Gulf Coast regions. At December 31, 2002, 84% of the Company's net proved reserves were oil and 16% were natural gas. The Company's oil reserves are confined primarily to the Rocky Mountain region and its natural gas reserves are primarily from the Mid-Continent and Gulf Coast regions. Approximately $66.8 million, or 63%, of the Company's projected $105.9 million capital expenditures for 2003 are focused on expansion and development of its oil properties in the Rocky Mountain region while the remaining $39.1 million, or 37%, is focused primarily on natural gas projects in the Mid-Continent and Gulf Coast regions. The following table provides information with respect to the Company's net proved reserves for its principal oil and gas properties as of December 31, 2002:
% of Total Oil Present Value Present Value Oil Gas Equivalent Of Future Net Of Future Net Area (MBbl) (MMcf) (MBoe) Revenues(1)(M$) Revenues(1) - ---------------------------------------------------------------------------------------------------------------------------- ROCKY MOUNTAINS: Williston Basin 54,026 10,817 55,829 $ 446,824 70% Big Horn Basin 4,758 10,119 6,445 35,511 6% ------------------ ---------------- -------------- ----------------- ---------------- Total ROCKY MOUNTAINS 58,784 20,936 62,274 482,335 76% MID-CONTINENT: Anadarko Basin 1,835 42,561 8,929 106,230 17% Black Warrior Basin 0 721 120 1,920 0% Texas Panhandle 17 2,480 430 4,613 1% Illinois Basin 2,565 464 2,642 28,243 4% ------------------ ---------------- -------------- ----------------- ---------------- Total MID-CONTINENT 4,417 46,226 12,121 141,006 22% GULF COAST: Luby 17 1,010 185 3,232 1% Pebble Beach 31 1,054 207 3,628 1% Louisiana Onshore 21 170 49 887 0% Offshore 11 551 103 2,309 0% ------------------ ---------------- -------------- ----------------- ---------------- Total GULF COAST 80 2,785 544 10,056 2% TOTALS 63,281 69,947 74,939 $ 633,397 100% ================== ================ ============== ================= ================ (1) Future estimated net revenues discounted at 10%
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, 2002, totaled 62.3 MMBoe and represented 76% of the Company's PV-10. Approximately 52% of these estimated proved reserves are proved developed. During the twelve months ended December 31, 2002, the average net daily production was 8,121 Bbls of oil and 4,891 Mcf of natural gas, or 8,943 Boe per day from the Rocky Mountain properties. The Company's leasehold interests include 173,000 net developed and 292,000 net undeveloped acres, which represent 27% and 45% of the Company's total leasehold, respectively. This leasehold is expected to be developed utilizing 3-D seismic, precision horizontal drilling and secondary recovery technologies, where applicable. As of December 31, 2002, the Company's Rocky Mountain properties included an inventory of 65 development and 21 exploratory drilling locations. WILLISTON BASIN CEDAR HILLS FIELD. The Cedar Hills Field was discovered in November 1994. During the twelve months ended December 31, 2002, the Cedar Hills Field properties produced 3,813 net Boe per day to the Company's interests. 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, 2002, the Company drilled or participated in 199 gross (139 net) horizontal wells, of which 192 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 either HPAI and/or traditional water flooding technology. Both technologies have been applied successfully in adjacent secondary recovery units for over 30 years and have proven to increase oil recoveries from the Red River "B" formation by 200% to 300% over primary recovery. The Company is proficient using either technology and is in the process of implementing both as part of its secondary recovery operations in the Cedar Hills Field. Effective March 1, 2001, the Company obtained approval for two secondary recovery units in the Cedar Hills Field; the Cedar Hills North-Red River "B" Unit ("CHNRRU") located in Bowman and Slope Counties, North Dakota and the West Cedar Hills Unit ("WCHU") located in Fallon County, Montana. The Company owns 95% of the working interest in the CHNRRU and is the operator of the unit. The CHNRRU contains 79 wells and 50,000 acres. The Company owns 100% of the working interest in the WCHU and is the unit operator. The WCHU contains 10 wells and 8,000 acres. An estimated $52.5 million will need to be invested during 2003 to fully implement the Company's secondary recovery operations in the Cedar Hills Field. The components of the $52.5 million invested are $40.2 million for infill drilling and $12.3 million for infrastructure. By year-end 2003, the Company expects to have completed 56 of the 65 required injectors and installed facilities to begin injection in 100% of the units. The Cedar Hills Field represents 59% of the Company's estimated proved reserves and $367.4 million, or 58%, of the PV-10 of the Company's proved reserves at December 31, 2002. MEDICINE POLE HILLS, MEDICINE POLE HILLS WEST, MEDICINE POLE HILLS SOUTH, 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, 2002, these units produced 1,034 Boe per day, net to the Company's interests, and represented 5.3 MMBoe and $36.4 million, or 6%, of the PV-10 attributable to the Company's estimated proved reserves as of December 31, 2002. These units are HPAI enhanced recovery projects that produce from the Red River "B" formation and are operated by the Company. All were discovered and developed with conventional vertical drilling. The oldest vertical well in these units has been producing for 47 years, demonstrating the long-lived production characteristic of the Red River "B" formation. There are 156 producing wells in these units and current estimates of remaining reserve life range from four to 13 years. The Company subsequently expanded the Medicine Pole Hills Unit through horizontal drilling into the Medicine Pole Hills West Unit ("MPHWU"), which became effective April 1, 2000. The MPHWU produces from 25 wells and encompasses an additional 22 square miles of productive Red River "B" reservoir. The Company owns approximately 80% of the MPHWU and began secondary injection November 22, 2000. The MPHWU was the first in a scheduled two-phase expansion of the Medicine Pole Hills Unit. Phase two of the expansion plan was successfully completed during 2001 delineating another 20 square miles of productive Red River B reservoir through horizontal drilling. The Medicine Pole Hills South Unit ("MPHSU") became effective October 1, 2002, with injection expected to begin by mid-year 2003. LUSTRE AND MIDFORK FIELDS. In January 1992, the Company acquired the Lustre and Midfork Fields which, during the twelve months ended December 31, 2002, produced 357 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 production rate and is long lived. There are currently 43 wells producing in the two fields. No secondary recovery operations are underway in either field at this time but are under consideration. The Company currently owns 99,000 net acres in the Lustre and Midfork Field area. The Company believes significant upside exists in the reservoirs that underlie the Charles "C" dolomite including the Mission Canyon, Lodgepole, and Nisku formations. Historically production from these reservoirs is more difficult to locate but prolific when found. 3-D seismic is being utilized to locate reserves in these reservoirs. During 2002, the Company made a modest discovery in the Lodgepole formation utilizing 60 square miles of proprietary 3-D data acquired in late 2001. The discovery is significant in that it established production 200 miles from the nearest Lodgepole production near Dickinson, North Dakota, which was quite prolific. The Company controls approximately 70,000 net undeveloped acres in this particular part of the play and has identified 12 drilling locations from its 3-D seismic. During 2003, the Company plans to drill 1 development and 2 exploratory wells. 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 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. During the twelve months ended December 31, 2002, the Worland Field properties produced 1,763 Boe per day, net to the Company's interests. These properties cover 96,000 net leasehold acres in the Worland Field of the Big Horn Basin in northern Wyoming, of which 29,000 net acres are held by production and 67,000 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 more than 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 38 producing wells located on non-unitized acreage. The Company's Worland Field properties include interests in 329 producing wells, 303 of which are operated by the Company. As of December 31, 2002, the estimated net proved reserves attributable to the Company's Worland Field properties were approximately 6.4 MMBoe, with an estimated PV-10 of $35.5 million. Approximately 74%, 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 December 1, 2001, through December 31, 2001, to sell crude oil produced from its Worland Field properties at an average price of $6.00 per Bbl less than the NYMEX price. Subsequent to these contracts, and effective January 1, 2002, the Company entered into a contract to sell the Worland Field production at a gravity-adjusted price of $4.21 per barrel less than the monthly NYMEX average price. This contract was renegotiated January 2003 at a price that will average $4.00 to $5.00 less than the monthly NYMEX average price. The Company believes that secondary and tertiary recovery projects have significant potential for the addition of reserves in the Worland Field area fields. The Company continues to seek the best method for increasing recovery from the producing reservoirs. Currently the Company has one Tensleep waterflood project and one pilot imbibition flood underway. The Company implemented water injection into five wells in late 2002 to evaluate secondary and pressure recovery techniques that will best process the Phosphoria dolomite oil reserves. Production should be enhanced in as many as 20 offset wells. The Company has installed the system for expansion if the results meet expectations. In addition to the secondary and pressure recovery projects, the Company is evaluating infill drilling opportunities based on neural network analysis techniques and has identified 70 wells for acid fracturing treatments. The infill drilling and acid frac procedures will be evaluated as each well is completed to ensure that the techniques are viable. As evidenced by past infill drilling and acid fracturing stimulations, reserve growth can be significant. MID-CONTINENT The Company's Mid-Continent properties are located primarily in the Anadarko Basin of western Oklahoma and the Texas Panhandle. During 2001, the Company expanded its operations in the Mid-Continent through successful exploration in the Black Warrior Basin in Mississippi and the acquisition of Farrar Oil Company's assets in the Anadarko and Illinois Basins. At December 31, 2002, the Company's estimated proved reserves in the Mid-Continent totaled 12.1 MMBoe and represented 22% of the Company's PV-10. At December 31, 2002, approximately 64% of the Company's estimated proved reserves in the Mid-Continent were natural gas. Net daily production from these properties during 2002 averaged 2,129 Bbls of oil and 15,150 Mcf of natural gas, or 4,658 Boe to the Company's interests. The Company's Mid-Continent leasehold position includes 100,000 net developed and 62,000 net undeveloped acres, representing 15% and 10% of the Company's total leasehold, respectively, at December 31, 2002. As of December 31, 2002, the Company's Mid-Continent properties included an inventory of 15 development and 17 exploratory drilling locations. ANADARKO BASIN. The Anadarko Basin properties contained 74% of the Company's estimated proved reserves for the Mid-Continent and 17% of the Company's total PV-10 at December 31, 2002, and represented 61% of the Company's estimated proved reserves of natural gas. During the twelve months ended December 31, 2002, net daily production from its Anadarko Basin properties averaged 799 Bbls of oil and 13,167 Mcf of natural gas, or 2,993 Boe to the Company's interests from 655 gross (289 net) producing wells, 330 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 Fork, Oswego, Skinner and Tonkawa formations, at depths ranging from 6,000 to 12,000 feet. These properties have been a steady source of cash flow for the Company and are continually being developed by infill drilling, recompletions and workovers. As of December 31, 2002, the Company had identified 12 development and one exploratory drilling location on its properties in the Anadarko Basin. ILLINOIS BASIN. On July 9, 2001, the Company purchased the assets of Farrar Oil Company and its subsidiary, Har-Ken Oil Company, for $33.7 million under its newly formed subsidiary, Continental Resources of Illinois, Inc. ("CRII"). The Illinois Basin properties contained 22% of the Company's estimated proved reserves for the Mid-Continent and 4% of the Company's total PV-10 at December 31, 2002. Net daily production during the twelve months ended December 31, 2002, averaged 1,244 Bbls of oil and 189 Mcf of natural gas, or 1,275 Boe to the Company's interests from 880 gross (646 net) producing wells, 714 of which are operated by the Company. Approximately 70% of the Company's net oil production in this basin comes from 31 active secondary recovery projects. Company expertise resulting in very efficient operations combined with low decline rates makes most of the properties very long lived. Many of the projects have been active for over 15 years with many years of economic life remaining. At year-end the Company was evaluating a production acquisition possessing significant secondary recovery potential. Three new secondary recovery projects are planned for implementation during 2003. All properties are constantly being evaluated and we are continually performing numerous workovers and making injection enhancements. As of December 31, 2002, the Company had 3 development and 10 exploratory drilling locations in inventory and scheduled for drilling during 2003. All of the exploratory drill sites were selected from interpretations utilizing detailed geological studies and computer mapping with all but one defined by seismic programs shot by the Company. In addition, the Company has 6 active exploration project areas with seismic programs to cover all the areas to be shot during 2003. Included in this seismic program are three projects where the use of 3-D seismic will be employed. BLACK WARRIOR BASIN. In April 2000, the Company began a grass roots effort to expand its exploration program into the Black Warrior Basin located in eastern Mississippi and western Alabama. The Company believes the Black Warrior Basin offers opportunity for growth and adds a component of low cost, high rate of return, shallow gas reserves to the Company's overall drilling program. Reservoirs are Pennsylvanian and Mississippian age sands found at depths of 2,500 feet to 4,500 feet with reserves of .75 Bcf per well on average. Net daily production during the ten months ended December 31, 2002, averaged 766 Mcf of natural gas or 128 Boe to the Company's interests. Competition in the basin is low which has enabled the Company to readily acquire leases on new projects and keep costs low. As of December 31, 2002, the Company had acquired 25,000 net acres on selected projects. The Company has also augmented its geological expertise by acquiring licenses to approximately 1,500 miles of 2-D seismic data across the basin. During 2002, the Company drilled 12 wells and established four producers for a 33% success rate. Although this success rate is in line with historical averages for the basin, the production and reserves found have not met expectations. During 2003, the Company plans to drill 5 wells and the results of these wells will dictate the Company's continued commitment to the basin. GULF COAST The Company's Gulf Coast activities are located primarily in the Pebble Beach and Luby Projects in Nueces County, Texas and the Jefferson Island Project in Iberia Parish, Louisiana. The Company is also a partner in a joint venture arrangement with Challenger Minerals, Inc. to locate and participate in drilling opportunities on the shallow shelf of the Gulf of Mexico. At December 31, 2002, the Company's estimated proved reserves in the Gulf Coast totaled .5 MMBoe (85% gas) representing 2% of the Company's total PV-10 and 4% of the Company's estimated proved reserves of natural gas. During 2002, the Company's Gulf Coast producing wells represented only 4% of the Company's total producing well count, but produced 21% of the Company's total gas production for the year. Net daily production from these properties is 187 Bbls of oil and 5,245 Mcf of natural gas or 1,061 Boe to the Company's interests from 5wells. The Company's leasehold position includes 6,000 net developed and 18,000 net undeveloped acres representing 1% and 3% of the Company's total leasehold respectively. From a combined total of 95 square miles of proprietary 3-D data, 22 development and 21 exploratory locations have been identified for drilling on these projects. PEBBLE BEACH/LUBY. The Pebble Beach/Luby projects target the prolific Frio and Vicksburg sands underlying and surrounding the Clara Driscoll and Luby fields in Nueces County, Texas. These sandstone reservoirs produce on structures readily defined by seismic and remain largely untested below the existing producing reservoirs in the fields at depths ranging from 6,000 feet to 13,000 feet. At December 31, 2002, the Company's estimated proved reserves in the Pebble Beach/Luby fields totaled 2,064 MMcf or 3% of the Company's estimated proved reserves of natural gas. Net daily production during the twelve months ended December 31, 2002, averages 65 Bbls of oil and 2,723 Mcf of gas, or 519 Boe to the Company's interests. The Company owns 23,000 gross and 19,000 net acres and has acquired 95 square miles of proprietary 3-D seismic data in these two projects. From the proprietary 3-D data, the Company has identified 22 development and 13 exploratory locations for drilling. During 2002, the Company drilled 9 wells with 8 being completed as producing wells and 1 dry hole. In 2003, the Company will continue its development and expects to drill 13 additional wells in the Pebble Beach/Luby projects. The Company also expects to acquire additional leasehold and approximately 60 square miles of new proprietary 3-D data in selected projects as part of its ongoing expansion in South Texas. 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 111.1 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 controls 2,000 gross and 1,000 net acres in the project and owns 35 square miles of proprietary 3-D seismic covering the property through an agreement with a third party. Under the agreement, the third party had to pay 100% of costs for acquiring 3-D seismic and drill five wells, carrying the Company for 16% working interest at no cost, to earn 50% interest in the Jefferson Island project. During 2000, the third party completed its 3-D seismic and drilling obligation and earned 50% of the project. Out of the five wells drilled by the third party, two are commercial wells, two non-commercials and one was a dry hole. With the third party's seismic and drilling obligations fulfilled, the Company regained control of drilling operations and drilled one exploratory well in 2001 seeking higher reserve potential. The exploratory well was successful and penetrated 180 feet of pay in multiple sands underlying a 3-D imaged salt overhang along the flank of the salt dome complex. The discovery is quite significant in that it confirmed our ability to image the salt and encounter pay in sand reservoirs not previously known to produce in the field. The Company has identified 5 additional exploratory drilling locations and plans to drill at least one in 2003. GULF OF MEXICO. In July 1999 the Company elected to expand its drilling program into the shallow waters of the Gulf of Mexico ("GOM") though a joint venture arrangement with Challenger Minerals, Inc. This was part of the Company's ongoing strategy to build its opportunity base of high rate of return, natural gas reserves in the Gulf Coast region. The expansion into the GOM has proven successful and as of December 31, 2002, the Company has participated in 15 wells that have resulted in seven producers, seven dry holes, and one well has been plugged. The Company plans to continue its activity in the GOM as a non-operator, restricting its risked investments to approximately $750,000 per project. The Company currently has 2 potential wells in inventory for 2003. 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, --------------------------------------------------------- NET PRODUCTION DATA: 2000 2001 2002 ------------------ ----------------- ----------------- Oil and condensate (MBbl) 3,360 3,489 3,810 Natural gas (MMcf) 7,939 8,411 9,229 Total (MBoe) 4,684 4,893 5,352 UNIT ECONOMICS Average sales price per Bbl (w/o hedges) $29.02 $23.79 $24.05 Average sales price per Bbl (with hedges) $27.41 $23.87 $22.56 Average sales price per Mcf $2.91 $3.41 $2.46 Average sales price per Boe (w/o hedges) $25.75 $22.82 $21.36 Average sales price per Boe (with hedges) $24.65 $22.92 $20.32 Lifting cost per Boe (1) $6.36 $7.52 $6.75 DD&A expense per Boe (1) $3.71 $4.90 $5.04 General and administrative expense per Boe (2) $1.52 $1.79 $1.99 Gross Margin $13.06 $8.71 $6.54 - --------------- (1) Related to oil and gas producing properties. (2) Related to oil and gas producing properties, net of operating overhead income.
