10-K 1 d84290e10-k.txt FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2000 1 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 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, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] COMMISSION FILE NUMBER 0-18886 HS RESOURCES, INC. (Exact name of Registrant as specified in its charter) DELAWARE 94-3036864 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) ONE MARITIME PLAZA, FIFTEENTH FLOOR 94111 SAN FRANCISCO, CA (Zip Code) (Address of principal executive offices)

Registrant's telephone number, including area code: (415) 433-5795 --------------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT TITLE OF EACH CLASS OF STOCK NAME OF EXCHANGE ON WHICH REGISTERED ~~Common Stock -- $.001 par value New York Stock Exchange~~

Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy information statements incorporated by reference in Part III of the Form 10-K or any amendment to this Form 10-K. [ ] Aggregate market value of Common Stock held by non-affiliates of the registrant as of the close of business at January 31, 2001: $671,731,958. Number of shares of Common Stock outstanding as of the close of business on January 31, 2001: 17,874,664 after deducting 1,840,351 shares in treasury. DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Proxy Statement of HS Resources, Inc. to be dated on or before April 30, 2001, are incorporated by reference into Part III. (A definitive proxy statement will be filed with the Commission within the prescribed period.) -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 2 TABLE OF CONTENTS

2 3 PART I ITEM 1. BUSINESS THE COMPANY HS Resources, Inc. ("HSR") is an independent energy company engaged in the development, exploitation, exploration, production, acquisition, gathering, transportation and marketing of oil and natural gas. We were organized as a Delaware corporation in 1987. Our activities are all in the continental United States. Currently we have four primary operating areas -- the Denver-Julesburg Basin in northeast Colorado (the "D-J Basin"), the onshore Gulf Coast area in south Louisiana and southeast Texas, the Mid-Continent region and the northern Rocky Mountain region. These operating areas are described more fully under Item 2. "Properties -- Oil and Gas Properties." We conduct the majority of our oil and gas activities ourselves. Our principal subsidiaries are Resource Gathering Systems, Inc. and HS Gathering, L.L.C., which hold our pipeline assets, and HS Energy Services, Inc. ("HSES"), which is our gas marketing, trading and transportation subsidiary. Substantially all of our other activity is handled through HSR or our 50% owned Gulf Coast joint venture, SouthTech Exploration, L.L.C. Our principal executive offices are located at One Maritime Plaza, Fifteenth Floor, San Francisco, California 94111 and our telephone number at that address is (415) 433-5795. During 2000 we produced 2.9 MMBbl of oil and 65.8 Bcf of natural gas, or 83.1 Bcfe (13.8 MMBoe). (Please see "Certain Definitions" for definitions of abbreviations and other terms.) For the twelve months ended December 31, 2000, we generated net cash flow of $191.2 million and net cash provided by operating activities of $186.2 million. More detailed information about our operating results is located in this report under Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations." At year-end 2000, we recorded proved reserves of 1.30 Tcfe of natural gas (215.9 MMBoe). Natural gas constituted approximately 79% of our reserves, and approximately 64% of our reserves were classified as developed. At year-end we owned interests in approximately 4,100 wells, and we operated approximately 71% of them. More detailed information about our reserves is located in this Report on Form 10-K under Item 2. "Properties -- Oil and Gas Reserves," and more information about our properties is located under Item 2. "Properties -- Oil and Gas Properties." Information concerning our business segments for each of the last three fiscal years, including revenues from external customers, profit or loss, total assets and other segment information is set forth in Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 13 to the Consolidated Financial Statements. Certain transactions in prior periods influence year-to-year comparisons. In December 1997, we acquired from Amoco Production Company all of Amoco's oil and gas properties in the D-J Basin. Effective September 1, 1998, we sold our Mid-Continent oil and gas subsidiary, HSRTW, Inc. for $157.5 million in cash and repaid a portion of our bank debt with the proceeds from the sale. In late 1999, we acquired from Kinder Morgan, Inc. ("KMI") certain natural gas gathering and transmission assets. The KMI transaction is described more fully under "Gas Gathering, Processing and Transmission" below. BUSINESS STRATEGY Our objective is to build shareholder value by increasing our oil and gas reserves and production. To achieve this objective, our strategy is to (i) consolidate in our core area, (ii) develop and exploit our existing property base, (iii) pursue focused exploration in prospective areas and (iv) apply advanced technologies in all areas of our business. Consolidation. We have been active in the D-J Basin since 1982, and since that time we have drilled more than 1,380 wells in the area. Throughout that time, we have conducted many engineering, geologic 3 4 and operational studies in the area, and have accumulated a large database of information and knowledge about the basin's hydrocarbon potential and production characteristics. This knowledge and experience, combined with our established infrastructure, led us to conclude that the area would benefit from consolidation, both to tap the full potential of the reserves and to maximize operating efficiencies. Thus, in 1995 and 1996 we acquired the D-J Basin assets of Freedom Energy, Inc. and Basin Exploration, Inc. In 1997 we acquired Amoco Production Company's D-J Basin properties. In December 1999, we acquired KMI's D-J Basin gas gathering and transmission assets and a 6.9% ownership interest in the BP Wattenberg gas processing plant. See "Gas Gathering, Processing and Transmission." In 2000 we acquired interests in 60 D-J Basin wells for approximately $7.2 million. We currently operate almost 3,000 wells in the D-J Basin, nearly 1,800 of which are connected to our gathering system. More importantly, our consolidation activities have given us a substantial inventory of projects with reduced operational risk but with attractive rates of return. Development and Exploitation. We have several thousand low risk development and exploitation projects in our inventory, including such activities as drilling infill and other development and exploitation wells, deepening existing wells to new formations, recompleting new formations in existing wells, and restimulating currently producing zones. Recent results of our development and exploitation program are set forth under Item 2. "Properties -- Oil and Gas Properties." Exploration. Our approach to exploration is to focus on plays and projects, rather than individual prospects, where we can use advanced technologies and employ in-house knowledge and expertise to gain a competitive advantage. Currently we have 26 project areas located in the onshore Gulf Coast region, where we have acquired approximately 1,300 square miles of 3-D seismic data. In addition, we are currently working four project areas in the Mid-Continent (Oklahoma) and we have a large acreage position in the Northern Rockies. Recent results of our exploration efforts are set forth under Item 2. "Properties -- Oil and Gas Properties." Technology. Our most visible technology is the application of 3-D seismic studies in our exploration programs. Use of this technology typically reduces exploratory drilling risk and enhances economic results. Our 3-D seismic inventory includes more than 1,800 square miles of data that have been acquired and are in various stages of interpretation. We also use other technologies such as reservoir simulators, directional drilling techniques and fully integrated digital databases, each of which aids in the efficient development of oil and gas. MARKETING Gas Marketing. Approximately 25% of our natural gas is subject to an arrangement with Duke Energy Field Services that effectively allows us to sell this gas at market rates to our marketing subsidiary, HSES, with Duke transporting our gas from the wellhead to the processing plant and profiting from a share of the extracted natural gas liquids. This arrangement is the result of our renegotiation of prior contracts with Duke whereby Duke marketed this portion of our gas, in addition to transporting and processing it. Because of the contracts that were in place, the most expedient means of restructuring the arrangements was to require Duke to sell the HSR gas to our subsidiary HSES. Approximately an additional 70% of our gas is sold by HSR directly to HSES at market rates. HSES then sells the gas to a variety of customers, including end users, local distribution companies, pipelines and other marketers. Most contracts are for a short term and provide for market indexed pricing. There are numerous potential customers in the gas market. Thus, we are not dependent on any one customer for the ultimate sale of our gas. The seasonality of the gas market is discussed under Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Oil and Gas Prices." Oil Marketing. Approximately 50% of our current oil production is subject to a "call" by BP Amoco. Under the arrangement, BP has the right, which it has historically always exercised, to purchase approximately 50% of our oil at market rates. Approximately 30% of our current oil production is sold to Conoco, and the rest is sold to other purchasers, all at market rates under contracts for one year or less. 4 5 The market for crude oil, like that for gas, contains numerous potential customers so that the loss of any one customer would not likely have an adverse effect on us. Trading and Hedging. The gas trading activities of HSES, and our oil and gas hedging program are described under Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations." GAS GATHERING, PROCESSING AND TRANSMISSION On November 26, 1999 we acquired our Wattenberg gas gathering and transmission assets ("WGS") from KMI for an adjusted purchase price of approximately $48 million plus the future assumption of an operating lease which then had a present value of $19 million. Although the formal closing of the transaction is scheduled to occur in December of 2001, we have assumed operational control of the system and bear the risks and receive the benefits of ownership. WGS consists of a low pressure gathering system and a high pressure transmission system. The low pressure gathering system consists of more than 1,500 miles of pipeline and 3,000 horsepower of compression, located in five northeastern Colorado counties. The low pressure system delivers the gas to the inlet of the high pressure transmission system, which consists of almost 60 miles of high pressure pipeline and almost 40,000 horsepower of compression. Nearly 1,800 of our D-J Basin wells are connected to WGS, and our operated production represented about 70% of the total system daily throughput of approximately 211 million cubic feet of natural gas per day during the fourth quarter