PRODUCING WELLS The following table sets forth the number of productive wells, exclusive of injection wells and water wells, as of December 31, 2002. In the table "gross" refers to total wells in which the Company had a working interest and "net" refers to gross wells multiplied by our working interest.
OIL WELLS GAS WELLS TOTAL WELLS ------------------------------------- -------------------------------- ------------------------------- ROCKY MOUNTAIN GROSS NET GROSS NET GROSS NET ------------------- ----------------- ---------------- --------------- ---------------- -------------- Williston Basin 381 328 0 0 381 328 Big Horn Basin 328 287 1 1 329 288 ------------------- ----------------- ---------------- --------------- ---------------- --------------- Total ROCKY MOUNTAIN 709 615 1 1 710 616 MID-CONTINENT Anadarko Basin 370 206 285 83 655 289 Texas Panhandle 19 12 15 5 34 17 Illinois Basin 843 612 37 34 880 646 Black Warrior Basin 0 0 5 4 5 4 ------------------- ----------------- ---------------- --------------- ---------------- --------------- Total MID-CONTINENT 1,232 830 342 126 1,574 956 GULF COAST Louisiana Onshore 2 1 7 3 9 4 Luby 33 33 31 31 64 64 Offshore 0 0 7 1 7 1 Pebble Beach 8 6 11 7 19 13 Texas Onshore 0 0 2 2 2 2 ------------------- ----------------- ---------------- --------------- ---------------- --------------- Total GULF COAST 43 40 58 43 101 84 TOTAL 1,984 1,485 401 171 2,385 1,656 =================== ================= ================ =============== ================ ===============
ACREAGE The following table sets forth the Company's developed and undeveloped gross and net leasehold acreage as of December 31, 2002. In the table "gross" refers to total acres in which the Company had a working interest and "net" refers to gross acres multiplied by our working interest.
Developed Undeveloped Total ----------------------------- ----------------------------- ---------------------------- Rocky Mountains Gross Net Gross Net Gross Net ------------- -------------- -------------- ------------- ------------- ------------- Williston Basin 163,470 143,915 249,198 207,644 412,668 351,559 Big Horn Basin 30,569 29,358 69,788 66,884 100,357 96,242 Canada 0 0 17,117 17,117 17,117 17,117 New Mexico 0 0 560 560 560 560 ------------- -------------- -------------- ------------- ------------- ------------- Total Rocky Mountains 194,039 173,273 336,663 292,205 530,702 465,478 Mid-Continent Anadarko Basin 119,879 68,110 30,870 26,953 150,749 95,063 Black Warrior Basin 1,530 1,102 37,820 24,380 39,350 25,482 Illinois Basin 39,809 30,384 1,905 1,905 41,714 32,289 Other 0 0 8,715 8,714 8,715 8,714 ------------- -------------- -------------- ------------- ------------- ------------- Total Mid-Continent 161,218 99,596 79,310 61,952 240,528 161,548 Gulf Coast 15,515 5,872 29,659 17,893 45,174 23,765 ------------- -------------- -------------- ------------- ------------- ------------- Total Gulf Coast 15,515 5,872 29,659 17,893 45,174 23,765 Grand Total Acreage 370,772 278,741 445,632 372,050 816,404 650,791 ============= ============== ============== ============= ============= =============
DRILLING ACTIVITIES The following table sets forth the Company's drilling activity on its properties for the periods indicated. In the table "gross" refers to total wells in which the Company had a working interest and "net" refers to gross wells multiplied by our working interest.
YEAR ENDED DECEMBER 31, --------------------------------------------------------------------------------------------- 2000 2001 2002 ------------------------------ ------------------------------- ------------------------------ DEVELOPMENT WELLS: GROSS NET GROSS NET GROSS NET -------------- --------------- --------------- --------------- -------------- --------------- Productive 23 19.4 32 25.4 52 46.4 Non-productive 3 2.9 15 7.2 5 4.3 -------------- --------------- --------------- --------------- -------------- --------------- Total 26 22.3 47 32.6 57 50.7 ============== =============== =============== =============== ============== =============== EXPLORATORY WELLS: Productive 15 9.3 11 5.7 16 12.8 Non-productive 7 3.0 10 5.5 9 6.2 -------------- --------------- --------------- --------------- -------------- --------------- Total 22 12.3 21 11.2 25 19.0 ============== =============== =============== =============== ============== ===============
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 83% of the PV-10 at December 31, 2000, 97.6% of the PV-10 at December 31, 2001, and 89% of the PV-10 at December 31, 2002. The Company prepared the reserve and present value data on all other properties.
(Dollars in thousands) December 31, --------------------------------------------------------- Proved developed reserves: 2000 2001 2002 ------------------ ------------------- ------------------ Oil (MBbl) 33,173 31,325 33,626 Natural Gas (MMcf) 58,438 56,647 69,273 Total (MBoe) 42,913 40,766 45,172 Proved undeveloped reserves: Oil (MBbl) 2,091 28,406 29,655 Natural Gas (MMcf) 1,435 (4,381) 674 Total (MBoe) 2,330 27,676 29,767 Total proved reserves: Oil (MBbl) 35,264 59,731 63,281 Natural Gas (MMcf) 59,873 52,267 69,947 Total (MBoe) 45,243 68,442 74,939 PV-10 (1) $491,799 $308,604 $633,397 - --------------- (1) PV-10 represents the present value of estimated future net cash flows before income tax discounted at 10%. 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, 2000, 2001 and 2002, were $26.80 per Bbl of oil and $9.78 per Mcf of natural gas, $18.67 per Bbl of oil and $1.96 per Mcf of natural gas and $29.04 per Bbl of oil and $3.33 per Mcf of natural gas, respectively.
Estimated quantities of proved reserves and future net cash flows there from 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 Continental Gas Inc. ("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 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 sold. 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 are 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, 2002, purchases of the Company's natural gas production by ONEOK Field Services accounted for 23% 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 61% 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 price risk management strategies to fix 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 hedging partner pays the Company. 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. During the second quarter of 2002, the Company discontinued crude oil trading contracts. ITEM 3. LEGAL PROCEEDINGS From time to time, the Company is party to litigation or other legal proceedings 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. 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. The Company authorized an approximate 293:1 stock split during 2000. As a result all amounts are presented retroactive to account for the split. As of March 28, 2003, there were three record holders of the Company's common stock. The Company issued no equity securities during 2002. During 2000, the Company established a Stock Option Plan with 1,020,000 shares available, of which options to purchase an aggregate of 172,000 shares have been granted. 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 operations and other financial data for the years ended December 31, 1998, 1999, 2000, 2001 and 2002, and the balance sheet data as of December 31, 1998, 1999, 2000, 2001 and 2002, have been derived from, and should be reviewed in conjunction with, the consolidated financial statements of the Company, and the notes thereto. Ernst and Young LLP audited our financial statements for 2002 and Arthur Andersen LLP audited the remaining years. The balance sheets as of December 31, 2001, and 2002, and the statements of operations for the years ended December 31, 2000, 2001 and 2002, 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. Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings.
Statement of Operating Data: YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------ (dollars in thousands) 1998 1999 2000 2001 2002 -------------- ------------- ------------- --------------- --------------- Revenue: Oil and Gas Sales $ 60,162 $ 65,949 $ 115,478 $ 112,170 $ 108,752 Crude Oil Marketing Income 232,216 241,630 279,834 245,872 153,547 Change in Derivative Fair Value 0 0 0 0 (1,455) Gathering, Marketing and Processing 17,701 21,563 32,758 44,988 33,708 Oil and Gas Service Operations 4,003 3,368 5,760 6,047 5,739 -------------- ------------- ------------- --------------- --------------- Total Revenues 314,082 332,510 433,830 409,077 300,291 Operating Costs and Expenses: Production Expenses and Taxes 22,611 19,368 29,807 36,791 36,112 Exploration Expenses 5,468 3,191 9,965 15,863 10,229 Crude Oil Marketing Expense. 228,797 236,135 278,809 245,003 152,718 Gathering, Marketing and Processing 16,233 18,391 28,303 36,367 29,783 Oil and Gas Service Operations 3,664 3,420 5,582 5,294 6,462 Depreciation, Depletion and Amortization 30,198 19,549 19,552 27,731 31,380 Property Impairments 10,165 5,154 5,631 10,113 25,686 General and Administrative 6,098 4,540 7,142 8,753 10,713 -------------- ------------- ------------- --------------- --------------- Total Operating Costs and Expenses 323,234 309,748 384,791 385,915 303,083 Operating Income (Loss) (9,152) 22,762 49,039 23,162 (2,792) Interest Income 967 310 756 630 285 Interest Expense (12,826) (17,370) (16,514) (15,674) (18,401) Change in Accounting Principle (1) 0 (2,048) 0 0 0 Other Revenue (Expense), net 3,031 266 4,499 3,549 876 -------------- ------------- ------------- --------------- --------------- Total Other Income(Expense) (8,828) (18,842) (11,259) (11,495) (17,240) Net Income (Loss) $ (17,980) $ 3,920 $ 37,780 $ 11,667 $ (20,032) ============== ============= ============= =============== =============== OTHER FINANCIAL DATA: Adjusted EBITDA (2) $ 40,677 $ 49,184 $ 89,442 $ 81,048 $ 65,664 Net cash provided by operations 27,884 26,179 72,262 63,413 46,997 Net cash used in investing (114,743) (15,972) (44,246) (106,384) (113,295) Net cash provided by (used in)financing 101,376 (15,602) (31,287) 43,045 61,593 Capital expenditures (3) 95,474 57,530 51,911 111,023 113,447 RATIOS: Adjusted EBITDA to interest expense 3.2x 2.8x 5.4x 5.2x 3.6x Total funded debt to Adjusted EBITDA (4) 4.2x 3.5x 1.6x 2.2x 3.6x Earnings to fixed charges (5) N/A 1.2x 3.3x 1.7x N/A BALANCE SHEET DATA (AT PERIOD END): Cash and cash equivalents $ 15,817 $ 10,421 $ 7,151 $ 7,225 $ 2,520 Total assets 253,739 282,559 298,623 354,485 406,677 Long-term debt, including current maturities 167,637 170,637 140,350 183,395 247,105 Stockholder's equity 60,284 86,666 123,446 135,113 115,081 - ---------------- (1) Change in accounting principle represents the cumulative effect impact of adopting EITF 98-10 "Accounting for Energy Trading and Risk Management Activities." (2) Adjusted EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment of property 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. 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. (3) Capital expenditures include costs related to acquisitions of producing oil and gas properties and include the contribution of the Worland properties by the principal stockholder of $22.4 million during the year ended December 31, 1999, and the purchase of the assets of Farrar Oil Company and Har-Ken Oil Company for $33.7 million during the year ended December 31, 2001. Capital expenditures for 2002 included $47.2 million for Cedar Hill's development and $9.9 for capital leases. (4) Total funded debt to Adjusted EBITDA excludes capital leases of $11.9 million. (5) For purposes of computing the ratio of earnings to fixed charges, earnings are computed as income from continuing operations before 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 and 2002, earnings were insufficient to cover fixed charges by $18.0 million and $20.0 million, respectively.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CRITICAL ACCOUNTING POLICIES AND PRACTICES The use of estimates is necessary in the preparation of the Company's consolidated financial statements. The circumstances that make these judgments difficult, subjective and complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. The use of estimates and assumptions affects the reported amounts of assets and liabilities. Such estimates and assumptions also affect the disclosure of legal reserves, abandonment reserves, oil and gas reserves and other contingent assets and liabilities at the date of the consolidated financial statements, as well as amounts of revenues and expenses recognized during the reporting period. Of the estimates and assumptions that affect reported results, estimates of the Company's oil and gas reserves are the most significant. Changes in oil and gas reserves estimates impact the Company's calculation of depletion and abandonment expense and is critical in the Company's assessment of asset impairments. Management believes it is necessary to understand the Company's significant accounting policies, "Item 8. Financial Statements and Supplementary Data-Note 1-Summary of Significant Accounting Policies" of this form 10-K, in order to understand the Company's financial condition, changes in 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 consolidated 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 produces. The Company produced more oil and gas in 2002 than in 2001. Average wellhead prices during 2002 were $22.90 per Bbl of oil and $2.46 per Mcf of natural gas compared to $24.05 per Bbl of oil and $3.41 per Mcf of natural gas during 2001 The Company uses the successful efforts method of accounting for its investment in oil and gas properties. Under the successful efforts method of accounting, 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 writedown for impairment of the carrying value of oil and gas properties. Once incurred, a writedown of an oil and gas property 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 periods indicated:
December 31, --------------------------------------- (Dollars in thousands, except price data) 2000 2001 2002 - ---------------------------------------------- ----------- ------------ ------------ Revenues $ 433,830 $ 409,077 $ 300,291 Operating expenses 384,791 385,915 303,083 Non-Operating income (expense) (11,259) (11,495) (17,240) Net income (loss) 37,780 11,667 (20,032) Adjusted EBITDA (1) 89,442 81,048 65,664 Production Volumes: Oil and condensate (MBbl) 3,360 3,489 3,810 Natural gas (MMcf) 7,939 8,411 9,229 Oil equivalents (MBoe) 4,681 4,893 5,352 Average Prices: Oil and condensate, with hedges ($/Bbl) $ 27.41 $ 23.87 $ 22.56 Natural gas ($/Mcf) $ 2.91 $ 3.41 $ 2.46 Oil equivalents, with hedges ($/Boe) $ 24.65 $ 22.92 $ 20.32 - --------------- (1) Adjusted EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment of property 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. 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.
YEAR ENDED DECEMBER 31, 2002, COMPARED TO YEAR ENDED DECEMBER 31, 2001 Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings. REVENUES OIL AND GAS SALES Our oil and gas sales revenue for 2002 decreased $3.4 million, or 3%, to $108.8 million from $112.2 million in 2001 due primarily to a loss on hedging activity of $4.9 million in 2002 and a decrease in gas prices. Gas prices decreased $0.95/Mcf, or 28%, from an average of $3.41/Mcf in 2001 to $2.46/Mcf in 2002. CRUDE OIL MARKETING We discontinued our crude oil trading activities effective May 2002. Prior to May 2002, we entered into third party contracts to purchase and resell crude oil. Although we no longer enter into third party contracts, we did continue to repurchase our physical production from the Rockies and resell equivalent barrels at Cushing to take advantage of better pricing and to reduce our credit exposure from sales to our first purchaser. We present sales and purchases of our production from the Rockies as crude oil marketing income and crude oil marketing expense, respectively. For the year to date period ended December 31, 2002, we recognized revenue of $153.5 million on crude oil marketing activities from January 2002 thru May 2002, compared to income of $245.9 million for the twelve months ended December 31, 2001 GATHERING, MARKETING AND PROCESSING Our 2002 gathering, marketing and processing revenues decreased $11.3 million, or 25%, to $33.7 million compared to $45.0 million for 2001. Of this decrease, $10.3 million was attributable to operations from the Eagle Chief Plant in Oklahoma, $1.1 million from the south Texas gathering systems, Driscoll and Arend, $0.8 million was from the Matli, Badlands and Worland gas gathering systems. These decreases were offset by increases in the remaining gas gathering systems, including an increase from the North Enid Plant in Oklahoma of $1.9 million. The decreases were due to lower natural gas and natural gas liquids prices in 2002. OIL AND GAS SERVICE OPERATIONS Our oil and gas service operations revenues decreased $0.3 million, or 5%, to $5.7 million in 2002 from $6.0 million in 2001 due primarily to lower volumes of reclaimed oil sales from our central treating unit. COSTS AND EXPENSES PRODUCTION EXPENSES AND TAXES Our production expenses and taxes were $36.1 million for 2002, a decrease of $0.7 million, or 2%, over the 2001 expenses of $36.8 million, primarily as a result of decreased energy costs and taxes of $1.8 million offset by increases in all other areas of direct costs associated with the Company's operations. EXPLORATION EXPENSE Our exploration expenses decreased $5.6 million, or 35%, to $10.2 million in 2002 from $15.8 million in 2001. The decrease was attributable to a $6.9 million decrease in dry hole expenses, offset by a $1.3 million increase in seismic and geological and geophysical expenses along with a $0.9 million increase in other expenses. CRUDE OIL MARKETING EXPENSE We discontinued our crude oil trading activities effective May 2002. Prior to May 2002, we entered into third party contracts to purchase and resell crude oil. Although we no longer enter into third party contracts, we did continue to repurchase our physical production from the Rockies and resell equivalent barrels at Cushing to take advantage of better pricing and to reduce our credit exposure from sales to our first purchaser. We present sales and purchases of our production from the Rockies as crude oil marketing income and crude oil marketing expense, respectively. For the year ended December 31, 2002, we recognized an expense of $152.7 million on crude oil marketing activities from January 2002 thru May 2002, compared to an expense of $245.0 million for the twelve months ended December 31, 2001 GATHERING, MARKETING AND PROCESSING Our gathering, marketing and processing expense for 2002 was $29.8 million, a decrease of $6.6 million, or 18%, from the $36.4 million incurred in 2001. Of this decrease, $8.3 million was attributable to the Eagle Chief Plant in Oklahoma which was offset by increases of $1.8 million from the North Enid Plant in Oklahoma and $0.8 million from the Arend gathering system in Texas. The decrease is a result of lower natural gas and natural gas liquids prices in 2002. OIL AND GAS SERVICE OPERATIONS Our oil and gas service operations expenses increased by $1.2 million, or 22%, to $6.5 million in 2002 from $5.3 million in 2001. The increase was due to the cost of purchasing and treating reclaimed oil for resale by $0.4 million, salaries increased $0.3 million and general repairs and maintenance made up the difference of $0.4 million. DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") For the year ended December 31, 2002, total DD&A expense was $31.3 million, a $3.6 million, or 13%, increase over the 2001 expense of $27.7 million. The increase was due to the DD&A associated with the Farrar assets acquired in July 2001, which were depreciated for a full year in 2002 and increased depreciation by $0.7 million. Depreciable and depletable assets increased $86.2 million from 2001 to 2002, which also increased DD&A expense. PROPERTY IMPAIRMENTS During 2002, we recorded property impairments of $25.7 million, compared to $10.1 million in 2001, a $15.6 million, or 154%, increase from last year. The majority of this impairment was related to our Bepco acquisition in the Worland Field. The Bepco acquisition included 466 proved undeveloped ("PUD") locations with a PV-10 value of $145.5 million. We allocated $26.7 million to these potential locations as part of the acquisition price. We have not developed any of the identified PUD locations during the past 4-1/2 years due to capital constraints imposed by our development of the Cedar Hills Field. A recent review of the PUD valuation made by our reservoir-engineering department of the original Ryder Scott report indicates that their analysis of reserve potential was accurate for the up-dip portion of the field, but potentially not applicable to all identified PUD locations. We have initiated a detailed review of the PUD locations by a consulting firm and expect to have a report during the third quarter of 2003. This review will involve geostatistical analysis of all available data and development of a neural network correlation to predict well performance. Economic analysis of specific locations and subsequent recommendation for drilling will follow this study. We may be required to write-down the carrying value of our 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. We recorded a $5.3 million FASB 121 write-down in 2001 and a $2.3 million FASB 121 write-down in 2002. GENERAL AND ADMINISTRATIVE ("G&A") Our G & A expense for 2002 was $10.7 million, an increase of $1.9 million, or 22%, from G&A expenses for 2001 of $8.8 million, primarily attributable to increased salaries and employment expenses due to an increased number of employees in 2002. INTEREST INCOME Our interest income for 2002 was $0.3 million compared to $0.6 million for 2001, a decrease of $0.3 million or 50%. The decrease in the 2002 period is attributable to lower interest rates and levels of cash invested during 2002. INTEREST EXPENSE Our interest expense for 2002 was $18.4 million, an increase of $2.7 million or 17% from $15.7 million in 2002. The increase in the 2002 expense was the additional interest paid on our credit facility due to higher average debt balances outstanding. OTHER INCOME Our other income decreased $2.6 million or 75%, to $0.9 million for the year ended December 31, 2002, from $3.5 million for 2001. Other income in 2001 reflects a gain on our sale of 62 uneconomical wells for $3.4 million, an extraordinary gain of $0.1 million on the repurchase of $3.0 million of our senior notes in 2001, and a gain of $0.3 million on the sale of miscellaneous assets in 2002. NET INCOME Our net loss for 2002 was $20.0 million, a decrease of $31.7 million, compared to net income of $11.7 million in 2001. This decrease reflects, among other items, the lower gas prices, which created a decrease in gas revenues of $8.0 million, an increase in DD&A expense and property impairments of $18.6 million, a $4.5 million decrease in gathering, marketing and processing margins, an increase in interest expense of $2.1 million, and a decrease in other income of $2.6 million. YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000 Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. These reclassifications do not affect our net income. OIL AND GAS SALES Our oil and gas sales revenues for 2001 decreased $3.3 million, or 3%, to $112.2 million from $115.5 million in 2000 due primarily to a decrease of $3.54 per barrel or 13% in oil prices from an average of $27.41 per barrel in 2000 to $23.87 per barrel in 2001. This decrease in oil prices was offset by an increase of $0.50 per Mcf or 17%, in average gas sales price from an average of $2.91 per Mcf in 2000 to $3.41 per Mcf in 2001. CRUDE OIL MARKETING We recognized a decrease in revenues on crude oil purchased for resale for 2001 of $34.0 million, or 12%, to $245.8 million from $279.8 million for 2000. Total volumes decreased approximately 1.1 million barrels along with the decrease in oil prices resulted in the decrease in crude oil marketing revenues. GATHERING, MARKETING AND PROCESSING Our 2001 gathering, marketing and processing revenues increased $12.2 million, or 37%, to $45.0 million compared to $32.8 for 2000. Of this increase, $5.3 million was attributable to operations from our south Texas gathering systems, $2.2 million was attributable to our Eagle Chief Plant in Oklahoma, and $1.5 million was attributable to our Matli gas gathering system in Oklahoma. The balance of the increase was due to an increase in gas prices. These increases were offset by our sale of the Rattlesnake and Enterprise gathering systems in January 2000. OIL AND GAS SERVICE OPERATIONS Our oil and gas service operations revenues increased 5% to $6.0 million in 2001 from $5.8 million in 2000. COSTS AND EXPENSES PRODUCTION EXPENSES AND TAXES Our production expenses and taxes were $36.8 million for 2001, a $7.0 million or 23% increase over the 2000 expenses of $29.8 million, primarily as a result of increased production volumes and energy costs. The increase was seen in all areas of direct costs associated with our operations, except taxes. Taxes decreased by approximately $1.0 million due to lower oil prices. EXPLORATION EXPENSE Our exploration expenses increased $5.9 million, or 59%, to $15.9 million in 2001 from $10.0 million in 2000. The increase was attributable to a $6.2 million increase in dry hole expenses and a $0.3 million decrease in seismic and geological/geophysical expenses. CRUDE OIL MARKETING Our expense for crude oil purchased for resale decreased $33.8 million, or 12%, to $245.0 million in 2001 from $278.8 million in 2000. This decrease was caused by decreased crude oil prices and reduced volumes of crude oil purchased. GATHERING, MARKETING AND PROCESSING Our gathering, marketing and processing expense for 2001 was $36.4 million, an increase of $8.1 million or 29% from the $28.3 million we incurred in 2000, due to increased system volumes resulting from the expansion of our existing facilities, the construction and operation of our new gathering and compression facilities in Texas, and higher natural gas and liquid prices. OIL AND GAS SERVICE OPERATIONS Our oil and gas service operations expenses decreased by $0.3 million or 5%, to $5.3 million in 2001 from $5.6 million in 2000. The decrease was primarily due to salt water disposal operating expenses. DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") For the year ended December 31, 2001, our total DD&A expense was $27.7 million, an $8.1 million or 42% increase over the 2000 expense of $19.6 million. In 2001, our lease and well DD&A was $24.0 million, an increase of $6.6 million from $17.4 million in 2000. The increase was primarily attributable to DD&A associated with the assets of Farrar Oil Company that we acquired in July 2001, and an increased FASB 121 write-down. We may be required to write-down the carrying value of our 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. We recorded a $1.7 million FASB 121 write-down in 2000 and a $5.3 million FASB 121 write-down in 2001. For 2001, DD&A expense on oil and gas properties amounted to $4.90 per Boe compared to $3.71 per Boe in 2000. GENERAL AND ADMINISTRATIVE ("G&A") Our G & A expense for 2001 was $8.8 million, an increase of $1.7 million, or 23%, from G&A expenses for 2000 of $7.1 million. The increase is primarily attributable to an increase in our employment expenses, legal costs, and our acquisition of the assets of Farrar Oil Company in July 2001. INTEREST INCOME Our interest income for 2001 was $0.6 million compared to $0.8 million for 2000, a decrease of $0.2 million or 25%. The decrease in the 2001 period was attributable to lower levels of cash invested during 2001. INTEREST EXPENSE Our interest expense for 2001 was $15.7 million, a decrease of $0.8 million, or 5%, from $16.5 million in 2000. The decrease in the 2001 expense was attributable primarily to the reduction in interest rates on borrowings under our credit facility in 2001 and the purchase and retirement of $3.0 million of our outstanding senior notes. OTHER INCOME Our other income decreased $1.0 million or 21%, to $3.5 million for the year ended December 31, 2001, from $4.5 million for 2000. This decrease reflects a $2.4 million gain on our sale of Arkoma Basin properties and an extraordinary gain of $0.7 million on our repurchase of senior notes during the 2000 period, compared to the sale of 62 uneconomical wells in 2001, which resulted in a gain of approximately $2.0 million and an extraordinary gain of $0.1 million on the repurchase of our senior notes in 2001. NET INCOME Our net income for 2001 was $11.7 million, a decrease of $26.1 million compared to $37.8 million in 2000. This decrease reflects among other items, lower oil prices which created a decrease in oil revenues of $8.8 million, an increase in DD&A and property impairments of $14.3 million, an increase in production expenses and taxes of $7.0 million and an increase in exploration expense of $4.1 million. LIQUIDITY AND CAPITAL ASSETS Our primary sources of liquidity have been cash flow from operating activities, financing provided by our credit facility and by our principal stockholder, and a private debt offering. Our cash requirements, other than for operations, are for acquisition, exploration, exploitation and development of oil and gas properties and debt service payments. CASH FLOW FROM OPERATIONS Our net cash provided by operating activities was $47.0 million for 2002, a decrease of 24% from the $62.1 million in 2001. The decrease was primarily due to the decrease in net income from operations, which was primarily attributable to the decreased gas prices and crude oil hedging loss. RESERVES AND EXPENDITURES We spent $111.0 million in 2001 and $113.4 million in 2002 on acquisitions, exploration, exploitation and development of oil and gas properties. Our total estimated proved reserves of natural gas increased from 52.3 Bcf at year-end 2001 to 69.9 Bcf at December 31, 2002, and our estimated total proved oil reserves increased from 59.7 million barrels at year-end 2001 to 63.3 million barrels at December 31, 2002. In 2002, we sold reserves estimated to contain approximately 12,000 barrels. FINANCING Our long-term debt, including current portion, was $183.4 million at December 31, 2001, and $247.1 million at December 31, 2002. The $63.7 million, or 35%, increase was primarily attributable to a $51.8 million increase in our bank debt. We used the majority of the proceeds of our 2002 borrowings for exploration and development of the Cedar Hills Field. CREDIT FACILITY We had $108.0 million outstanding debt balance under our credit facility at December 31, 2002. The effective rate of interest under the credit facility was 4.8% at December 31, 2001 and 4.37% at December 31, 2002. Our credit facility, which matures March 28, 2005, charges interest based on a rate per annum equal to the rate at which eurodollar deposits for one, two, three or six months are offered by the lead bank plus an applicable margin ranging from 150 to 250 basis points or the lead bank's reference rate plus an applicable margin ranging from 25 to 50 basis points. At December 31, 2002, the borrowing base of our credit facility was $140.0 million. The borrowing base is re-determined semi-annually. Between December 31, 2002 and March 28, 2003, we have drawn $18.5 million on our line of credit and currently have $126.5 million of outstanding debt on our line of credit. SENIOR NOTES On July 24, 1998, we issued $150.0 million of our 10 1/4% Senior Subordinated Notes due August 1, 2008, in a private placement. Interest on the senior notes is payable semi annually on each February 1 and August 1. In connection with the issuance of the senior notes, we incurred debt issuance costs of approximately $4.7 million, which we have capitalized as other assets and amortize on a straight-line basis over the life of the senior notes. In May 1998 we entered into a forward interest rate swap contract to hedge exposure to changes in prevailing interest rates on our senior notes. Due to changes in Treasury note rates, we paid $3.9 million to settle the forward interest rate swap contract. This payment resulted in an increase of approximately 0.5% to our effective interest rate, or an increase of approximately $0.4 million per year, over the term of the senior notes. During 