of 2000. Along with the system, we acquired a 6.9% interest in the BP Wattenberg gas processing plant, and a right of first refusal to purchase the remaining 93.1% interest in the plant. The acquisition is being accounted for using the purchase method of accounting. INTERNAL REVENUE CODE SECTION 29 TAX CREDITS Internal Revenue Code Section 29 provides tax credits for natural gas produced from certain types of reservoirs. The credit is available through the end of 2002. Some, but not all, of our gas production qualifies for this tax credit. However, because much of our net income typically has been temporarily offset, for tax purposes, by such things as intangible drilling and development costs, these tax credits would have been lost and could not have been carried forward. As a result, we and our professional advisors structured certain transactions through which we have retained a significant portion of the value of the Section 29 tax credits that would otherwise have been lost to us because of our tax position. In each transaction, we convey substantially all of the working interest in credit-qualified properties to a limited liability company owned by one or more large financial institutions. We retain both an option to reacquire the properties and a 100% production payment in the properties until 95% of the net present value of the properties, measured at the time the working interest was conveyed, is produced. The effect of the transactions is that we receive the production-related cash flow that we would have received if we were the working interest owner, and the investor receives tax credits. The investor makes an initial payment to us, and makes periodic payments that vary depending on the volume of credit-qualified gas produced. The transactions are structured in accordance with private letter rulings issued by the Internal Revenue Service to third parties. In some cases, the investors have obtained private letter rulings that specifically cover our transactions. Through these transactions, we have recognized approximately $8.2 million and $10.1 million of "other gas revenues" associated with the tax credits during the years ended December 31, 2000 and 1999, respectively. We expect to receive approximately $15 million for tax credits for the period 2001 through 2002, based on current production estimates. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations." 5 6 COMPETITION The oil and gas industry is highly competitive. We compete with major oil companies, other independent oil and gas concerns and individual producers and operators for opportunities and talented personnel. Many of these competitors have substantially greater financial and other resources than HSR. REGULATION The following discussion of regulation of the oil and gas industry is necessarily brief and is not intended to constitute a complete discussion of the various statutes, rules, regulations or governmental orders to which our operations may be subject. Price Controls on Liquid Hydrocarbons. There are currently no federal price controls on oil production. There can be no assurance, however, that Congress or the relevant state governments will not enact price controls in the future. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Considerations -- High Prices and Price Regulation." Federal Regulation of First Sales and Transportation of Gas. Historically, the transportation and sale for resale of gas in interstate commerce have been regulated under the Natural Gas Act, the Natural Gas Policy Act, and the regulations issued under the Act by the Federal Energy Regulatory Commission ("FERC"). Maximum selling prices of certain categories of gas sold in "first sales" were regulated pursuant to the Natural Gas Policy Act. On July 26, 1989, the Natural Gas Wellhead Decontrol Act was enacted removing, as of January 1, 1993, all remaining federal price controls from gas sold in "first sales." FERC retains its jurisdiction over gas transportation. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Considerations -- High Prices and Price Regulation." Beginning in the mid-1980s and continuing until the present, FERC promulgated a series of orders designed to correct perceived market distortions and to make gas markets more competitive by, among other things, removing the transportation barriers to market access. These orders have had a significant impact upon gas markets in the United States and have fostered the development of a large spot market for gas and increased competition for gas markets. As a result of the FERC orders, producers can access gas markets directly but face increased competition for those markets. Interstate pipelines continue to be regulated by FERC under the Natural Gas Act. The high pressure transmission line that HSR acquired from KMI is currently subject to FERC jurisdiction. FERC regulations require extensive reporting, advance approval of system changes or expansion, and control of tariff and rate provisions. While KMI handles regulatory compliance until closing of the transaction expected in December 2001, we have significant reporting obligations to KMI during that period and are subject to the construction, operation, tariff and rate constraints imposed by FERC. We expect to close the acquisition of WGS from KMI at the end of 2001, and will be responsible for compliance with FERC regulations after that time. Various state commissions also regulate the rates and services of pipelines whose operations are purely intrastate in nature. Some state utility commissions, including the Colorado Public Utilities Commission, now require that intrastate pipeline and local distribution public utilities offer open access, non-discriminatory transportation which allows consumers connected to those systems to contract with producers or other suppliers for gas. State and Local Regulation of Drilling and Production. State regulatory authorities have established rules and regulations governing, among other things, permits for drilling and production, drilling and operations, performance bonds, reports concerning operations, discharge, disposal and other waste-related permits, well spacing, unitization and pooling of operations, taxation, environmental and conservation matters. A few states (Texas and Louisiana, for example) also limit production from wells, but this currently has no effect on our wells. 6 7 Many of the cities, towns and counties in Colorado affected by oil and gas development have also enacted ordinances and established regulations and procedures that affect oil and gas operations. In general, these measures make oil and gas development more difficult. While we believe that some of these measures are invalid, their existence may adversely affect our activities unless they are judicially invalidated or are repealed. Environmental Regulations. Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities. Also, the discharge of oil, gas or other pollutants into the air, soil or water may give rise to significant liabilities of HSR to the government and/or third parties. Moreover, we have agreed to indemnify certain sellers of producing properties from whom we have acquired properties against certain liabilities for environmental claims associated with the properties purchased by us. Compliance with environmental laws has not had a material adverse effect upon us to date and we are not aware of any matter that is likely to have a material adverse effect on us in the future. No assurance can be given, however, that existing environmental laws or regulations, as currently interpreted or as may be interpreted in the future, or future laws, regulations and policies will not materially adversely affect our results of operations and financial condition or that material indemnity claims will not arise against us with respect to properties we acquire. For a discussion of particular environmental issues currently affecting the Company, see Item 3. "Legal Proceedings and Environmental Issues," and Note 10 to Consolidated Financial Statements. Federal Leases. Operations on federal leases must be conducted in accordance with permits and regulations issued by the Bureau of Land Management or other federal agencies and are subject to a number of other regulatory restrictions. In addition, on certain federal leases prior approval of drillsite operations must be obtained from the Environmental Protection Agency ("EPA"). Although we hold interests in many federal oil and gas leases, very few of our producing operations are located on these leases. TITLE TO PROPERTIES We generally obtain a title opinion prior to beginning drilling operations on properties. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. Customary royalty interests, liens for current taxes and other matters generally burden our properties. These burdens do not materially interfere with the use or affect the value of such properties. We have mortgaged a portion of our properties to secure borrowings under our credit facilities. Consistent with standard industry practice, our title investigation before acquiring undeveloped properties is typically less rigorous than that conducted prior to drilling a well. OPERATIONAL HAZARDS AND INSURANCE Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, as well as the gathering and transportation of gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, equipment and vehicle accidents, fires, pollution, releases of toxic gas and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We have engaged Insurance Management Associates, Inc., one of the world's largest insurance brokerage firms, to procure various types of coverage for our operations. We believe our insurance coverage is reasonable and prudent for the types of risks we expect to encounter. Our insurance does not cover every potential risk associated with the drilling, production, storage and transportation of oil and gas and, while certain environmental coverage is provided, coverage is not obtainable for all types of environmental hazards. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. Moreover, we 7 8 cannot assure you that we will be able to maintain adequate insurance in the future at rates we consider to be reasonable. EMPLOYEES In addition to our San Francisco headquarters, we have offices in three cities in Colorado, two offices in Oklahoma and one in Texas. At December 31, 2000, we had 363 employees, with 27 located in San Francisco, California, 113 in Denver, Colorado, 160 in Evans, Colorado, 44 in Brighton, Colorado, 12 in Tulsa, Oklahoma, 4 in Oklahoma City, Oklahoma and 3 in Houston, Texas. None of our employees is subject to a collective bargaining agreement. We consider our relations with our employees to be good. ITEM 2. PROPERTIES OFFICE LEASES HSR leases the following office space:

--------------- (1) HSR's monthly rental obligation under this lease is $48,472 per month. However, in 2000, HSR subleased 9,834 square feet of its office space to a third party for $49,170 per month, resulting in the net amount shown above. This sublease expires in December 2003. In addition, pursuant to the KMI transaction, HSR has acquired and is occupying 26,798 square feet of office space in Brighton, Colorado. OIL AND GAS PROPERTIES The following tables summarize certain information with respect to each of our areas of operations and production. All information is presented as of December 31, 2000.