2000, we repurchased $19.9 million principal amount of our senior notes at a cost of $18.3 million. We wrote off $0.9 million of the issuance costs associated with the repurchased senior notes. During 2001, we repurchased $3.0 million principal amount of our senior notes at a cost of $2.7 million. We wrote off $0.1 million of the issuance costs associated with the repurchased senior notes. CAPITAL EXPENDITURES In 2002, we incurred $113.4 million of capital expenditures, exclusive of acquisitions. We will initiate, on a priority basis, as many projects as cash flow allows. We anticipate that we will initiate approximately 194 projects in 2003 for projected capital expenditures of $105.9 million. We expect to fund our 2003 capital budget of $105.9 million through cash flow from operations and our credit facility. STOCKHOLDER DISTRIBUTION During 2002, we paid no dividends to our stockholders. The terms of the indenture and our credit facility restrict our ability to pay dividends. However, we are permitted to pay dividends to our stockholders in an amount sufficient to cover the taxes on the taxable income passed through to the stockholders. HEDGING From time to time, we and our subsidiaries utilize energy derivative contracts to hedge the price or basis risk associated with the specifically identified purchase or sales contracts, oil and gas production or operational needs. Prior to January 1, 2001, we accounted for changes in the market value of derivative instruments used for hedging as a deferred gain or loss until the production month of the hedged transaction, at which time the gain or loss on the derivative instruments was recognized in earnings. Effective January 1, 2001, we account for derivative instruments in accordance with SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." The specific accounting treatment for changes in the market value of the derivative instruments used in hedging activities is determined based on the designation of the derivative instruments as either a cash flow, fair value, or foreign currency exposure hedge, and effectiveness of the derivative instruments. Additionally, in the normal course of business, we will enter into fixed price forward sales contracts related to our oil and gas production to reduce our sensitivity to oil and gas price volatility. We deem forward sales contracts that will result in physical delivery of our production to be in the normal course of our business and we do not account for them as derivatives. In connection with our offering of senior notes, we entered into an interest rate hedge on which we experienced a $3.9 million loss. This loss will result in an effective increase of approximately 0.5% in our interest costs on the senior notes. OTHER We follow the "sales method" of accounting for our gas revenue, whereby we recognize sales revenue on gas sold, regardless of whether the sales are proportionate to our ownership in the gas produced. We recognize a liability to the extent that we have a net imbalance in excess of our share of the reserves in the underlying properties. Historically, our aggregate imbalance positions have been immaterial. We believe that any future periodic settlements of gas imbalances will have little impact on our liquidity. We sold a number of our non-strategic oil and gas properties and other properties over the past three years, recognizing pretax gains of approximately $3.7 million in 2000, $3.5 million in 2001, and $0.2million in 2002 respectively. The aggregate amount of oil and gas reserves associated with these dispositions was 290 MBbls of oil and 4,913 MMcf of natural gas. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to market risk in the normal course of our business operations. Due to the volatility of oil and gas prices, we, from time to time, have entered into financial contracts to hedge oil and gas prices and may do so in the future as a means of controlling our exposure to price changes. Most of our financial contracts settle against either a NYMEX based price or a fixed price. DERIVATIVES The risk management process we established is designed to measure both quantitative and qualitative risks in our businesses. We are exposed to market risk, including changes in interest rates and certain commodity prices. To manage the volatility relating to these exposures, periodically we enter into various derivative transactions pursuant to our policies on hedging practices. Derivative positions are monitored using techniques such as mark-to-market valuation and value-at-risk and sensitivity analysis. We had a derivative contract in place at December 31, 2002, which is being marked to market under SFAS No. 133 with changes in fair value being recorded in earnings as such contract does not qualify for special hedge accounting nor does such contract meet the criteria to be considered in the normal course of business. Such contract provides for a fixed price of $24.25 per barrel on 360,000 barrels of crude oil through December 2003 when market prices exceed $19.00 per barrel. However, if the average NYMEX spot crude oil price is $19.00 per barrel or less, no payment is required of the counterparty. If NYMEX spot crude oil prices during the month average more than $24.25 per barrel, we pay the excess to the counterparty. As of December 31, 2002, we have recorded a net unrealized loss of $2.1 million. COMMODITY PRICE EXPOSURE The market risk inherent in our market risk sensitive instruments and positions is the potential loss in value arising from adverse changes in our commodity prices. The prices of crude oil, natural gas, and natural gas liquids are subject to fluctuations resulting from changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we may hedge (through the utilization of derivatives) a portion of our production and sale contracts. Because the commodities covered by these derivatives are substantially the same commodities that we buy and sell in the physical market, no special studies other than monitoring the degree of correlation between the derivative and cash markets are deemed necessary. A sensitivity analysis has been prepared to estimate the price exposure to the market risk of our crude oil, natural gas and natural gas liquids commodity positions. Our daily net commodity position consists of crude inventories, commodity purchase and sales contracts and derivative commodity instruments. The fair value of such position is a summation of the fair values calculated for each commodity by valuing each net position at quoted futures prices. Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in such prices over the next 12 months. Based on this analysis, we have no significant market risk related to our crude trading or hedging portfolios. During the fourth quarter of 2002, we entered into forward fixed price sales contracts in accordance with our hedging policy, to mitigate its exposure to the price volatility associated with its crude oil production. As of December 31, 2002, we had entered into financial contracts covering the notational volumes set forth in the following tables for the periods indicated: Time Period Barrels per Month Price per Barrel ----------- ----------------- ---------------- 01/03-03/03 60,000 $21.98 01/03-06/03 30,000 $24.01 01/03-01/04 30,000 $24.01 01/03-12/03 30,000 $25.08 01/03-12/03 30,000 $24.85 Each month the contractual price per barrel is compared to average NYMEX spot crude oil price. When the contractual price is greater than the NYMEX price, we receive an amount equal to the difference multiplied by the notational volume. When the contractual price is less than the NYMEX price, we pay an amount equal to the difference multiplied by the notational volume. 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 Statement No. 133". As a result of SFAS No. 137, adoption of SFAS No. 133 was required for financial statements for periods beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities", which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and hedging activities. SFAS No. 133 sweeps in a broad population of transactions and changes the previous accounting definition of a derivative instrument. Under SFAS No. 133 every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. During 2000, we reviewed all our contracts to identify both freestanding and embedded derivatives that meet the criteria set forth in SFAS No. 133 and SFAS No. 138. We adopted the new standards effective January 1, 2001. We had no outstanding hedges or derivatives which had not been previously marked to market through its accounting for trading activity. As a result, the adoption of SFAS No. 133 and SFAS No. 138 had no significant impact. INTEREST RATE RISK Our exposure to changes in interest rates relates primarily to long-term debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. We might utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. The fair value of long-term debt is estimated based on quoted market prices and management's estimate of current rates available for similar issues. The following table itemizes our long-term debt maturities and the weighted-average interest rates by maturity date.
2002 Year-end (Dollars in thousands) 2003 2004 2005 2006 Thereafter Total Fair Value - ---------------------- ---- ---- ---- ---- ---------- ----- ---------- Fixed rate debt: Principal amount $0 $0 $0 $0 $127,150 $127,150 $116,978 Weighted-average Interest rate N/A N/A N/A N/A 10.25% 10.25% Variable-rate debt: Principal amount $0 $0 $108,000 $0 $0 $0 $108,000 Weighted-average Interest rate 0% 0% 4.4% 0% 0% 4.4%
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Information concerning this Item begins on Page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Arthur Andersen LLP audited our financial statements for 2000 and 2001. As a result of Andersen's liquidation, we changed our auditors to Ernst and Young LLP on July 12, 2002. This change was reported in a current report on Form 8-K dated July 16, 2002. 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)(3)......... 57 Chairman of the Board of Directors, President, Chief Executive Officer and Director Jack Stark (1)(3).......... 48 Senior Vice President--Exploration and Director Jeff Hume (1)(3)........... 52 Senior Vice President-Resource Development Randy Moeder (1)(3)........ 42 President - Continental Gas, Inc. Roger Clement (1)(2)(4).... 58 Senior Vice President, Chief Financial Officer, Treasurer and Director Mark Monroe (2)(3)......... 48 Director Robert Kelley (2)(5)....... 57 Director H. R. Sanders (2)(4)....... 70 Director - ----------------- (1) Member of the Executive Committee (2) Member of the Audit Committee (3) Term expires in 2003 (4) Term expires in 2004 (5) Resigned as of 2/2003 HAROLD HAMM, L.L.M., has been President and Chief Executive Officer and a Director of the Company since its inception in 1967 and currently serves as Chairman of the Board. Mr. Hamm is a long-time Oklahoma Independent Petroleum Association board member and currently its Vice President of the Western Region. He is the founder and served as the Chairman of Save Domestic Oil, Inc. Currently, Mr. Hamm is the President of the National Stripper Well Association, serves on the Executive Boards of the Oklahoma Independent Petroleum Association and the Oklahoma Energy Explorers. JACK STARK joined the Company as Vice President of Exploration in June 1992 and was promoted to Senior Vice President and Director in May 1998. He holds a Masters degree in Geology from Colorado State University and has 24 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 became Senior Vice President of Resource Development of the Company in July 2002. He had been Vice President of Drilling Operations 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 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 Senior Vice President and General Counsel of the Company from May 1998 to August 2000 and was Vice President and General Counsel from November 1990 to April 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 and the Oklahoma and American Bar Associations. Mr. Moeder is also a Certified Public Accountant. ROGER CLEMENT became Vice President, Chief Financial Officer, Treasurer and a Director of the Company in March 1989 and was promoted to Senior Vice President in May 1998. He holds a Bachelor of Business Administration degree from the University of Oklahoma and is a Certified Public Accountant. Prior to joining the Company, Mr. Clement was a partner in the accounting firm of Hunter and Clement in Oklahoma City for 17 years. The firm provided accounting, tax, audit and consulting services for various industries. Mr. Clement's clients were primarily involved in oil and gas and real estate. He was also a 50% partner in a construction company from 1973 to 1984 that constructed residential real estate and small commercial properties. He is a member of the Oklahoma Independent Petroleum Association, the American Institute of Certified Public Accountants and the Oklahoma Society of Certified Public Accountants. MARK MONROE was the Chief Executive Officer and President of Louis Dreyfus Natural Gas prior to its merger with Dominion Resources in October 2001. Prior to the formation of Louis Dreyfus Natural Gas in 1990, he was the Chief Financial Officer of Bogert Oil Company. He currently serves as the President of the Oklahoma Independent Petroleum Association and is a Board member of the Oklahoma Energy Explorers. Previously Mr. Monroe served on the Domestic Petroleum Council and the Board of the Independent Petroleum Association of America. Mr. Monroe is a Certified Public Accountant and received his Bachelor of Business Administration degree from the University of Texas at Austin. ROBERT KELLEY served as Chairman of the Board of Noble Affiliates, Inc., from 1992 until he retired in 2000. Noble Affiliates, Inc. is an independent energy company with exploration and production operations throughout the United States, the Gulf of Mexico, and international operations in Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea, the North Sea, and Vietnam. Prior to October 2000 he also served as President and Chief Executive Officer of Noble Affiliates, Inc. and its three subsidiaries, Samedan Oil Corporation, Noble Gas Marketing, Inc., and Noble Trading, Inc. He is a Director of OG&E Energy Corporation, a public utility headquartered in Oklahoma; and Lone Star Technologies, Inc., a leading manufacturer of oilfield tubular goods also located in Texas. Mr. Kelley attended the University of Oklahoma and received a Bachelor of Business Administration degree and he is a Certified Public Accountant. Mr. Kelley resigned from the Board effective February 10, 2003, due to conflicts of interest with other exploration and production companies. H. R. SANDERS, JR. served as a Director of Devon Energy Corporation from 1981 through 2000. In addition, he held the position of Executive Vice President of Devon from 1981 until his retirement in 1997. Prior to joining Devon, Mr. Sanders served Republic Bank of Dallas, N.A. from 1970 to 1981 as the bank's Senior Vice President with direct responsibility for independent oil, gas and mining loans. Mr. Sanders is a former member of the Independent Petroleum Association of America, Texas Independent Producers and Royalty owners Association and Oklahoma Independent Petroleum Association. He currently is a Director on the Board of Torreador Resources Corporation and is also a past Director of Triton Energy Corporation. ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table
Other Annual Securities Underlying All Other Annual Compensation Compensation Option Compensation Compensation ------------------- ------------ --------------------- ------------ Name Year Salary Bonus (1) # of shares (2) (3) - --------------- ---- --------- --------- ------------- ------------------- ------------ Harold Hamm (4) 2002 $0 $0 $0 0 $0 2001 $0 $0 $0 0 $0 2000 $500,000 $0 $0 0 $0 Jack Stark 2002 $161,512 $36,651 $0 8,000 $11,751 2001 $151,384 $17,996 $0 0 $11,244 2000 $139,456 $16,850 $0 32,000 $10,648 Jeff Hume 2002 $135,012 $20,450 $0 0 $22,501 2001 $125,580 $15,747 $0 0 $22,029 2000 $119,226 $15,820 $0 32,000 $21,711 Roger Clement 2002 $146,424 $32,841 $0 0 $8,544 2001 $127,500 $15,883 $0 0 $12,068 2000 $120,376 $15,406 $0 40,000 $7,558 Randy Moeder 2002 $132,619 $23,930 $0 0 $21,625 2001 $124,208 $25,197 $0 0 $21,217 2000 $121,335 $16,024 $0 25,000 $11,817 - --------------- (1) Represents the value of perquisites and other personal benefits in excess of the lesser of $50,000 or 10% of annual salary and bonus. For the years ended December 31, 2000, 2001 and 2002, the Company paid no other annual compensation to its named executive officers. (2) The Company adopted its 2000 Stock Option Plan effective October 1, 2000, and allocated a maximum of 1,020,000 shares of Common Stock to this plan. Effective October 1, 2000, the Company granted Incentive Stock Options to purchase 90,000 shares and Non-qualified Options to purchase 54,000 shares. Effective April 1, 2002, the Company granted Incentive Stock Options to purchase 13,000 shares and Non-qualified Options to purchase 5,000 shares. Effective July 1, 2002, the Company granted Incentive Stock Options to purchase 5,000 shares and Non-qualified Options to purchase 5,000 shares. (3) Represents contributions made by the Company to the accounts of executive officers under the Company's profit sharing plan and under the Company's nonqualified compensation plan. (4) Received no compensation during the calendar year 2001 and 2002.