8 9

--------------- (1) Includes 979 D-J Basin wells in which we own only overriding royalty interests. (2) Calculated for the quarter ended December 31, 2000. (3) Includes acres upon which we own options to lease and seismic permits as well as oil and gas leases. Denver-Julesburg Basin. The D-J Basin, located in northeastern Colorado, has been our primary producing region for almost 20 years. One of the attractive features of D-J Basin geology is its potential for multiple pay zones in a single wellbore. In a section only 3,500 feet thick, there are at least seven potentially productive formations. Three of the formations, the Codell, Niobrara and J Sand, are "blanket" zones in our Wattenberg Field area, located approximately 35 miles north and east of Denver. The Codell and Niobrara formations are found there at depths ranging from 6,400 to 7,700 feet and the J Sand is found between 7,400 and 7,800 feet. Codell and Niobrara wells produce oil and natural gas, while J Sand wells produce primarily gas. Our D-J Basin production and reserves are largely found in these formations. Although more localized in extent, we also have production from the deeper D Sand and Dakota sandstones and the shallower Sussex and Shannon sandstones. Drilling success rates have historically been high, and production from these formations is characterized by strong initial production flows and long-lived reserves. Production also tends to be a combination of oil and gas. Gas produced in the central part of the D-J Basin, including the Wattenberg Field area, has an energy content ranging from 1,150 to 1,350 Btu per cubic foot, which typically enhances wellhead value. We have a large inventory of projects in the D-J Basin comprised of development and exploitation drilling in existing spacing units, recompletions of currently nonproducing formations in existing wells, restimulating ("refracing") currently producing formations, and deepening existing wells to new formations. We also have several exploration leads in this area. During 2000 we conducted 394 activities in the D-J Basin. Key activities included refracing the Codell formation in 211 wells, drilling 53 new J Sand wells, deepening 81 other wells to the J Sand, and 49 Dakota formation tests. Gulf Coast Region. We also have established a core geographic focus in onshore south Louisiana and the upper Texas Gulf Coast. Our activities there target both shallow exploitation and deeper exploration projects. Our typical approach is to augment our geologic interpretation by applying geophysical expertise to normal and slightly over-pressured formations. Our primary areas of interest include Acadia, Allen, Jefferson Davis, Beauregard, Calcasieu, St. Landry and Evangaline Parishes in Louisiana and Chambers, Jefferson, Ft. Bend and Matagorda Counties in Texas. The complex faulted and prolific salt dome dominated region possesses numerous reservoir targets that, in various combinations, provide attractive multi-zone drilling prospects. Wells in the area target the Frio, Hackberry, Vicksburg, Yegua, Sparta and Wilcox formations at depths ranging from 3,000 to 13,500 feet with most targets between 8,000 and 12,000 feet. More recently, HSR has initiated an exploration program targeting deep, over-pressured lower Miocene sands in St. Mary and Terrebonne Parishes in Louisiana. In this project, prospective reservoir sands are typically encountered below 17,000 feet. To date, we have acquired approximately 1,300 square miles of advanced 3-D seismic data to support an exploration and exploitation effort on 26 major project areas. During 2000, our Gulf Coast program continued the drilling phase on several projects as we participated in 27 gross (11.8 net) wells, of which 14 gross (5.9 net) wells were successful. 9 10 During 2000, we continued to exploit our technical knowledge of the rotated Hackberry play. In particular, we further developed the Indian Village project area directly east of our North Gillis project in Louisiana. Since the inception of the Indian Village project HSR has drilled 13 successful wells in 14 attempts. HSR operates the project and owns a 50% working interest. Results in Indian Village in 2000 included four Hackberry discoveries, one Miocene discovery and one dry hole. We drilled two additional Hackberry discoveries in the North Gillis project area which we operate (37.5% working interest). In addition, one Hackberry discovery was drilled on the Edgerly project (25% working interest). The Roanoke project (50% working interest) had additional activity, resulting in one successful Hackberry well. In Texas, we drilled one Hackberry discovery on the Lox B project area. We also drilled one dry hole at Cottonwood Creek (55% working interest) targeting the Vicksburg formation. At Caney Creek (25% working interest), we participated in two wells, one of which was successful. Also during 2000, we began drilling on two additional rotated Hackberry project areas, Hathaway and Starks, both in Louisiana. On the Hathaway project (37.5% working interest) we drilled two Hackberry discoveries. On the Starks project (50% working interest) we drilled three dry holes. Mid-Continent. During 2000, we focused on advancing the evaluation of our grass-roots exploration projects. We currently have four active projects in varying stages of maturity: Upper Red Fork Valley, Western Mountain Front, Eastern Mountain Front and a regional Granite Wash study. We successfully drilled our first well in Upper Red Fork Valley at the Bethel Church prospect in August. In the Upper Red Fork Valley project, the Brooks 1-27 was brought on line during the fourth quarter at a rate of 1.0 MMcfe per day net to HSR. Based on the success of this well, two development locations have been identified in this project and a second analog prospect is being pursued. In the Western Mountain Front, 28 square miles of 3-D seismic were evaluated, the location of our first overturned Springer test was confirmed and two other leads were identified at the West Rainey prospect. The Cain 1-26 is scheduled to be drilled in the first quarter of 2001. In the Eastern Mountain Front, we anticipate drilling in the fourth quarter of 2001 after integration of reprocessed and newly acquired 2-D seismic data. The Granite Wash project was initiated during the fourth quarter of 2000 as a natural complement to the Mountain Front projects. Northern Rockies. HSR currently has four project areas in the Green River Basin of southwest Wyoming. Three of the projects are focused primarily on tight gas sands which are South Jonah, North Pinedale and Gold Coast. We are also evaluating coalbed methane ("CBM") potential at the Adaville project. At South Jonah, we drilled and completed the HSR Scarlet 11-24 in an effort to evaluate reservoir quality, drilling costs, and stimulation techniques. Results show that the Lance reservoir is extensive, but the combination of low reservoir deliverability and relatively high drilling and completion costs has resulted, to date, in marginally economic wells. Future drilling activity is currently under evaluation. At Gold Coast, HSR's partners drilled two wells. Both encountered overpressured target sections, but failed to discover quality reservoir rock sufficient to deliver economic gas. These data are currently being reviewed with no immediate plans for additional drilling. At Adaville, we have developed a project to evaluate the CBM potential of the western Green River Basin. The project is downdip from active coal mines and leasing was completed during 2000. We currently control nearly 40,000 net acres in the project and evaluation of the potential should begin during 2001. 10 11 ACREAGE The following table sets forth the gross and net developed and undeveloped acres on which we own the rights to conduct exploration and development activity as of December 31, 2000.

--------------- (1) Includes acres upon which we own options to lease and seismic permits as well as oil and gas leases. OIL AND GAS RESERVES Since 1998, Netherland, Sewell & Associates, Inc. ("NSAI") has reviewed our estimates of proved reserves, projected future production and estimated future net revenues from production of proved reserves. NSAI's estimates are based upon a review of production histories and other geologic, economic, ownership and engineering data provided by or available to us. In the aggregate, for the year ended December 31, 2000, NSAI reviewed proved properties constituting 81% of the pre-tax present value of our total proved reserves. In determining the estimates of the reserve quantities that are economically recoverable, we used selling prices (without consideration of hedging effects) and estimated development and production costs that were in effect as of December 31, 2000. In accordance with guidelines promulgated by the Securities and Exchange Commission, no price or cost escalation or de-escalation was considered. The following table sets forth information as of December 31, 2000, derived from our reserve reports. The present value (discounted at 10%) of estimated future net revenues before income taxes shown in the table is not intended to represent the current market value of the estimated oil and gas reserves owned by HSR.

There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data presented above represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and 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 any estimate may justify revision of the estimate, either upward or downward, and such revision may be material. Accordingly, reserve estimates often differ from the quantities of oil and gas ultimately recovered. Furthermore, the estimated future net revenues from proved reserves and the present value of those reserves are based upon certain assumptions, including prices, future production levels and cost, that may not prove correct over time. 11 12 Predictions about prices and future production levels are very uncertain. This is particularly true as to proved undeveloped reserves, which are by their nature less certain than proved developed reserves, and which comprise a significant portion of our proved reserves. Pricing assumptions materially affect the calculation of present value of future net revenues, principally in two ways. First, higher or lower prices directly affect estimated cash flows attributable to a given reserve and production stream. Second, higher or lower prices also increase or decrease the number of potentially recoverable barrels of oil or cubic feet of gas. This is because wells reach their economic limit earlier in a lower product price environment than in a higher price environment, hence truncating the economic recovery of reserves. Oil and gas prices have fluctuated widely in recent years. The weighted average sales prices utilized for the purposes of estimating our proved reserves and future net revenue therefrom at December 31, 2000, were $25.29 per Bbl of oil and $8.91 per Mcf of gas. The use of these year end prices is required by SEC regulations. The price of gas at the end of 2000 was high and significantly exceeds the average prices we currently expect to receive in the foreseeable future. Consequently, the present value of estimated future net revenues stated in this Report on Form 10-K should be used for comparative purposes only and is not intended to represent the market value of these assets. For cautions regarding forward-looking statements made or implied by us see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Disclosure Regarding Forward-Looking Statements" and "Certain Considerations." For further information concerning the present value of future net revenue from HSR's proved reserves, see Note 14 of the Notes to Consolidated Financial Statements. Since December 31, 1990, as an operator of domestic oil and gas properties, HSR has filed Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported in this Annual Report on Form 10-K. Form EIA-23 requires that an operator report on the total reserves attributable to wells which are operated by it, without regard to ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis), while reserves reported in this Form 10-K are net to HSR. DRILLING ACTIVITY The following table sets forth the net wells drilled and completed during the periods indicated. Substantially all of our wells produce both oil and gas. This table excludes deepenings, refracs and recompletions in existing wells, which constituted a large portion of our 2000 activities.