2002 Year-End Option Value
- ------------------------------------------------------------------------------------------ Number of Securities Underlying Value of Unexercised In-the-Money Unexercised Options at 12/31/02(#) Options at 12/31/02($) Name Exercisable/Unexercisable Exercisable/Unexercisable (1) - ------------------------------------------------------------------------------------------ Jack Stark 16,000/24,000 $170,886/$250,154 Jeff Hume 16,000/16,000 $170,886/$142,874 Roger Clement 21,334/18,666 $246,516/$180,684 Randy Moeder 11,334/13,666 $104,709/$109,791 - --------------- (1) The value of unexercised in-the-money options at December 31, 2002, is computed as the product of the stock value at December 31, 2002, assumed to be $21.18 per share less the stock option exercise price, and the number of underlying securities at December 31, 2002.
Employment Agreements The Company does not have formal employment agreements with any of its senior management employees. Stock Option Plan The Company adopted its 2000 stock option plan to encourage its key employees by providing opportunities to participate in its ownership and future growth through the grant of incentive stock options and nonqualified stock options. The plan also permits the grant of options to the Company's directors. The plan is presently administered by the Company's Board of Directors. 2000 Stock Incentive Plan The Company adopted the 2000 stock incentive plan effective October 1, 2000. The maximum number of shares for which it may grant options under the plan is 1,020,000 shares of common stock, subject to adjustment in the event of any stock dividend, stock split, recapitalization, reorganization or certain defined change of control events. Shares subject to previously expired, canceled, forfeited or terminated options become available again for grants of options. The shares that the Company will issue under the plan will be newly issued shares. The Chairman of the Board of Directors determines the number of shares and other terms of each grant. Under its plan, the Company may grant either incentive stock options or nonqualified stock options. The price payable upon the exercise of an incentive stock option may not be less than 100% of the fair market value of the Company's common stock at the time of grant, or in the case of an incentive stock option granted to an employee owning stock possessing more than 10% of the total combined voting power of all classes of the Company's common stock, 110% of the fair market value on the date of grant. The Company may grant incentive stock options to an employee only to the extent that the aggregate exercise price of all such options under all of its plans becoming exercisable for the first time by the employee during any calendar year does not exceed $100,000. The Company may not grant a nonqualified stock option at an exercise price which is less than 50% of the fair market value of the Company's common stock on the date of grant. Each option that the Company has granted or will grant under the plan will expire on the date specified by the Company, but not more than ten years from the date of grant or, in the case of a 10% shareholder, not more than five years from the date of grant. Unless otherwise agreed, an incentive stock option will terminate not more than 90 days, or twelve months in the event of death or disability, after the optionee's termination of employment. An optionee may exercise an option by giving written notice to the Company, accompanied by full payment: o in cash or by check, bank draft or money order payable to the Company; o by delivering shares of the Company's common stock or other equity securities having a fair market value equal to the exercise price; or o a combination of the foregoing. Outstanding options become nonforfeitable and exercisable in full immediately prior to certain defined change of control events. Unless otherwise determined by the Company, outstanding options will terminate on the effective date of the Company's dissolution or liquidation. The plan may be terminated or amended by the Company at any time subject, in the case of certain amendments, to shareholder approval. If not earlier terminated, the plan expires on September 30, 2010. With certain exceptions, Section 162(m) of the Internal Revenue Code denies a deduction to publicly held corporations for compensation paid to certain executive officers in excess of $1.0 million per executive per taxable year (including any deduction with respect to the exercise of an option). An exception exists, however, for amounts received upon exercise of stock options pursuant to certain grandfathered plans. Options granted under the Company's plan are expected to satisfy this exception. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth certain information regarding the beneficial ownership of the Company's common stock as of March 28, 2003 held by: o each of the Company's directors who owns common stock, o each of the Company's executive officers who owns common stock, o each person known or believed by the Company to own beneficially 5% or more of the Company's common stock, and o all of the Company's directors and executive officers as a group Unless otherwise indicated, each person has sole voting and dispositive power with respect to such shares. The number of shares of common stock outstanding for each listed person includes any shares the individual has the right to acquire within 60 days of this prospectus. Shares of Ownership Name of Beneficial Owner Common Stock Percentage - ------------------------ ------------ ---------- Harold Hamm (1)(2) 13,037,328 90.7% Harold Hamm DST Trust 798,917 5.6% Harold Hamm HJ Trust 532,674 3.7% 302 North Independence Enid, Oklahoma 73702 All executive officers and directors as a group 13,037,328 90.7% (5 persons) - --------------- (1) Director (2) Executive officer 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 2002. 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 affiliated companies. 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 affiliated companies. The aggregate amounts paid by Continental to these affiliated companies during 2002 was $11.7 million and at December 31, 2002, the Company owed these companies approximately $0.9 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 unaffiliated parties. In addition, Harold Hamm and certain companies controlled by him own interests in wells operated by the Company. At December 31, 2002, the Company owed such persons an aggregate of $0.1 million, representing their shares of oil and gas production sold by the Company. During 2001, in its capacity as operator of certain oil and gas properties the Company began selling natural gas produced to a related party. During 2002, the Company sold natural gas valued at $1.24 million to this related party. During December 2002, the Company entered into a long-term lease agreement with a related party for $12.0 million. These lease arrangements were entered into at rates equal to, or better than, could have been negotiated with a third party. OFFICE LEASE. The Company leases office space under operating leases directly or indirectly from the principal stockholder and an affiliate of the principal stockholder. In 2002, the Company paid rents associated with these leases of approximately $421,000. The Company believes that the terms of its lease are no less favorable to the Company than those that 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 properties. At December 31, 2002, the aggregate unpaid balance owed to the Company by such officers and directors was $1,294, none of which was past due. 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 Auditors thereon are included on pages F-1 through F-20 of this Form 10-K. Report of Independent Auditors Copy of Report of Independent Public Accountants (Arthur Andersen LLP) Consolidated Balance Sheets as of December 31, 2001 and 2002 Consolidated Statement of Operations for the three years in the period ended December 31, 2002 Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2002 Consolidated Statement of Stockholder's Equity for the three years in the period ended December 31, 2002 Notes to the Consolidated Financial Statements 2. FINANCIAL STATEMENT SCHEDULES: None. 3. EXHIBITS: 2.1 Agreement and Plan of Recapitalization of Continental Resources, Inc. dated October 1, 2000. [2.1](4) 3.1 Amended and Restated Certificate of Incorporation of Continental Resources, Inc. [3.1](1) 3.2 Amended and Restated 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 April 21, 2000 between Continental Resources, Inc. and Continental Gas, Inc., as Borrowers and MidFirst Bank as Agent (the "Credit Agreement") [4.4] (3) 4.1.1 Form of Consolidated Revolving Note under the Credit Agreement [4.4] (3) 4.1.2 Second Amended and Restated Credit Agreement among Continental Resources, Inc., Continental Gas, Inc. and Continental Resources of Illinois, Inc., as Borrowers, and MidFirst Bank, dated July 9, 2001.[10.1](5) 4.1.3 Third Amended and Restated Credit Agreement among Continental Resources, Inc., Continental Gas, Inc. and Continental Resources of Illinois, Inc., as Borrowers, and MidFirst Bank, dated January 17, 2002. [4.13] (7) 4.1.4 Fourth Amended and Restated Credit Agreement dated March 28, 2002, among the Registrant, Union Bank of California, N. A., Guaranty Bank, FSB and Fortis Capital Corp. [10.1] (8) 4.2 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) 10.1 Unlimited Guaranty Agreement dated March 28, 2002 [10.2] (8) 10.2 Security Agreement dated March 28, 2002, between Registrant and Guaranty Bank, FSB, as Agent. [10.3] (8) 10.3 Stock Pledge Agreement dated March 28, 2002, between Registrant and Guaranty Bank, FSB, as Agent [10.4] (8) 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. [10.4](2) 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 [10.5](2) 10.6+ Continental Resources, Inc. 2000 Stock Option Plan. [10.6](4) 10.7+ Form of Incentive Stock Option Agreement. [10.7](4) 10.8+ Form of Non-Qualified Stock Option Agreement. [10.8](4) 10.9 Purchase and Sales Agreement between Farrar Oil Company and Har-Ken Oil Company, as Sellers, and Continental Resources of Illinois, Inc. as Purchaser, dated May 14, 2001.[2.1](5) 10.10 Collateral Assignment of Contracts dated March 28, 2002, between Registrant and Guaranty Bank, FSB, as Agent. [10.5] (8) 12.1 Statement re computation of ratio of debt to Adjusted EBITDA [12.1] (*) 12.2 Statement re computation of ratio of earning to fixed charges [12.2] (*) 12.3 Statement re computation of ratio of Adjusted EBITDA to interest expense [12.3] (*) 21.0 Subsidiaries of Registrant.[21](6) 99.1 Letter to the Securities and Exchange Commission dated March 28, 2002, regarding the audit of the Registrant's financial statements by Arthur Andersen LLP. [99.1] (7) - --------------- + Represents management compensatory plans or agreements. * 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 herein by reference. (2) Filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999. The exhibit number is indicated in brackets and is incorporated herein by reference. (3) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2000. The exhibit number is indicated in brackets and is incorporated herein by reference. (4) Filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal quarter ended December 31, 2000. The exhibit number is indicated in brackets and is incorporated herein by reference. (5) Filed as an exhibit to current report on Form 8-K dated July 18, 2001. The exhibit number is indicated in brackets and is incorporated herein by reference. (6) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2001. The exhibit number is indicated in brackets and is incorporated herein by reference. (7) Filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2001. The exhibit number is indicated in brackets and is incorporated herein by reference. (8) Filed as an exhibit to current report on Form 8-K dated April 11,2002. The exhibit number is indicated in brackets and is incorporated herein by reference. (b) REPORTS ON FORM 8-K None 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, 2003 CONTINENTAL RESOURCES, INC. By 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, 2003 President, Chief Executive Officer (principal executive officer) and Director ROGER V. CLEMENT Roger V. Clement Senior Vice President and March 28, 2003 Chief Financial Officer (principal financial officer and principal accounting officer), Treasurer, and Director JACK STARK Jack Stark Senior Vice President of Exploration March 28, 2003 and Director H. R. SANDERS, JR. H. R. Sanders, Jr. Director March 28, 2003 MARK MONROE Mark Monroe Director March 28, 2003 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. CERTIFICATIONS FOR FORM 10-K I, Harold Hamm, Chief Executive Officer, certify that: (1) I have reviewed this annual report on Form 10-K of Continental Resources, Inc. ("Registrant"); (2) Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; (3) Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; (4) The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and (c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluations as of the Evaluation Date; (5) The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls: and (6) The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. CONTINENTAL RESOURCES, INC. Date: March 28, 2003 By: HAROLD HAMM Harold Hamm Chief Executive Officer CERTIFICATIONS FOR FORM 10-K I, Roger V. Clement, Vice President and Chief Financial Officer, certify that: (1) I have reviewed this annual report on Form 10-K of Continental Resources, Inc. ("Registrant"); (2) Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; (3) Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; (4) The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and (c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluations as of the Evaluation Date; (5) The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls: and (6) The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. CONTINENTAL RESOURCES, INC. Date: March 28, 2003 By: ROGER V. CLEMENT Roger V. Clement Vice President and Chief Financial Officer INDEX OF FINANCIAL STATEMENTS Report of Independent Auditors.............................................F - 3 Copy of Report of Independent Public Accountants (Arthur Andersen LLP).....F - 3 Consolidated Balance Sheets as of December 31, 2001 and 2002...............F - 3 Consolidated Statements of Operations for the Years Ended December 31, 2000, 2001 and 2002...................................................F - 5 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2000, 2001 and 2002..................F - 6 Consolidated Statements of Cash Flows for the Years Ended December 31, 2000, 2001 and 2002...................................................F - 7 Notes to Consolidated Financial Statements.................................F - 8 REPORT OF INDEPENDENT AUDITORS To the Board of Directors of Continental Resources, Inc.: We have audited the accompanying consolidated balance sheet of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries as of December 31, 2002, and the related consolidated statements of operations, stockholders' equity and cash flows for the year then ended. 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 audit. The consolidated financial statements of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries as of December 31, 2001 and for each of the two years in the period then ended were audited by other auditors who ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated February 15, 2002. We conducted our audit 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 audit provided a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Continental Resources, Inc. and subsidiaries at December 31, 2002, and the consolidated results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States. ERNST & YOUNG LLP Oklahoma City, Oklahoma, March 14, 2003 INFORMATION REGARDING PREDECESSOR INDEPENDENT PUBLIC ACCOUNTANTS' REPORT The following report is a copy of a previously issued report by Arthur Andersen LLP ("Andersen"). The report has not been reissued by Andersen nor has Andersen consented to its inclusion in this annual report on Form 10-K. The Andersen report refers to the consolidated balance sheet as of December 31, 2000 and the consolidated statements of operations, stockholders' equity, and cash flows for the year ended December 31, 1999, which are no longer included in the accompanying 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, 2000 and 2001, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2001. 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, 2000 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. Oklahoma City, Oklahoma ARTHUR ANDERSEN LLP February 15, 2002 CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (dollars in thousands, except share data)
December 31, ------------------------------------ CURRENT ASSETS: 2001 2002 ------------------ ---------------- Cash $ 7,225 $ 2,520 Accounts receivable - Oil and gas sales 7,731 14,756 Joint interest and other, net 10,526 7,884 Inventories 6,321 6,700 Prepaid expenses 487 482 Fair value of derivative contracts - 628 ------------------ ---------------- Total current assets 32,290 32,970 PROPERTY AND EQUIPMENT, AT COST: Oil and gas properties, based on successful efforts accounting Producing properties 395,559 488,432 Nonproducing leaseholds 50,889 33,781 Gas gathering and processing facilities 28,176 33,113 Service properties, equipment and other 17,427 18,430 ------------------ ---------------- Total property and equipment 492,051 573,756 Less - Accumulated depreciation, depletion and amortization (174,720) (205,853) ------------------ ---------------- Net property and equipment 317,331 367,903 OTHER ASSETS: Debt issuance costs 4,851 5,796 Other assets 13 8 ------------------ ---------------- Total other assets 4,864 5,804 ------------------ ---------------- Total assets $ 354,485 $ 406,677 ================== ================
The accompanying notes are an integral part of these consolidated balance sheets. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (dollars in thousands, except share data)
December 31, --------------------------- CURRENT LIABILITIES: 2001 2002 ------------- ------------ Accounts payable $ 22,576 $ 26,665 Current debt 5,400 2,400 Revenues and royalties payable 3,404 5,299 Accrued liabilities and other 9,906 10,320 Fair Value of derivative contracts - 2,082 ------------- ------------ Total current liabilities 41,286 46,766 LONG-TERM DEBT, net of current portion 177,995 244,705 OTHER NONCURRENT LIABILITIES 91 125 STOCKHOLDERS' EQUITY: Preferred stock, $0.01 par value, 1,000,000 shares authorized, 0 shares issued and outstanding - - Common stock, $0.01 par value, 20,000,000 shares authorized, 14,368,919 shares issued and outstanding 144 144 Additional paid-in-capital 25,087 25,087 Retained earnings 109,882 89,850 ------------- ------------ Total stockholders' equity 135,113 115,081 ------------- ------------ Total liabilities and stockholders' equity $ 354,485 $ 406,677 ============= ============