12 13 PRODUCTIVE OIL AND GAS WELLS As of December 31, 2000, we owned interests in the following productive oil and gas wells:

--------------- (1) We also have overriding royalty interests in 979 gross (50.1 net) wells that are not reflected in these numbers. Wells are classified for legal purposes as oil or gas producers as described in statutory definitions based on oil/gas ratios. Such definitions result in most of our wells being categorized as oil wells, even though, on an equivalent Btu basis, such wells tend to produce more gas than oil. DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES The following table provides certain information regarding the costs we have incurred in our development, exploration and acquisition activities during the periods indicated (in thousands).

13 14 PRODUCTION The following table sets forth our oil and gas production data during the periods indicated.

--------------- (1) Average daily production for 2000, 1999 and 1998 was calculated for the quarter ended December 31. ITEM 3. LEGAL PROCEEDINGS AND ENVIRONMENTAL ISSUES Litigation. We are subject to minor lawsuits incidental to operations in the oil and gas industry. We believe we have meritorious defenses to all lawsuits in which we are a defendant and will vigorously defend against them. We believe that the resolution of these lawsuits, regardless of the outcome, will not have a material adverse effect on our results of operations or financial position. Environmental Proceedings. In May 1995, we were named by the Environmental Protection Agency ("EPA") pursuant to a Resource Conservation and Recovery Act administrative order as one of two respondents in addition to the owner/operator of an oilfield production water evaporation facility. The order requires that work be performed to abate a perceived endangerment to wildlife, the environment or public welfare. We and other non-operator respondents have worked together with the EPA to develop characterization studies of the site, and have caused the facility to be permanently closed. HSR and other non-operator respondents have completed substantially all work at the site. We have incurred approximately $1.3 million as of December 31, 2000 for our portion of the costs. This amount has been recorded in our financial statements as of December 31, 2000 and we believe that no substantial liability remains. Additionally, in March of 1999 we became subject to an enforcement action handled by the EPA and the Department of Justice for alleged violations of Section 404 of the Clean Water Act concerning wetlands in Louisiana. The consent decree order resolving the matter has been entered by the federal court in Louisiana. The settlement will not have a material adverse effect on us. In 1999 we accrued an amount in our financial statements that is sufficient to cover the settlement costs. Finally, the gathering and transmission properties we are acquiring from KMI contain numerous areas of polluted soil and ground water. These conditions have been reported to the appropriate jurisdictional agencies. In December 2000, we settled the environmental liability with KMI for $3.3 million (which will be paid as an offset to the purchase price) and have entered into a turnkey agreement with an environmental cleanup company to complete the work. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 14 15 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS HSR's common stock is traded publicly on the New York Stock Exchange ("NYSE") under the symbol "HSE." The following table presents the high and low sales prices reported by the NYSE for the periods indicated. These prices do not include retail markups, markdowns or commissions.

As of January 31, 2001, there were 517 holders of record of our common stock. We have never paid any cash dividends on our common stock, and our Board of Directors does not currently intend to declare cash dividends on our common stock. We instead intend to retain our earnings to support the growth of our business. Any future cash dividends would depend on future earnings, capital requirements and our financial condition and other factors deemed relevant by the Board of Directors. Our credit facility currently prohibits payment of dividends and the indentures governing our outstanding 9 1/4% and 9 7/8% senior subordinated notes due in 2006 and 2003, respectively, also limit our ability to pay dividends. In March and May of 2000, we issued 6,000 shares of common stock pursuant to the exercise of warrants issued in 1990. The exercise price was $6.67 per share and total proceeds were $40,000. The proceeds will be used for general corporate purposes. These securities were issued in reliance on the exemption provided under Section 4(2) of the Securities Act of 1933 and not pursuant to a registration statement. HSR has no other warrants outstanding. 15 16 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected financial data, as of the dates and for the periods indicated, and is qualified in its entirety by reference to the consolidated financial statements of HS Resources, Inc. included in this Annual Report on Form 10-K. For further discussion, see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 2 to Consolidated Financial Statements.

16 17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General. Our strategy centers around consolidation of assets in the Denver-Julesburg ("D-J") Basin, coupled with development, exploitation and exploration in our core areas. We use a technology-oriented approach designed to reduce risk and maximize efficiencies. We currently operate primarily in four core areas: the D-J Basin, the onshore Gulf Coast and, to a lesser extent, the Mid-Continent and Northern Rockies. For the year ended December 31, 2000, approximately 83% of our production (on an energy equivalent basis) came from the D-J Basin and 17% from the Gulf Coast. We intend to continue to pursue certain technology-oriented exploration projects and other activities in other regions, including the Mid-Continent. We also intend to continue our strategically important and historically profitable presence in the gas marketing, trading and transportation business through our wholly-owned subsidiary, HSES. HSES provides opportunities for us to enhance our operating margins on gas production from each of our producing areas and from production we market on behalf of other oil and gas producers. HSES also trades financial positions in the gas commodities market. In December 1999, we furthered our consolidation strategy in the D-J Basin by acquiring from KMI the WGS assets for an adjusted purchase price of approximately $48 million, plus the assumption of an operating lease which then had a net present value of $19 million. As part of this transaction, we also purchased a 6.9% interest in the BP Wattenberg gas processing plant, and a right of first refusal to purchase the remaining interest in the plant. The transaction is scheduled to close in December 2001, however, the acquisition is recorded in our financial statements as of December 1, 1999 using the purchase method of accounting as all operational control was acquired by HSR at that time. WGS consists of a low pressure gathering system and a high pressure transmission system. The low pressure gathering system consists of more than 1,500 miles of pipeline and 3,000 horsepower of compression, located in five northeastern Colorado counties. Gas is delivered to the inlet of the high pressure transmission system, which consists of almost 60 miles of high pressure pipeline and almost 40,000 horsepower of compression. This purchase has given us operational control over the gathering of a large percentage of our gas production. By operating the pipeline we are better positioned to anticipate and alleviate any gathering system bottlenecks that might adversely affect our D-J Basin development and exploitation program and the production of other operators. Oil and Gas Prices. Profitability in the United States oil and gas industry fluctuates widely due in part to fluctuating commodity prices and related changes in rates of reinvestment by industry participants. In early 1999, United States natural gas prices and international crude oil prices were very low, resulting in significant reductions in the operating and financial margins of oil and gas producers. Additionally, low oil prices had a depressing effect on the price of liquids recovered from natural gas during this time period. Thus, the low oil prices of early 1999 further diminished the overall price received for our gas production. In April 1999, both oil and gas prices began to recover, and were substantially higher in 2000. This resulted in HSR realizing for the three months ended December 31, 2000 an average price per Bbl, excluding hedging effects, of $31.35 compared to $22.98 for the comparable period in 1999, and $11.43 for the three months ended March 31, 1999. Natural gas prices per Mcf, excluding hedging effects, were $5.96 for the three months ended December 31, 2000 compared to $2.86 in the comparable period in 1999 and $1.93 for the three months ended March 31, 1999. At December 31, 2000, approximately 79% of our proved producing reserves consisted of gas, of which 97% were located in the D-J Basin. The absolute level and volatility of gas prices, particularly in the D-J Basin, have a material impact on us. Historically, the price of D-J Basin gas (on a Btu-equivalent basis) has been linked closely to the Colorado Interstate Gas Company ("CIG") pipeline Rocky Mountain Index. This remains the case during the lower demand summer months (generally April through October). More recently, however, as a result of increased pipeline capacity into and out of the D-J Basin, a transportation cost advantage for deliveries into the Public Service Company of Colorado (now Xcel Energy) market, and seasonal fluctuations, the price more closely tracks Mid-Continent indices during the higher demand winter periods (generally November through March). We are also working on creating a gas storage field in the D-J Basin that would help us reduce the seasonal volatility of gas prices in this area. 17 18 Gas and oil prices remain strong as of the date of this report. However, we cannot predict future trends in gas or oil prices. The uncertainty concerning the price of oil and gas remains a dominant and unpredictable factor in our profitability. The recent energy crisis in California has not directly adversely affected our business, nor are we aware of any way in which it is likely to directly adversely affect us materially in the future. Nevertheless, this situation is inherently uncertain and presents unknown and unquantifiable risks that could adversely affect us in the future. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Considerations -- California Energy Crisis" and "High Prices and Price Regulation." Results of Operations. During 2000, we continued our drilling and development activities to exploit our opportunities in the D-J Basin. We also continued our exploitation and exploration activities in the Gulf Coast region. Future results will be significantly affected by our exploration, exploitation and development activities as well as fluctuations in oil and gas prices. Comparative operating results by business segment, consolidated other income, expenses and income taxes are presented below. Segment operating revenues, costs and expenses are before intersegment eliminations. COMPARISON OF YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 D-J BASIN OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)