The accompanying notes are an integral part of these consolidated balance sheets. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (dollars in thousands, except share data)
December 31, ---------------------------------------------- REVENUES: 2000 2001 2002 -------------- -------------- -------------- Oil and gas sales $ 115,478 $ 112,170 $ 108,752 Crude oil marketing income 279,834 245,872 153,547 Change in derivative fair value - - (1,455) Gathering, marketing and processing 32,758 44,988 33,708 Oil and gas service operations 5,760 6,047 5,739 -------------- -------------- -------------- Total revenues 433,830 409,077 300,291 OPERATING COSTS AND EXPENSES: Production expenses 20,301 28,406 28,383 Production taxes 9,506 8,385 7,729 Exploration expenses 9,965 15,863 10,229 Crude oil marketing expenses 278,809 245,003 152,718 Gathering, marketing and processing 28,303 36,367 29,783 Oil and gas service operations 5,582 5,294 6,462 Depreciation, depletion and amortization 19,552 27,731 31,380 Property impairments 5,631 10,113 25,686 General and administrative 7,142 8,753 10,713 -------------- -------------- -------------- Total operating costs and expenses 384,791 385,915 303,083 OPERATING INCOME (LOSS) 49,039 23,162 (2,792) OTHER INCOME (EXPENSES): Interest income 756 630 285 Interest expense (16,514) (15,674) (18,401) Other income, net 4,499 3,549 876 -------------- -------------- -------------- Total other income (expense) (11,259) (11,495) (17,240) -------------- -------------- -------------- NET INCOME (LOSS) $ 37,780 $ 11,667 $ (20,032) ============== ============== ============== EARNINGS PER COMMON SHARE: Basic $ 2.63 $ 0.81 $ (1.39) ============== ============== ============== Diluted $ 2.62 $ 0.81 $ (1.39) ============== ============== ==============
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, 2000, 2001 AND 2002 (dollars in thousands)
Additional Total Shares Common Paid-In Retained Stockholders' Outstanding Stock Capital Earning Equity ------------- ------------ ------------ ------------- -------------- BALANCE, December 31, 1999 14,368,919 $ 144 $ 25,087 $ 61,435 $ 86,666 Net Income - - - 37,780 37,780 Dividends paid - - - (1,000) (1,000) ------------- ------------ ------------ ------------- -------------- BALANCE, December 31, 2000 14,368,919 $ 144 $ 25,087 $ 98,215 $ 123,446 ------------- ------------ ------------ ------------- -------------- Net Income - - - 11,667 11,667 ------------- ------------ ------------ ------------- -------------- BALANCE, December 31, 2001 14,368,919 $ 144 $ 25,087 $ 109,882 $ 135,113 ------------- ------------ ------------ ------------- -------------- Net Loss - - - (20,032) (20,032) ------------- ------------ ------------ ------------- -------------- BALANCE, December 31, 2002 14,368,919 $ 144 $ 25,087 $ 89,850 $ 115,081 ============= ============ ============ ============= ==============
The accompanying notes are an integral part of these consolidated financial statements. CONTINENTAL RESORUCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMETNS OF CASH FLOW FOR THE YEARS ENDED DECEMBER 31, 2000, 2001 AND 2002
2000 2001 2002 --------------- -------------- -------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ 37,780 $ 11,667 $ (20,032) Adjustments to reconcile net income (loss) to net cash provided by operating activities- Depreciation, depletion and amortization 19,552 27,731 31,380 Impairment of properties 4,786 6,595 25,686 Change in derivative fair value - - 1,455 Amortization of debt issuance costs 728 534 1,171 Gain on sale of assets (3,719) (3,460) (223) Dry hole costs and impairment of undeveloped leases 7,119 12,996 5,880 Cash provided by (used in) changes in assets and liabilities- Accounts receivable (5,591) 7,360 (4,383) Inventories (876) (1,333) (379) Prepaid expenses 1,481 (278) 5 Accounts payable 8,716 5,411 4,089 Revenues and royalties payable 315 (3,776) 1,895 Accrued liabilities and other 599 (469) 414 Other noncurrent assets 1,373 435 5 Other noncurrent liabilities - - 34 --------------- -------------- -------------- Net cash provided by operating activities 72,263 63,413 46,997 CASH FLOWS FROM INVESTING ACTIVITIES: Exploration and development (50,711) (68,123) (106,532) Gas gathering and processing facilities and service properties, equipment and other (1,200) (6,645) (6,260) Purchase of oil and gas properties - (36,535) (655) Proceeds from sale of assets 7,665 4,639 152 --------------- -------------- -------------- Net cash used in investing activities (44,246) (106,384) (113,295) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from line of credit and other 37,000 52,245 138,830 Repayment of Senior Subordinated Notes (19,850) (3,000) Repayment of line of credit and other (47,436) (6,200) (75,120) Debt issuance costs - - (2,117) Repayment of short-term debt due to stockholder - - - Payment of cash dividend (1,000) - - --------------- -------------- -------------- Net cash provided by (used in) financing activities (31,286) 43,045 61,593 NET INCREASE (DECREASE) IN CASH (3,269) 74 (4,705) CASH, beginning of year 10,421 7,151 7,225 --------------- -------------- -------------- CASH, end of year $ 7,152 $ 7,225 $ 2,520 =============== ============== ============== SUPPLEMENTAL CASH FLOW INFORMATION: Interest paid $ 16,615 $ 15,269 $ 16,386
The accompanying notes are an integral part of these consolidated financial statements. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: 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 three wholly owned subsidiaries, Continental Gas, Inc. ("CGI"), Continental Resources of Illinois, Inc. ("CRII") and Continental Crude Co. ("CCC"). CGI was incorporated in April 1990, CRII was incorporated in June 2001 for the purpose of acquiring the assets of Farrar Oil Company and Har-Ken Oil Company and CCC was incorporated in May 1998. Since its incorporation, CCC has had no operations, has acquired no assets and has incurred no liabilities. CRI and CRII's principal business is oil and natural gas exploration, development and production. CRI and CRII have interests in approximately 2,460 wells and serve as the operator in the majority of these wells. CRI and CRII's operations are primarily in Oklahoma, North Dakota, South Dakota, Montana, Wyoming, Texas, Illinois, Mississippi 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 eight gas gathering systems and three gas processing plants in its operating areas. In addition, CGI participates with CRI in certain oil and natural gas wells. Basis of Presentation The accompanying consolidated financial statements include the accounts and operations of CRI, CRII, CGI and CCC (collectively the "Company"). All significant intercompany accounts and transactions have been eliminated in the consolidated financial statements. Certain reclassifications have been made to prior year amounts to conform to the current year presentation. Recently Issued Accounting Pronouncements In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method and the liability should be accreted to its face amount. The Company adopted SFAS No. 143 on January 1, 2003. The primary impact of this standard relates to oil and gas wells on which the Company has a legal obligation to plug and abandon the wells. Prior to SFAS No. 143, the Company had not recorded an obligation for these plugging and abandonment costs due to its assumption that the salvage value of the surface equipment would substantially offset the cost of dismantling the facilities and carrying out the necessary clean-up and reclamation activities. The adoption of SFAS No. 143 on January 1, 2003, resulted in a net increase to Property and Equipment and Asset Retirement Obligations of approximately $39.3 million and $35.2 million, respectively, as a result of the Company separately accounting for salvage values and recording the estimated fair value of its plugging and abandonment obligations on the balance sheet. The impact of adopting SFAS No. 143 has been accounted for through a cumulative effect adjustment that amounted to $4.1 million increase to net income recorded on January 1, 2003. The increase in expense resulting from the accretion of the asset retirement obligation and the depreciation of the additional capitalized well costs is expected to be substantially offset by the decrease in depreciation from the Company's consideration of the estimated salvage values in the calculation. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 requires (a) that an impairment loss be recognized only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and (b) that the measurement of any impairment loss be the difference between the carrying amount and the fair value of the long-lived asset. SFAS No. 144 also requires companies to separately report discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. The Company adopted SFAS No. 144 effective January 1, 2002. The adoption of this new standard did not have a material impact on the Company's consolidated financial position or results of operations. As of May 15, 2002, the Company adopted SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS 145 rescinds the automatic treatment of gains and losses from extinguishments of debt as extraordinary unless they meet the criteria for extraordinary items as outlined in Accounting Principles Board Opinion No. 30, Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions. SFAS 145 also requires sale-leaseback accounting for certain lease modifications that have economic effects similar to a sale-leaseback transaction and makes various corrections to existing pronouncements. The adoption of SFAS 145 did not have a material effect on the Company's consolidated financial position or results of operations. In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 addresses financial accounting and reporting for costs associated with exit and disposal activities and supersedes Emerging Issues Task Force (EITF) Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF 94-3. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Adoption of SFAS No. 146 is required for exit and disposal activities initiated after December 31, 2002. The Company adopted this new standard effective January 1, 2003. The impact on the financial position and results of operations of adopting this new standard was not material. In October 2002, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The consensus rescinded EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The October 2002 consensus precludes mark-to-market accounting for all energy trading contracts not within the scope of SFAS No. 133, Accounting for Derivative and Hedging Activities. The consensus to rescind EITF 98-10 is applicable for fiscal periods beginning after December 15, 2002 (early adoption allowed), except that energy trading contracts not within the scope of SFAS No. 133 and executed after October 25, 2002, but prior to the implementation of the consensus, are not permitted to apply mark-to-market accounting. The EITF also reached a consensus that gains and losses (whether realized or unrealized) on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are purchased for trading purposes with the exception of derivative contracts that culminate in the physical delivery of a commodity and meet the criteria of EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent. The Company elected to early adopt this consensus on October 1, 2002. As the Company has no contracts outside the scope of SFAS No.133 that are being marked to market and as the Company's prior policy related to the presentation of gains and losses on derivative contracts entered into for trading purposes is consistent with the requirements of EITF 02-3, the adoption of EITF 02-3 had no material impact on the Company. As further discussed in Derivatives below, the Company has discontinued its trading activities as of May 2002. Accounts Receivable The Company operates exclusively in the oil and natural gas exploration and production, gas gathering and processing and gas marketing industries. Joint interest and oil and gas sales receivables are generally unsecured. The Company's joint interest receivables at December 31, 2001 and 2002, are recorded net of an allowance for doubtful accounts of approximately $359,000 and $544,000, 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, 2001 and 2002, tubular goods and production equipment totaled approximately $5,071,000 and $5,572,000, respectively and crude oil in tanks totaled approximately $1,250,000 and $1,128,000, 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 are 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. Earnings per Common Share Basic earnings per common share is computed by dividing income available to common stockholders by the weighted-average number of shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if diluted stock options were exercised calculated using the treasury stock method. The weighted-average number of shares used to compute basic earnings per common share was 14,368,919 in 2000, 2001 and 2002. The weighted-average number of shares used to compute diluted earnings per share for 2000 and 2001 was 14,393,132. The outstanding stock options (see Note 7) were not considered in the diluted earnings per share calculation for 2002, as the effect would be antidilutive. There were no common stock equivalents or securities outstanding during 1999 that would result in material dilution. Accounting for Derivatives Non-Trading Activity The Company periodically utilizes derivative contracts to hedge the price or basis risk associated with specifically identified purchase or sales contracts, oil and gas production or operational needs. As of January 1, 2001, the Company accounts for its non-trading derivative activities under the guidance provided by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Prior to January 1, 2001, the Company accounted for changes in the market value of derivative instruments used for hedging as a deferred gain or loss until the production month of the hedged transactions, at which time the gain or loss on the derivative instrument was recognized in earnings. Under SFAS No. 133, the Company recognizes all of its derivative instruments as assets or liabilities in the balance sheet at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings during the period of the change in fair values. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative's change in fair value is recognized currently in earnings. Hedge effectiveness is measured at least quarterly based on relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transaction is no longer probable of occurring, any gain or loss deferred in accumulated other comprehensive income is recognized in earnings currently. On January 1, 2001, the Company had no outstanding derivatives that had not been previously marked to market through its accounting for trading activity (see Crude Oil Marketing below). As a result, the initial adoption of SFAS No. 133 had no significant impact on the Company's financial position or results of operations. Crude Oil Marketing During 1998, the Company began trading crude oil, exclusive of its own production, with third parties, under fixed and variable priced physical delivery contracts with terms extending out less than one year. Crude oil marketing activities are accounted for in accordance with SFAS No. 133 and EITF 98-10, Accounting for Energy Trading and Risk Management Activities. The adoption of SFAS No. 133 as of January 1, 2001, had no impact on the Company's accounting for derivative contracts used in its crude oil marketing activities as such contracts were recorded at fair value under EITF 98-10 which was issued prior to SFAS No. 133. Under the guidance provided by SFAS No. 133 and EITF 98-10, all energy and energy related contracts are valued at fair value and recorded as assets or liabilities in the consolidated balance sheet, classified as current or long-term based on their anticipated settlement. Unrealized gains and losses from changes in the fair value of open contracts are included in oil and gas sales in the consolidated income statement. Crude oil marketing contracts that result in delivery of a commodity and meet the requirements of EITF 99-19, Reporting Revenues Gross as a Principal or Net as an Agent, are included as crude oil marketing income or expense in the consolidated income statement depending on whether the contract relates to the sale or purchase of the commodity. Effective May 2002, the Company no longer enters into third party contracts to purchase and resell crude oil, however we did continue to repurchase our physical production from the Rockies and resell equivalent barrels at Cushing to take advantage of better pricing and to reduce our credit exposure from sales to our first purchaser. We have stated these purchases and sales at gross in crude oil marketing. Also see Recently Issued Accounting Pronouncements for further discussion of the accounting for the Company's energy trading activities. Oil and Gas Sales and Gas Balancing Arrangements The Company sells oil and natural gas to various customers, recognizing revenues as oil and gas is produced and sold. The Company uses the sales method of accounting for gas imbalances in those circumstances were it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recognized only to the extent that an imbalance cannot be recouped from the reserves in the underlying properties. The Company's aggregate imbalance positions at December 31, 2001 and 2002, were not material. Changes for gathering and transportation are included in production expenses. Significant Customer During 2000, 2001 and 2002, approximately 22.8%, 17.8% and 42.4%, 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 long-term debt, less the senior subordinated notes discussed in Note 4, approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. Business Segments The Company operates in one business segment pursuant to Statement of Financial Accounting Standards (SFAS) No. 131, "Disclosure About Segments of an Enterprise and Related Information." 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. Stock Based Compensation The Company applies APB Opinion No. 25 in accounting for its fixed price stock options. Under APB 25, no compensation expense is recognized relating to stock options issued under a fixed price plan with a strike price at or above the fair market value of the underlying shares of common stock at the date of grant. For stock options issued with a strike price below the fair market value of the underlying shares of common stock, compensation expense is recognized over the vesting period equal to the fair market value of the common stock at the date of grant less the strike price. During 2001 and 2002, compensation expenses related to in the money options were immaterial. Had the Company determined compensation expense based on the fair value at the grant date for its stock options under SFAS No. 123, the Company's net income (loss) would have been adjusted as indicated below.
- -------------------------------------------------------------------------------- (dollars in thousands except per share amounts) 2001 2002 ---- ---- Net Income (Loss): As Reported $11,667 $(20,032) Pro Forma $11,575 $(20,117) Basic Earnings Per Share: As Reported $ 0.81 $ (1.39) Pro Forma $ 0.81 $ (1.40) Diluted Earnings Per Share: As Reported $ 0.81 $ (1.39) Pro Forma $ 0.81 $ (1.39)
2. FORWARD SALES CONTRACTS: We are exposed to market risk in the normal course of our business operations. Due to the volatility of oil and gas prices, we, from time to time, have entered into financial contracts to hedge oil and gas prices and may do so in the future as a means of controlling our exposure to price changes. Most of our financial contracts settle against either a NYMEX based price or a fixed price. As the contracts provide for physical delivery of its production, the Company has deemed these contracts to be sales in the normal course of business and it does not account for these contracts as derivatives. Revenues from fixed price sales contracts in the normal course of business are recognized as production occurs. As of December 31, 2002, we had entered into contracts covering the notional volumes set forth in the following table for the periods indicated: TIME PERIOD BARRELS PER MONTH PRICE PER BARREL 1/03-3/03 60,000 $21.98 1/03-6/03 30,000 $24.01 1/03-1/04 30,000 $24.01 1/03-12/03 30,000 $25.08 1/03-12/03 30,000 $24.85 In August 2002, we elected to convert the fixed price on 200,000 barrels of crude oil covered under these firm commitments to a variable price by entering into fixed price purchase contracts at an average price of $25.44 per barrel. These derivative purchase contracts have been designated as fair value hedges of a portion of the volumes covered under the firm commitments. As required by SFAS No. 133, changes in the fair value of the firm commitment occurring subsequent to the time the hedges were designated have been recorded in the accompanying balance sheet. As the critical terms of the derivative contracts and firm commitment coincide, changes in the value of the firm commitment are perfectly offset by changes in the value of the derivative contracts. At December 31, 2002, we had a crude oil derivative contract in place, which is being marked to market under SFAS No. 133 with changes in fair value being recorded in earnings as such contract does not qualify for special hedge accounting nor does such contract meet the criteria to be considered in the normal course of business. The contract provides for a fixed price of $24.25 per barrel on 360,000 barrels of crude oil through December 2003 when market prices exceed $19.00 per barrel. However, if the average NYMEX spot crude oil price is $19.00 per barrel or less, no payment is required to the counterparty. If NYMEX sport crude oil prices during a month average more than $24.25 per barrel, we pay the excess to the counterparty. At December 31, 2002, we have recorded a net unrealized loss of $1.5 million on this contract 3. ACQUISITION OF PRODUCING PROPERTIES: On July 9, 2001, the Company's subsidiary, CRII, purchased the assets of Farrar Oil Company, Inc. and Har-Ken Oil Company (collectively "Farrar") for $33.7 million using funds borrowed under the Company's credit facility. This purchase was accounted for as a purchase and the cost of the acquisition was allocated to the acquired assets and liabilities. The allocation of the $33.7 million purchase price on July 9, 2001, was as follows: Current assets $ 950 Producing properties 30,603 Non-producing properties 1,117 Service properties 1,000 -------- $ 33,670 The unaudited pro forma information set forth below includes the operations of Farrar assuming the acquisition of Farrar by CRII occurred at the beginning of the periods presented. The unaudited pro forma information is presented for information only and is not necessarily indicative of the results of operations that actually would have achieved had the acquisition been consummated at that time: Pro Forma (Unaudited) For the twelve months ended December 31, 2001
($ in thousands except share data) Farrar CRI Consolidated - ---------------------------------- ------- ------------ ------------ Revenue $18,219 $263,934 $282,153 Net Income $ 7,700 $ 12,119 $ 19,819 Earnings Per Common Share Basic $0.54 $0.84 $1.38 Diluted $0.54 $0.84 $1.38
4. LONG-TERM DEBT: Long-term debt as of December 31, 2001 and 2002, consists of the following (in thousands):
2001 2002 ---- ---- 10.25% Senior Subordinated Notes due Aug. 2008 (a) $ 127,150 $ 127,150 Credit Facility due March 28, 2005 (b) 56,245 108,000 Capital Lease Agreement (c) - 11,955 --------- --------- Outstanding debt 183,395 247,105 Less Current portion 5,400 2,400 --------- --------- Total long-term debt $ 177,995 $ 244,705 ========= ========= - ---------------- (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 effective interest rate 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. During 2000, the Company repurchased $19.9 million principal amount of its Notes at a cost of $18.3 million and during 2001, the Company repurchased $3.0 million principal amount of its Notes at a cost of $2.7 million. (b) On March 31, 2002, the Company executed a Fourth Amended and Restated Credit Agreement in which a group of lenders agreed to provide a $175.0 million senior secured revolving credit facility with a current borrowing base of $140.0 million. Borrowings under the credit facility are secured by liens on all oil and gas properties and associated assets of the Company. Borrowings under the credit facility bear interest, payable quarterly, at (a) a rate per annum equal to the rate at which eurodollar deposits for one, two, three or six months are offered by the lead bank plus a margin ranging from 150 to 250 basis points, or (b) at the lead bank's reference rate plus an applicable margin ranging from 25 to 50 basis points. The Company paid approximately $2.2 million in debt issuance fees for the new credit facility. The credit facility matures on March 28, 2005. The lead bank's reference rate plus margins at December 31, 2002, was 4.50%. The Company has $108.0 million outstanding debt on its line of credit at December 31, 2002. (c) On December 9, 2002 and December 12, 2002, the Company entered into a long-term lease arrangement with a related party for $2.1 million and $9.9 million, respectively. These lease arrangements were entered into at rates equal to, or better than could have been negotiated with a third party.
The Company's line of credit agreement contains certain negative financial and certain information reporting covenants. The Company was in compliance with all covenants at December 31, 2002. The annual maturities of long-term debt subsequent to December 31, 2002, are as follows (in thousands): 2003 $ 2,400 2004 2,400 2005 110,400 2006 2,400 2007 and thereafter 129,505 ------------------------------ ----------- Total maturities $247,105 =========== At December 31, 2002, the Company had $1.6 million of outstanding letters of credit that expire during 2003. The estimated fair value of long-term debt is approximately $236,933,000 and $164,323,000 at December 31, 2002 and 2001, respectively. The fair value of long-term debt is estimated based on quoted market prices and managements estimate of current rates available for similar issues. 5. INCOME TAXES: The Company follows Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." As mentioned in Note 1, the Company is an S-Corporation resulting in the taxable income or loss of the Company being reported to the stockholders and included in their respective Federal and state income tax returns. The difference in the taxable income of the stockholders versus the net income of the Company is due primarily to intangible drilling costs which are capitalized for book purposes but charged to expense for tax purposes and accelerated depreciation and depletion methods utilized for tax purposes. 6. STOCKHOLDER'S EQUITY: On October 1, 2000, the Company's Board of Directors and shareholders approved an Agreement and Plan of Recapitalization (the "Recapitalization Plan") and the Amended and Restated Certificate of Incorporation to be filed with the Oklahoma Secretary of State. As outlined in the Recapitalization Plan, the authorized number of shares of capital stock was increased from 75,000 shares of common stock to 21 million shares consisting of 20 million shares of common stock and one million shares of $0.01 par value Preferred Stock. In addition, the par value of common stock was adjusted from $1 per share to $0.01 per share and 1.02 million shares of the common stock were reserved for issuance under the 2000 incentive Stock Option Plan discussed in Note 7. Concurrent with the approval of the Recapitalization Plan, the Company affected an approximate 293: 1 stock split whereby the Company issued new certificates for 14,368,919 shares of the newly authorized common stock in exchange for the 49,041 previously outstanding shares of common stock. As a result of the stock split, additional paid-in capital was reduced by approximately $95,000, offset by an increase in the common stock at par. 7. STOCK OPTIONS: The Company has a stock option plan, the Continental Resources, Inc. 2000 Stock Option Plan (the "Plan"), which became effective October 1, 2000. Under the Plan, the Company may, from time to time, grant options to directors and eligible employees. These options may be Incentive Stock Options or Nonqualified Stock Options, or a combination of both. The earliest the granted options may be exercised is over a five year vesting period at the rate of 20% each year for the Incentive Stock Options and over a three year period at the rate of 33 1/3% for the Nonqualified Stock Options, both commencing on the first anniversary of the grant date. The maximum shares covered by options shall consist of 1,020,000 shares of the Company's common stock, par value $.01 per share. The Company granted 144,000 shares during 2000. No options were granted in 2001 and 28,000 shares were granted during 2002. Stock options outstanding under the Plan are presented for the periods indicated. Number of Shares Option Price Range - ---------------------------------------------------- --------------------- Outstanding December 31, 2000 - $ - Granted 144,000 $7.00 - $14.00 Exercised - $ - Canceled - $ - Outstanding December 31, 2001 144,000 $7.00 - $14.00 Granted 28,000 $7.77 - $14.00 Exercised - $ - Canceled - $ - Outstanding December 31, 2002 172,000 $7.00 - $14.00 8. 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 2000, 2001 and 2002, contributions to the plan were 5% of eligible employees' compensation. Pension expense for the years ended December 31, 2000, 2001 and 2002, was approximately $390,000, $392,000 and $353,590, 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 $150,000 and $500,000, respectively, 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 assessments are anticipated for periods prior to December 31, 2002. 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. 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 environmental contamination. The Company is not aware of any material potential environmental issues or claims. 9. RELATED PARTY TRANSACTIONS: 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 was billed to other interest owners, was approximately $8,713,000, $10,942,000 and $11,679,000 during the years ended December 31, 2000, 2001 and 2002, respectively. These services were provided at amounts which management believes approximate the costs that would have been paid to an unrelated party for the same services. At December 31, 2001 and 2002, the Company owed approximately $266,000 and $919,000, respectively, to these companies, which are 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 to the Company. At December 31, 2001 and 2002, approximately $344,000 and $481,000, respectively, from affiliated companies is included in accounts receivable in the accompanying consolidated balance sheets. The Company leases office space under operating leases directly or indirectly from the principal stockholder. Rents paid associated with these leases totaled approximately $313,000, $334,000 and $421,000 for the years ended December 31, 2000, 2001 and 2002, respectively. See Note 4 for discussion of related party capital lease transaction. During 2001, the Company, acting as operator on certain properties began selling natural gas to a related party. During 2002, the Company sold $1.24 million of natural gas to this related party. 10. IMPAIRMENT OF LONG-LIVED ASSETS: The Company accounts for impairment of long-lived assets in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." During 2000, 2001 and 2002, 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 deemed appropriate, an additional charge was added to property impairment expense. The Company recognized $1,665,000 additional property impairment in 2000, $5,303,000 was recognized additional property impairment in 2001, and $2,300,000 was recognized additional property impairment in 2002. 11. GUARANTOR SUBSIDIARIES: The Company's wholly owned subsidiaries, Continental Gas, Inc. ("CGI"), Continental Resources of Illinois, Inc. ("CRII"), and Continental Crude Co. ("CCC") have guaranteed the Company's outstanding Senior Subordinated Notes and its bank credit facility. The following is a summary of the condensed consolidating financial information of CGI and CRII as of December 31, 2000, 2001 and 2002:
Condensed Consolidating Balance Sheet As of December 31, 2001------------------------------------------------------------------------ - ----------------------------------- Guarantor ($ in thousands) Subsidiaries Parent Eliminations Consolidated ---------------- ---------------- ----------------- ---------------- Current Assets $ 6,310 $ 51,915 $ (25,935) $ 32,290 Property and Equipment 42,051 275,280 0 317,331 Other Assets 12 4,863 (11) 4,864 ---------------- ---------------- ----------------- ---------------- Total Assets $ 48,373 $ 332,058 $ (25,946) $ 354,485 Current Liabilities $ 11,039 $ 38,629 $ (8,382) $ 41,286 Long-Term Debt 17,553 178,086 (17,553) 178,086 Other Liabilities 0 91 0 91 Stockholders' Equity 19,781 115,252 (11) 135,022 ---------------- ---------------- ----------------- ---------------- Total Liabilities and Stockholders' Equity $ 48,373 $ 332,058 $ (25,946) $ 354,485 ================ ================ ================= ================ As of December 31, 2002 - ----------------------------------- Current Assets $ 6,524 $ 49,308 $ (22,862) $ 32,970 Property and Equipment 42,664 325,239 0 367,903 Other Assets 7 5,811 (14) 5,804 ---------------- ---------------- ----------------- ---------------- Total Assets $ 49,195 $ 380,358 $ (22,876) $ 406,677 Current Liabilities $ 11,443 $ 42,258 $ (6,934) $ 46,767 Long-Term Debt 15,928 244,705 (15,928) 244,705 Other Liabilities 0 125 0 125 Stockholders' Equity 21,824 93,270 (14) 115,080 ---------------- ---------------- ----------------- ---------------- Total Liabilities and Stockholders' Equity $ 49,195 $ 380,358 $ (22,876) $ 406,677 ================ ================ ================= ================