--------------- (1) Includes effects of hedging activities. General. We have been active in the D-J Basin for almost 20 years. Over the years we have sought to consolidate our position there by acquiring properties and conducting active exploitation programs. More recent acquisitions include the June 1996 acquisition of Basin Exploration, Inc.'s D-J Basin properties, the 18 19 December 1997 Amoco acquisition, the 1999 acquisition of WGS and the 2000 acquisition of interests in 60 wells and associated mineral rights for approximately $7.2 million. The 2000 and 1999 exploitation programs consisted of 394 and 397 separate activities, respectively. Oil And Gas Revenues. Over the past several years, our D-J Basin oil and gas production and revenues have increased primarily as the result of the acquisition of properties, the success of our ongoing exploitation and development activities and increased product prices. In 1999, other gas revenues related to the sale of tax credits increased as a result of our refrac program, which increased production on the wells eligible for Section 29 tax credits. Other gas revenues decreased in 2000 compared to 1999 due to natural production declines and significantly less refrac activity on wells eligible for tax credits. Production Expenses. Total lease operating expense ("LOE") increased from 1998 to 1999 and from 1999 to 2000 due to an increase in the number of wells in each of these years compared to the prior year, higher workover costs in 2000 and 1999, and increased COPAS charges in 1999. The increase in COPAS charges was due to an increase in the COPAS escalation factor as of April 1, 1999 in accordance with COPAS guidelines. LOE per Mcfe was $0.42 in 2000 and $0.41 in both 1999 and 1998. Production taxes increased from 1998 to 1999 as a result of higher realized oil and gas prices in 1999. The higher taxes were offset partially by adjustments we recorded in the second quarter to reduce the ad valorem tax accrual rate for 1998 and 1999 to the rate actually paid in 1999. An adjustment of $1.7 million was also recorded in the last quarter of 1999 for an ad valorem rebate associated with the 1996, 1997 and 1998 tax years. The production tax increase from 1999 to 2000 is due mainly to the significant increase in product prices and resulting higher revenues. Depreciation, Depletion And Amortization. Depreciation, depletion and amortization ("DD&A"), a non-cash expense, decreased from 1998 to 1999 and remained flat from 1999 to 2000, even though production increased, because of a decrease in the depletion rate due to the addition of proved reserves. The weighted average depletion rate per Mcfe for the D-J Basin was $0.71, $0.75, and $0.80 for the years ended December 31, 2000, 1999 and 1998, respectively. We annually adjust our DD&A rate based on year-end engineering and, if material changes in our reserves warrant, on an interim basis. Exploratory And Abandonment Costs. Exploratory and abandonment costs include the costs of exploratory dry holes, delay rentals, plugging and abandonment ("P&A") costs, expired acreage and salaries and related overhead ("overhead") costs directly related to exploratory activities. Exploratory and abandonment costs decreased from 1998 to 1999 and from 1999 to 2000 mainly due to a decrease in exploratory dry hole costs. Geological And Geophysical Costs. Geological and geophysical ("G&G") costs include costs for seismic activity as well as overhead costs directly attributable to G&G activity. Of the total G&G costs, we incurred $0.2 million, $0.1 million and $1.4 million in seismic costs for the years ended 2000, 1999 and 1998, respectively. The remaining G&G costs of $0.3 million, $0.2 million and $0.5 million relate to overhead costs directly attributable to G&G activity. The increase in 1998 relates to an increase in 3-D seismic activity in the Greater D-J Basin area. Impairment And Loss (Gain) On Sales Of Oil And Gas Properties. In 1998, we recorded a gain on the sale of 93 wells, for $2.9 million in cash, located primarily in the Yuma County area of the D-J Basin. 19 20 GULF COAST OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)

--------------- (1) There were no hedging activities affecting Gulf Coast production in 2000, 1999, or 1998. General. Over the past several years, the majority of our Gulf Coast activities focused on acquiring, processing and interpreting 3-D seismic information, acquiring leasehold interests, and drilling on our project areas. During 2001 we expect to continue our level of Gulf Coast drilling activities on prospects that we have identified through our 3-D seismic programs. Oil And Gas Revenues. Oil and gas revenues increased significantly since 1998 due to increases in both production and in oil and gas prices. We drilled a total of 27 gross (11.8 net) wells in 2000, 26 gross (11.2 net) wells in 1999 and 24 gross (6.7 net) in 1998. Of the total wells drilled to date, 5 gross (2.05 net) are currently awaiting pipeline hookup. Production Expenses. Aggregate LOE has increased since 1998 because of the greater number of producing wells but LOE per Mcfe decreased from $0.15 in 1998 to $0.09 in 1999 to $0.08 in 2000 because the increase in aggregate LOE was more than offset by the production increase. Production taxes have increased since 1998 as a result of increases in both production and product prices. Depreciation, Depletion and Amortization. Total DD&A increased from 1998 to 1999 mainly as a result of an increase in production. DD&A also increased from 1999 to 2000 due to an increase in production and an increase in the DD&A rate. The increase in the DD&A rate was due to the cost of drilling several wells that was only partially offset by the addition of proved reserves for those wells. The weighted average DD&A rate per Mcfe in the Gulf Coast was $0.59, $0.45 and $0.48 for 2000, 1999 and 1998, respectively. Exploratory And Abandonment Costs. In 2000 we incurred $5.0 million for 13 exploratory dry holes, $6.1 million for expired acreage, $1.8 million for delay rentals and $1.4 million for overhead costs. During 1999 we incurred $4.8 million for 11 exploratory dry holes, $4.3 million for expired acreage, $1.4 million for delay rentals and $1.0 million for overhead costs. In 1998, we incurred $5.8 million for expired acreage, $0.8 million in delay rentals, $1.0 million for seven exploratory dry holes and $1.6 million for overhead costs directly related to exploratory activities. 20 21 Geological And Geophysical Costs. Of total G&G costs, we incurred $6.5 million, $4.5 million and $9.4 million in 2000, 1999 and 1998, respectively, for seismic permits and processing costs in the Gulf Coast. The remaining G&G of $2.0 million, $1.1 million and $1.5 million relates to overhead costs directly attributable to G&G activity. Impairment And Loss On Sales Of Oil And Gas Properties. In 2000, we recorded a loss on the sale of one well. In 1998, we recorded a loss on the sale of two wells. The wells sold in 1998 were conveyed in a non-cash transaction to a third party purchaser which assumed liability for plugging and abandonment costs. MID-CONTINENT AND NORTHERN ROCKIES OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)

--------------- (1) Includes results for production, operating revenues and associated expenses for the Mid-Continent through date of sale, September 1, 1998. (2) There were no hedging activities affecting Mid-Continent and Northern Rockies production in 2000, 1999, or 1998. General. Information for this segment includes activity for both the Mid-Continent and Northern Rockies areas. Effective September 1, 1998, we sold the majority of our Mid-Continent assets and used the proceeds from the sale to pay down a portion of debt under our senior credit facility. Our current strategy in the Mid-Continent is to pursue technology-oriented exploration projects. We have an extensive acreage position in the Northern Rockies region. Our current strategy is to utilize our acreage position as a vehicle for generating capital expenditures by third party operators on our acreage. Oil And Gas Revenues. Because our Mid-Continent properties were sold effective September 1998, the 1998 numbers reflect only a partial year of activity. In 2000 and 1999 there were minimal oil and gas 21 22 revenues in this segment because of the earlier Mid-Continent property sale and the sale of properties in the Northern Rockies region. Exploratory And Abandonment Costs. The majority of exploratory and abandonment costs for 2000, 1999 and 1998 represent costs incurred for expired acreage, delay rentals and capitalized interest for projects in the Northern Rockies. Geological And Geophysical Costs. G&G costs increased in 2000 compared to 1999 due to an increase in seismic activity in the Mid-Continent project area. The decrease in G&G costs in 1999 compared to 1998 is the result of a reduction in seismic activity in the Northern Rockies project area. Impairment And Loss (Gain) On Sales Of Oil And Gas Properties. In 2000 we recorded impairment of $1.5 million on several wells in the Northern Rockies region in accordance with the requirements of successful efforts accounting. We also recorded a $0.7 million loss relating to the settlement of a gas imbalance position on a well we previously owned in the Mid-Continent region. In 1999 we recorded expenses of $2.2 million related to the 1998 sale of the Mid-Continent properties, and income from the sale of the Blue Forest unit and other properties of $3.4 million. In 1998, we recorded impairments of $5.0 million on properties in the Northern Rockies region and recorded a loss on the sale of Mid-Continent properties of $7.0 million. TRADING AND TRANSPORTATION (IN THOUSANDS)