Condensed Consolidating Balance Sheet As of December 31, 2001------------------------------------------------------------------------- - ----------------------------------- Guarantor ($ in thousands) Subsidiaries Parent Eliminations Consolidated --------------- --------------- ----------------- ---------------- Total Revenue $ 52,051 $ 357,589 $ (563) $ 409,077 Operating Expenses 46,695 339,784 (563) 385,916 Other Income (Expense) (95) (11,400) 0 (11,495) --------------- --------------- ----------------- ---------------- Net Income $ 5,261 $ 6,405 $ 0 $ 11,666 =============== =============== ================= ================ As of December 31, 2002 - ----------------------------------- Total Revenue $ 48,248 $ 253,624 $ (1,581) $ 300,291 Operating Expenses 44,575 260,089 (1,581) 303,083 Other Income (Expense) (1,632) (15,608) 0 (17,240) --------------- --------------- ----------------- ---------------- Net Income $ 2,041 $ (22,073) $ 0 $ (20,032) =============== =============== ================= ================
At December 31, 2001 and 2002, current liabilities payable from the subsidiaries to CRI totaled approximately $8.2 million and $22.6 million, respectively. For the years ended December 31, 2000, 2001 and 2002, depreciation, depletion and amortization, included in operating costs, totaled approximately $2.1 million, $4.9 million and $5.6 million, respectively. Since its incorporation, CCC has had no operations, has acquired no assets and has incurred no liabilities. 12. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED): Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings. Proved Oil and Gas Reserves The following reserve information was developed from reserve reports as of December 31, 1999, 2000, 2001 and 2002, 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 (MMcf) Condensate (MBbls) ------------------ ------------------ Proved reserves as of December 31, 1999 75,761 36,624 Revisions of previous estimates (10,106) 1,340 Extensions, discoveries and other additions 4,613 664 Production (7,939) (3,360) Sale of reserves in place (2,456) (4) Purchase of reserves in place 0 0 -------------- ------------- Proved reserves as of December 31, 2000 59,873 35,264 Revisions of previous estimates (11,766) (2,378) Extensions, discoveries and other additions 9,319 27,276 Production (8,411) (3,489) Sale of reserves in place (2,457) (274) Purchase of reserves in place 5,709 3,332 -------------- ------------- Proved reserves as of December 31, 2001 52,267 59,731 Revisions of previous estimates 21,854 6,195 Extensions, discoveries and other additions 4,948 1,173 Production (9,229) (3,810) Sale of reserves in place 0 (12) Purchase of reserves in place 107 4 -------------- ------------- Proved reserves as of December 31, 2002 69,947 63,281 ============== =============
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 quantities of oil and gas that are ultimately recovered. The year-end weighted average oil and gas prices utilized in the computation of future cash inflows were $10.37 per Bbl and $1.37 per Mcf, respectively, higher in 2002 than in 2001. This price increase accounts for the majority of the revisions of previous estimates for 2002. Gas imbalance receivables and liabilities for each of the three years ended December 31, 2000, 2001 and 2002, were not material and have not been included in the reserve estimates. Proved Developed Oil and Gas Reserves The following reserve information was developed by the Company and sets forth the estimated quantities of proved developed oil and gas reserves of the Company as of the beginning of each year.
Crude Oil and Proved Developed Reserves Natural Gas (MMcf) Condensate (MBbls) - ------------------------- ---------------- ----------------- January 1, 2000 65,723 34,432 January 1, 2001 58,438 33,173 January 1, 2002 56,647 31,325 January 1, 2003 69,273 33,626
Proved developed reserves are proved reserves that 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 years 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.
Property acquisition costs: 2000 2001 2002 ----------- ------------ ----------- Proved $ - $ 36,535 $ 655 Unproved 5,231 11,386 10,504 ----------- ------------ ----------- Total property acquisition costs $ 5,231 $ 47,921 $ 11,159 Exploration costs 6,152 9,170 11,809 Development costs 39,329 47,567 84,219 ----------- ------------ ----------- Total $ 50,712 $ 104,658 $ 107,187
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):
2001 2002 ----------- ----------- Proved oil and gas properties $425,754 $505,444 Unproved oil and gas properties 20,694 16,769 ----------- ----------- Total $446,448 $522,213 Less-Accumulated DD&A (155,703) (182,863) ----------- ----------- Net capitalized costs $290,745 $339,349 =========== ===========
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):
2000 2001 2002 -------------- ------------- ------------- Revenues $115,478 $112,170 $108,752 Production costs 29,807 36,791 36,112 Exploration expenses 9,965 15,863 10,229 DD&A and valuation provision (1) 17,454 29,003 29,244 -------------- ------------- ------------- Income 58,252 30,513 33,167 Income tax expense (2) - - - -------------- ------------- ------------- Results of operations from producing activities (3) $58,252 $29,844 $33,167 ============== ============= ============= - --------------- (1) Includes $1.6 million in 2000, $5.3 million in 2001 and $2.3 million in 2002 of additional DD&A as a result of SFAS No. 121 impairments (2) The Company is an S-Corporation; as a result, the income or loss of the Company is taxable at the stockholder level. (3) Excluding corporate overhead and interest costs
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 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, 2000, 2001 and 2002, as required by SFAS No. 69. The Standard requires the use of a 10% discount rate. This information 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).
2000 2001 2002 ------------- ------------- ------------- Future cash inflows $1,403,645 $1,300,078 $2,131,097 Future production and development costs (495,953) (667,533) (827,238) Future income tax expenses - - - ------------- ------------- ------------- Future net cash flows 907,692 632,545 1,303,859 10% annual discount for estimated timing of cash flows (415,893) (323,941) (670,462) ------------- ------------- ------------- Standardized measure of discounted future net cash flows $491,799 $308,604 $633,397 ============= ============= =============
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 computation of future cash inflows was approximately $26.80, $18.67, and $29.04 per BBL at December 31, 2000, 2001 and 2002, respectively. The year-end weighted average gas price utilized in the computation of future cash inflows was approximately $9.78, $1.96, and $3.33 per MCF at December 31, 2000, 2001 and 2002, respectively. Such prices do not include the effect of the Company's fixed price contracts designated as hedges. 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, 2000, 2001 or 2002, 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)
2000 2001 2002 ------------- ------------- ------------- Standardized measure of discounted future net cash flows at the beginning of the year $334,411 $491,799 $308,604 Extensions, discoveries and improved recovery, less related costs 29,915 98,719 21,082 Revisions of previous quantity estimates (3,544) (33,338) 87,325 Changes in estimated future development costs 853 (107,009) 6,748 Purchase (sales) of minerals in place (1,387) 10,755 161 Net changes in prices and production costs 149,400 (136,665) 233,518 Accretion of discount 33,441 49,180 30,860 Sales of oil and gas produced, net of production costs (85,671) (75,379) (73,755) Development costs incurred during the period 19,196 12,260 52,834 Change in timing of estimated future production, and other 15,185 (1,718) (33,980) ------------- ------------- ------------- Net Change 157,388 (183,195) 324,793 ------------- ------------- ------------- Standardized measure of discounted future net cash flows at the end of the year $491,799 $308,604 $633,397 ============= ============= =============
INDEX TO EXHIBITS
Exhibit No. Description Method of Filing - --- ----------- ---------------- 2.1 Agreement and Plan of Recapitalization Incorporated herein by reference of Continental Resources, Inc. dated October 1, 2000. 3.1 Amended and Restated Certificate of Incorporated herein by reference Incorporation 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 April Incorporated herein by reference 21, 2000 between Continental Resources, Inc. and Continental Gas, Inc., as Borrowers and MidFirst Bank as Agent (the "Credit Agreement"). 4.1.1 Form of Consolidated Revolving Note Incorporated herein by reference under the Credit Agreement. 4.1.2 Second Amended and Restated Credit Incorporated herein by reference Agreement among Continental Resources, Inc., Continental Gas, Inc. and Continental Resources of Illinois, Inc., as Borrowers, and MidFirst Bank, dated July 9, 2001. 4.1.3 Third Amended and Restated Credit Incorporated herein by reference Agreement among Continental Resources, Inc., Continental Gas, Inc. and Continental Resources of Illinois, Inc., as Borrowers, and MidFirst Bank, dated January 17, 2002. 4.1.4 Fourth Amended and Restated Credit Incorporated herein by reference Agreement dated March 28, 2002, among the Registrant, Union Bank of California, N. A., Guaranty Bank, FSB and Fortis Capital Corp. 4.2 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. 10.1 Unlimited Guaranty Agreement dated March Incorporated herein by reference 28, 2002. 10.2 Security Agreement dated March 28, 2002, Incorporated herein by reference between Registrant and Guaranty Bank, FSB, as Agent. 10.3 Stock Pledge Agreement dated March 28, Incorporated herein by reference 2002, between Registrant and Guaranty Bank, FSB, as Agent. 10.4 Conveyance Agreement of Worland Area Incorporated herein by reference 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, Incorporated herein by reference effective October 1, 1999, by and between Patrick Energy Corporation as Buyer and Continental Resources, Inc. as Seller. 10.6 Continental Resources, Inc. 2000 Stock Incorporated herein by reference Option Plan. 10.7 Form of Incentive Stock Option Incorporated herein by reference Agreement. 10.8 Form of Non-Qualified Stock Option Incorporated herein by reference Agreement. 10.9 Purchase and Sales Agreement between Incorporated herein by reference Farrar Oil Company and Har-Ken Oil Company, as Sellers, and Continental Resources of Illinois, Inc. as Purchaser, dated May 14, 2001. 10.10 Collateral Assignment of Contracts dated Incorporated herein by reference March 28, 2002, between Registrant and Guaranty Bank, FSB, as Agent. 12.1 Statement re computation of ratio of Filed herewith electronically debt to Adjusted EBITDA. 12.2 Statement re computation of ratio of Filed herewith electronically earning to fixed charges. 12.3 Statement re computation of ratio of Filed herewith electronically Adjusted EBITDA to interest expense. 21.0 Subsidiaries of Registrant. Incorporated herein by reference 99.1 Letter to the Securities and Exchange Incorporated herein by reference Commission dated March 28, 2002, regarding the audit of the Registrant's financial statements by Arthur Andersen LLP.
EX-12.1 3 criexh121form10k-32803.txt Exhibit 12.1 - COMPUTATION OF RATIO OF DEBT TO ADJUSTED EBITDA CONTINENTAL RESOURCES, INC.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------------- 1998 1999 2000 2001 2002 --------------- ------------------ ----------------- ----------------- -------------- NET INCOME (LOSS) (17,980) 3,920 37,780 11,667 (20,032) INCOME TAXES - - - - - INTEREST EXPENSE 12,826 17,370 16,514 15,674 18,401 DD&A 30,198 19,549 19,552 27,731 31,380 PROPERTY IMPAIRMENTS 10,165 5,154 5,631 10,113 25,686 EXPLORATION EXPENSE 5,468 3,191 9,965 15,863 10,229 LITIGATION SETTLEMENT - - - - - ------- ------- ------- ------- ------- ADJUSTED EBITDA (1) 40,677 49,184 89,442 81,048 65,664 TOTAL DEBT 167,639 170,637 140,350 183,395 247,105 TOTAL DEBT TO ADJUSTED EBITDA 4.1 3.5 1.6 2.3 3.8 - --------------- (1) Adjusted EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization, property impairments and exploration expense, excluding proceeds from litigation settlements. Adjusted EBITDA is not a measure of cash flow as determined by generally accepted accounting principles ("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 computations 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' ability to meet future debt service requirements, if any.
EX-12.2 4 criexh122form10k-32803.txt Exhibit 12.2 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES CONTINENTAL RESOURCES, INC.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------------ 1998 1999 2000 2001 2002 ------ ------ ------ ------ ------ EARNINGS (17,980) 3,920 37,780 11,667 (20,032) FIXED CHARGES 12,704 16,990 16,513 15,674 18,401 ------ ------ ------ ------ ------ TOTAL EARNINGS & FIXED CHARGES (5,276) 20,910 54,293 27,341 (1,631) RATIO N/A 1.2 3.3 1.7 N/A EARNINGS INSUFFICIENT TO COVER FIXED CHARGES BY 17,980 N/A N/A N/A 20,032
EX-12.3 5 criexh123form10k-32803.txt Exhibit 12.3 - COMPUTATION OF RATIO OF ADJUSTED EBITDA TO INTEREST EXPENSE CONTINENTAL RESOURCES, INC.
YEAR ENDED DECEMBER 31, -------------------------------------------------------------------------------------------- 1998 1999 2000 2001 2002 -------------------------------------------------------------------------------------------- NET INCOME (LOSS) (17,980) 3,920 37,780 11,667 (20,032) INCOME TAXES - - - - - INTEREST EXPENSE 12,826 17,370 16,514 15,674 18,401 DD&A 30,198 19,549 19,552 27,731 31,380 PROPERTY IMPAIRMENTS 10,165 5,154 5,631 10,113 25,686 EXPLORATION EXPENSE 5,468 3,191 9,965 15,863 10,229 LITIGATION SETTLEMENT - - - - - ADJUSTED EBITDA (1) 40,677 49,184 89,442 81,048 65,664 TOTAL ADJUSTED EBITDA TO INTEREST EXPENSE 3.2 2.8 5.4 5.2 3.6 - --------------- (1) ADJUSTED EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization, property impairments and exploration expense, excluding proceeds from litigation settlements. EBITDA is not a measure of cash flow as determined by generally accepted accounting principles ("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' financial performance, such as a company' 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 computations 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' ability to meet future debt service requirements, if any.
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