--------------- (1) Includes intercompany revenues of $208,766, $117,570 and $88,230 in 2000, 1999 and 1998, respectively, and expenses of $204,619, $115,098 and $85,794 in 2000, 1999 and 1998, respectively. Such amounts are attributable to our volumes which are marketed by HSES and have been eliminated in our consolidated financial statements. Through our wholly-owned subsidiary, HSES, we market our own gas production as well as that of third parties. A portion of this gas is sold directly to end users, while other amounts are used as the equity-gas foundation for a physical trading business in which gas volumes may be traded several times at different receipt and delivery points in order to capture the greatest margin possible. HSES also serves as an intermediary in the execution of financial derivative instruments for a variety of energy related products and, to a lesser extent, makes speculative trades for its own account in the commodity and basis markets. Operating margins increased in 2000 compared to 1999 and 1998, primarily as a result of an increase in the volume of natural gas marketed and an increase in margins per MMBtu due to the volatility of natural gas physical and financial markets. For the years ended December 31, 2000, 1999 and 1998, gains of $4.4 million, $3.3 million and $2.8 million, respectively, were recognized in connection with financial trading activities. 22 23 GAS GATHERING AND TRANSMISSION (IN THOUSANDS)

Gathering and Transmission System Revenues and Expenses. Effective December 1, 1999 we took over operations of WGS from KMI. The revenues and expenses associated with third party gas are recorded as gathering and transmission system revenues and expenses. During the quarter ended December 31, 2000, WGS transported an average of approximately 211 MMcf of gas per day. Additional compression and other system improvements are under way that are expected to boost daily capacity on WGS by up to 50 MMcf per day by the second quarter of 2001. To accomplish this goal, we are adding three 1,000 horsepower temporary compressors and constructing a new 6,000 horsepower compressor station. As part of the overall WGS system improvement project we are also planning to add a gas processing facility. This plant is designed to be capable of processing up to 50 MMcf per day while recovering 1,500 barrels of natural gas liquids daily. Barring permitting, equipment or other delays, the plant is expected to be operational by the second quarter of 2001. OTHER INCOME AND EXPENSES (IN THOUSANDS)

Interest Income And Other Income. Interest and other income increased from 1999 to 2000 due to interest earned on severance tax refunds. Interest and other income decreased from 1998 to 1999, because, as a result of the Mid-Continent sale, we no longer record income on an interest in a limited partnership. General And Administrative Expenses. General and administrative expenses ("G&A") reflect costs incurred, net of administrative costs directly attributable to drilling and well operations (which costs are included in LOE). G&A costs directly related to geological and geophysical activities and exploratory activities are included in geological and geophysical costs and exploratory costs. G&A per Mcfe was $0.10, $0.08 and $0.11 in 2000, 1999 and 1998, respectively. G&A increased from 1999 to 2000 mainly due to higher payroll and related employee benefits costs. On both an absolute and an Mcfe basis, G&A decreased from 1998 to 1999. The decrease from 1998 to 1999 was due primarily to discontinued G&A related to our Mid-Continent properties and the efficiencies associated with our consolidation program in the D-J Basin. Interest Expense. Interest expense increased from 1999 to 2000 mainly due to an increase in the interest rate on our bank debt, interest attributable to the financing of WGS and a decrease in capitalized interest as a result of a reduction in the undeveloped acreage account. Interest expense increased from 23 24 1998 to 1999 due to a full year of interest payments on the $85 million senior subordinated notes issued in December 1998, a decrease in capitalized interest as a result of a reduction in the undeveloped acreage account, and interest associated with the 1999 purchase of WGS. During 2000, 1999 and 1998, we capitalized $6.4 million, $7.1 million and $11.7 million, respectively, of interest relating to undeveloped acreage. INCOME TAXES (IN THOUSANDS)

Provision For Income Taxes. We follow the provisions of Statement of Financial Accounting Standards ("SFAS") No. 109. Pursuant to SFAS 109, we have recorded a tax provision based on tax rates in effect during the period. Accordingly, we accrued taxes at the rate of 38.5% in 2000 and 38.1% in 1999 and 1998. Due primarily to significant intangible drilling costs, which are deductible for income tax purposes, substantially all of our tax provision in 2000 and 1999 is deferred. In 1998, the current provision is attributable to taxes owed in connection with the sale of our Mid-Continent properties. LIQUIDITY AND CAPITAL RESOURCES Financing Sources. We believe that our current level of debt is manageable under expected production and pricing levels because our debt is supported by stable, long-lived producing reserves and by short-term product prices that are partially hedged at prices that support our bank and other debt requirements. We expect cash flows from producing activities to be sufficient to enable us to service our debt for the foreseeable future, absent any major and prolonged period of low commodity prices or sustained production interruptions. We have a large number of low-risk, potentially high-return exploitation projects that are expected to enhance production and cash flow. As part of an overall financing strategy, we continually evaluate a wide range of future financing alternatives and are not committed to any particular course. In undertaking any future financing transactions, we will seek to achieve the optimal capital structure needed to support our long-term strategic objectives. Any such financings will reflect market conditions at the time and may include the issuance of medium or long-term debt, equity, or equity-linked securities. We currently plan to fund capital expenditures attributable to exploration, exploitation and development activities primarily out of our expected cash flow from operations, subject to periodic variation resulting from the timing of project activities and short-term product price volatility, and apply the excess proceeds, if any, to the repayment of debt, repurchase of stock, or the acceleration of capital projects. The borrowing base under our revolving senior bank credit facility led by The Chase Manhattan Bank is currently $325.0 million. The interest rate under the Chase facility is, at HSR's election, the Base Rate plus 0% to 0.625%, or LIBOR plus 0.75% to 1.625%. The borrowing base is based on the review of our reserves by the lending bank group and their view of future pricing and is usually reviewed annually for potential revision. Under the terms of the Chase facility, no principal payments are required until December 15, 2002, assuming we maintain a borrowing base sufficient to support the outstanding loan balance. As of December 31, 2000, $189.0 million was outstanding under the Chase facility compared to $227.0 million at December 31, 1999. We anticipate that our borrowing capacity under the Chase facility and our operating cash flow will provide us with adequate financial resources and flexibility to fund current and ongoing activities, to 24 25 service our debt and to meet other financial obligations. The nature of our current development strategies and other activities provide us with considerable flexibility in terms of the timing and magnitude of our capital expenditures. If we experience unforeseen changes in our working capital position or capital resources, we may revise the capital expenditure program accordingly or alternatively may attempt to supplement our capital position through, among other things, the issuance of additional equity, equity-linked or debt securities, additional borrowing under the Chase facility, the sale or monetization of properties or by entering into joint venture arrangements. Capital Commitments. We continuously evaluate our inventory of drilling opportunities to develop a growth-oriented portfolio of risk-balanced development, exploitation and exploration opportunities. On an ongoing basis, we adjust the amount and allocation of our capital expenditures based on a number of factors, including seismic results, prospect readiness, product prices, service company availability and rates, acquisitions and capital position. For the year ended December 31, 2000, we incurred total costs for exploration, development, leasehold, exploratory and abandonment, geological and geophysical activities and improvements on WGS of $118.0 million, exclusive of acquisitions, capitalized interest and overhead costs directly related to exploratory and G&G activity. We estimate that such expenditures for the calendar year 2001 will be approximately $135 to $150 million. These costs will be allocated in varying amounts primarily to activities in our core geographic areas. A major component of our capital program relates to our development and gathering activities in the D-J Basin. We incurred approximately $64.7 million for the year ended December 31, 2000 for leasehold and geological and geophysical costs and to drill, deepen, recomplete and refrac our D-J Basin properties as well as $8.2 million on WGS. We anticipate allocating approximately 55% to 60% of our capital budget to the D-J Basin during 2001. Another component of our capital program has been to develop our exploitation and exploration prospects in the onshore portion of the Gulf Coast. For the year ended December 31, 2000, we incurred total expenditures of $38.0 million for seismic, leasehold and drilling costs in the Gulf Coast. We anticipate allocating approximately 35% to 40% of our capital budget to the Gulf Coast projects during 2001 for exploration and development activities, including land and seismic. In our Mid-Continent project area we intend to focus on high volume, long-life gas prospects. We are acquiring and processing 3-D seismic data and are preparing to initiate drilling activity on several prospects. One well was spud and brought on line in the Mid-Continent project area during 2000. For the year ended December 31, 2000, we incurred $3.0 million for seismic, leasehold and drilling costs in the Mid-Continent. We anticipate allocating approximately 1% to 5% of our capital budget to Mid Continent projects during 2001 for exploratory and development activities, including land and seismic. Activities in the Northern Rockies are planned to manage risk by utilizing our extensive acreage positions, operational expertise, and geotechnical ideas to attract risk capital from partners who also add expertise and other value to the project. We believe our projects have substantial flexibility in terms of timing, as a result of long-term leases and minimal future capital obligations. We have also entered into a number of other standard industry arrangements that require the drilling of wells or other activities. We believe that we will meet our obligations under these arrangements, which individually and in the aggregate are not material. Working Capital and Cash Flow. HSR aggressively manages its working capital position including periodic borrowings and repayments under its revolving credit facility. Of the total working capital deficit of $42.6 million at December 31, 2000, $24.4 million represents the current portion of the amount payable to KMI for the purchase of WGS. We intend to use cash provided by monthly gathering and transportation revenues from existing contractual agreements, including amounts paid by HSR for gathering and transportation on WGS, to fund the monthly obligations to KMI. We believe that the payments made under the gathering agreements will exceed the payments to KMI, assuming no unforeseen extended operational interruptions of the system. Net cash provided by operating activities for the year ended December 31, 2000 was $186.2 million, up from $65.0 million for the same period in 1999 as a result of an increase in production and product prices. 25 26 Future cash flows will be influenced by, among other factors, the number of producing wells on line, product prices and production constraints. Risk Management/Hedging. We use financial instruments to reduce our exposure to market fluctuations in the price and transportation costs of oil and gas. Our general strategy is to hedge price and location risk of a portion of our production with swap, collar, floor and ceiling arrangements. We generally enter into hedges for delivery into one of several pipelines located near our producing regions, Panhandle Eastern Pipeline Company ("PEPL"), Northwest Pipeline Corporation ("NW"), CIG, or at the New York Mercantile Exchange ("NYMEX") prices settled at the Henry Hub. With respect to the NYMEX-hedged volumes that exceed our Gulf Coast volumes, it is our practice to hedge our basis (meaning the transportation differential from our producing regions to the location of delivery for a hedged volume), although in some cases an exact hedge instrument may not exist. Gains and losses on hedging positions are recognized in the period during which the underlying physical transactions occur and are booked in "oil and gas sales" (for company-owned production) and "trading and transportation revenues" (for third party gas). Hedging contracts for our production reduced our oil and gas sales by $72.5 million and by $6.1 million for the years ended December 31, 2000 and 1999, respectively, and increased our oil and gas sales by $9.0 million in 1998. The large revenue reduction resulting from hedging agreements in 2000 is mainly due to the significant increase in gas prices toward the end of 2000. Hedging contracts for third party gas increased trading and transportation revenues by approximately $0.8 million, $0.04 million and $0.3 million for the years ended December 31, 2000, 1999 and 1998, respectively. Recently issued accounting pronouncements can change current and future accounting and reporting requirements for certain risk management activities. See Note 4 of the Notes to Consolidated Financial Statements. 26 27 As of December 31, 2000, we held specific swap positions as follows: GAS HEDGES

GAS BASIS HEDGES

27 28 Additionally, with respect to the hedging of third party gas, we have hedged 80.1 Bcf from January 2001 through October 2002 with offsetting physical positions at settlement prices which are based upon NYMEX future prices or other published indices. The fair market value of these hedges at December 31, 2000 was a gain of approximately $17.6 million, of which a gain of $18.8 million and a loss of $1.2 million relates to 2001 and 2002, respectively. In addition to using financial instruments to reduce our exposure to market fluctuations in the price of oil and gas, we have also entered into future sales contracts to be settled by physical delivery covering a portion of our production as follows: GAS SALES

OIL SALES

Trading Activities. We engage in the trading of various energy related financial instruments which require payments to or receipt of payments from counterparties based on the differential between a fixed and a variable price for the commodity, swap or other contractual arrangement. We have established policies with respect to open positions, which limit our exposure to market risk and require daily reporting to management of the potential financial exposure resulting from both hedging and trading activities. Our policy requires that, within defined trading limits, financial instrument purchase and sales contracts be balanced in terms of contract volumes and the timing of performance and delivery obligations. Activities for trading purposes are accounted for using the mark-to-market method. Under this method, changes in the market value of outstanding financial instruments are recognized in "trading and transportation revenues" as a net gain or loss in the period of change. The market prices used to value these transactions reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions. For the years ended December 31, 2000, 1999 and 1998, gains of $4.4 million, $3.3 million and $2.8 million, respectively, were recognized in connection with financial trading activities. As of December 31, 2000, the fair value of the financial instruments is an asset of $9.3 million. Credit Risk. While notional amounts are used to express the volume of various derivative financial instruments, the amounts potentially subject to credit risk in the event of nonperformance by the third parties are substantially smaller. Counterparties to the swap, collar, floor and ceiling arrangements discussed above are generally investment grade institutions. Accordingly, we do not anticipate any material impact to our financial position or results of operations as a result of nonperformance by the third parties to financial instruments related to hedging activities or trading activities. See "Certain Considerations -- California Energy Crisis." Interest Rate Swaps. During the fourth quarter of 1998, we entered into an interest rate exchange agreement with a financial institution to hedge the interest rate on $80 million of our borrowings at 5.86% through December 15, 2006. In the first quarter of 1999, we entered into an interest rate exchange agreement with a financial institution to hedge $50 million of our borrowings at 5.66% through March 31, 2004. Under the terms of the agreements, the difference between the fixed rate and the one-month LIBOR rate is received or paid by us. The mark-to-market value of our interest rate swaps as of December 31, 2000 28 29 was $0.2 million. Market risk related to borrowings from a one percent change in interest rates would result in an approximate $0.6 million impact on pre-tax income, based on the quarter end borrowing level and the amount of such borrowings that are not subject to interest rate swaps. Total Return Equity Swaps. In 1999, we entered into three total return equity swap agreements with financial institutions. Under the terms of the first agreement, entered into on February 25, 1999, the financial institution acquired approximately 732,000 shares of our common stock from another investor at a price of $6.0625 per share. Effective April 20, 2000 we repurchased the 732,000 shares of our common stock and recorded the shares into treasury stock. On May 24, 1999, we entered into a second agreement whereby the financial institution acquired 100,000 shares of our common stock from another investor at a price of $11.9875 per share. In addition, on December 1, 1999, we entered into a third agreement whereby a financial institution agreed to acquire on the open market approximately 300,000 shares of our stock at current market prices over a three month period beginning December 2, 1999. As of March 2000, the financial institution had acquired 308,100 shares at a weighted average price of $14.55 per share. In October 2000, we repurchased the 408,100 shares under the second and third agreements and recorded the shares into treasury stock. There are no commitments that remain related to these swaps. Contingencies. We have resolved the alleged Clean Water Act Section 404 (wetlands) violations in Louisiana. The consent decree order resolving the matter has been entered by the federal court in Louisiana. The settlement will not have a material adverse effect on us. In 1999 we accrued an amount in our financial statements that is sufficient to cover the agreed upon settlement costs. Also, the gathering and transmission properties we are acquiring from KMI contain numerous areas of polluted soil and ground water. These conditions have been reported to the appropriate jurisdictional agencies. In December 2000, we settled the environmental liability with KMI for $3.3 million (which will be paid as an offset to the purchase price) and have entered into a turnkey agreement with an environmental cleanup company to complete the work. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Form 10-K includes statements that are not purely historical and 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, including statements regarding our expectations, hopes, beliefs, intentions or strategies regarding the future. From time to time we also make verbal forward-looking statements. All statements other than statements of historical facts included in this Form 10-K or otherwise stated by HSR are forward-looking statements, including without limitation, statements under Item 3. "Legal Proceedings and Environmental Issues," Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Item 8. "Financial Statements and Supplementary Data -- Notes to Consolidated Financial Statements." These statements may concern, among other things: - reserves, their values and expected growth; - planned capital expenditures and allocations; - increases in oil and gas production; - planned expansions of gathering, transmission and processing facilities; - production economics; - expected drilling opportunities; - trends or expectations concerning oil and gas prices or market characteristics; - marketing, hedging and trading risks, strategies, policies and procedures; - our financial position, stability of cash flow, debt service capabilities and capital availability; 29 30 - the amount of expected Section 29 tax credit payments; - the ability to manage risk through hedging and similar activities; - business strategy and other plans and objectives for future operations; - planned acquisitions; - potential liabilities or the expected absence thereof; and - the potential outcome of environmental matters, litigation or other proceedings. All forward-looking statements included in this Form 10-K or otherwise stated by us are based on information available to us on the date hereof or at the time verbal statements are made, and we assume no obligation to update such forward-looking statements. Although we believe the forward-looking statements are based on reasonable assumptions, we can give no assurance that our expectations will prove to have been correct or that we will take any actions that may presently be planned. Actual results may differ materially from any forward-looking statements made by us depending on a variety of factors, including, among others, the factors discussed in "Certain Considerations." CERTAIN CONSIDERATIONS Volatility Of Oil And Gas Prices; Marketability Of Production. Oil and gas prices can be extremely volatile and have recently been significantly higher than 1999 levels. Gas prices affect us more than oil prices, because most of our production and reserves are gas. At December 31, 2000, approximately 79% of our estimated reserves were gas and approximately 79% of our total production during 2000 was gas. However, oil prices can affect the price of liquids extracted from gas, and thus can affect the overall revenue we realize from gas sales. Our revenues, profitability and future rate of growth depend substantially upon prevailing prices for our oil and gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. We cannot predict future oil and gas prices. Factors that cause this fluctuation include: - changes in supply and demand; - the level of consumer product demand; - market uncertainty; - weather conditions; - gas storage levels and rates of injection and drawdown; - federal and state regulation of oil and gas production and transportation; - the price and availability of alternative fuels or energy sources; - political conditions in the Middle East and other international producing regions; - the foreign supply of oil and gas; - the price of oil and gas imports; - actions of state and local agencies, the United States and foreign governments and international cartels; and - general economic conditions both in the United States and throughout the world. These external factors and the volatile nature of the energy markets make it impossible to forecast accurately future prices of oil and gas. Prices for D-J Basin gas, which represents a significant portion of our 30 31 overall production, have at times been more volatile than the prices prevailing in the broader United States gas market, however this has not been the case in recent months. Although from time to time we hedge a portion of our oil and gas production to provide some protection from price fluctuation, any substantial or extended decline in the price of oil or gas would have a material adverse effect on our financial condition and results of operations. Hedging arrangements may limit the risk of declines in pricing, but also may limit further revenues from price increases. In 2000, for example, hedging reduced the revenue we would otherwise have received from the generally high prices by $72.5 million, but afforded substantial protection against price declines. The marketability of our production depends upon the availability and capacity of refineries, gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand all could adversely affect our ability to produce and market our oil and gas. If market factors were to change dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control and thus represent a significant risk. Effects Of Leverage; Existing Indebtedness. As of December 31, 2000, our total long-term debt was approximately $495.3 million. Our level of debt has important consequences, including the following: (i) our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes may be impaired; (ii) a portion of our cash flow from operations must be dedicated to the payment of the principal of and interest on our existing debt; (iii) certain of our borrowings, principally those under our revolving credit facility, are at variable rates of interest, which may make us vulnerable to increases in interest rates; and (iv) the terms of certain of our indebtedness permit our creditors to accelerate payments upon certain events of default or a change of control. As of December 31, 2000, $59.0 million, or 16.2%, of our long-term debt bears interest at floating rates. This does not include an additional $130.0 million that also bears interest at floating rates, but against which we have entered into interest rate hedging agreements. Together, without considering the effect of those interest rate hedging agreements, $189.0 million, or 38.2% of our long-term debt, is characterized by floating rate obligations. Interest rates on our debt ranged from 7.03% to 9.875% per annum in 2000. Our Chase revolving credit facility, and the indentures under which our 9 1/4% Senior Subordinated Notes due 2006 and 9 7/8% Senior Subordinated Notes due 2003 were issued, impose financial and other restrictions on us and our subsidiaries, including limitations on the incurrence of additional indebtedness and limitations on the sale of assets. The Chase facility and the indentures also require us to make periodic payments of interest. Our Chase facility also requires us to: (i) make principal payments from the proceeds of certain asset sales and in the event our outstanding debt exceeds the borrowing base; (ii) maintain certain financial ratios, including interest coverage and leverage ratios; and (iii) maintain a minimum level of consolidated cash flow. We cannot assure you that these requirements or other material requirements of our Chase facility will be met in the future. If they are not, the lenders would be entitled to declare the indebtedness thereunder immediately due and payable. Additionally, in the event of such an acceleration of indebtedness by the lenders under our revolving credit facility, a default would be deemed to occur under the terms of the 9 1/4% Notes and the 9 7/8% Notes. In addition, the indentures contain certain restrictive covenants that may limit our ability to engage in certain transactions. 31 32 Based upon the current and anticipated level of operations, we believe that our cash flow from operations, together with the proceeds available under our Chase facility and other sources of liquidity, will be adequate to meet our anticipated requirements in the foreseeable future for working capital, capital expenditures, interest payments and scheduled principal payments. We cannot assure you, however, that our business will continue to generate cash flow at or above current levels. If we are unable to generate sufficient cash flow from operations to pay our debt, we would be required to refinance all or a portion of our existing debt (provided the necessary consents are obtained), or to obtain additional financing, or to sell substantial assets. There can be no assurance that a refinancing would be possible or that any additional financing could be obtained. Our ability to pay our debt and reduce total indebtedness depends not only upon our future drilling and production performance, but also on oil and gas prices, general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control. Our strategy and historical focus has been, and is expected to continue to be, the development, acquisition, exploitation, exploration, production and marketing of oil and gas. Each of these activities requires substantial capital. We intend to finance such capital expenditures in the future through cash flow from operations, the incurrence of additional indebtedness and/or the issuance of additional equity or equity-linked securities. Estimation Of Reserves. The reserve data in this Report on Form 10-K are calculated estimates only. There are numerous uncertainties in estimating quantities of proved reserves, future rates of production and the timing and success of development expenditures, including many factors beyond our control. Although we believe that all of our reserve estimates are reasonable, reserve estimates are only estimates and should be expected to change as additional information becomes available. Furthermore, estimates of oil and gas reserves, of necessity, are projections based on engineering, geologic and production data, and the interpretation thereof, the projection of future rates of production and the timing and success of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be exactly measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, estimates of the economically recoverable quantities of oil and gas attributable to any particular property or group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom, which are prepared by different engineers or by the same engineers at different times, may vary substantially. Moreover, we cannot assure you that the reserves set forth herein will ultimately be produced or that the proved undeveloped reserves will be developed within the periods anticipated. Variances from the estimates contained herein could be material. In addition, the estimates of future net revenues from our proved reserves and the present value of these reserves are based upon certain assumptions about production levels, prices and costs, which may be inaccurately estimated and which are dictated by SEC regulations. These regulations are intended to create a uniform measure from company to company for comparison purposes and are not intended to be an estimate of value. The discounted future net cash flows should not be construed as representative of the fair market value of our proved oil and gas properties, as discounted future net cash flows are based upon year end prices which may vary significantly from realized average prices or estimates of future prices. Year end prices in 2000, for example, were significantly higher than the average prices we received during 2000 and that we expect to realize on average in the near future. These estimates of future net revenues also do not take into account possible future changes in expenses and capital costs. The accuracy of these estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Considerations -- Volatility of Oil and Gas Prices; Marketability of Production" and "Risks of Hedging and Trading Transactions." Replacement Of Reserves. Our future performance depends in part upon our ability to acquire, find and develop additional oil and gas reserves that are economically recoverable. Without successful acquisition, exploration or development activities, our reserves will decline over time. We cannot assure you that we will be able to acquire or find and develop additional reserves on an economic basis. 32 33 Our business is capital intensive and, to maintain our asset base of proved oil and gas reserves, a significant amount of cash flow from operations must be reinvested in development or exploration activities or property acquisitions. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain or expand our asset base would be impaired. Without such investment, our oil and gas reserves will decline over time. Our strategy will include continued exploitation and exploration of our existing properties and may include opportunistic acquisitions of other oil and gas properties. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are necessarily inexact and their accuracy inherently uncertain. We cannot assure you that our acquisition activities and exploration and development projects will result in increases in reserves. Our operations may be curtailed, delayed or canceled as a result of a lack of adequate capital and other factors, such as title problems, weather, compliance with governmental regulations or price controls, mechanical difficulties or shortages or delays in the delivery of equipment. Furthermore, while our revenues may increase if prevailing gas and oil prices increase significantly, our finding costs for additional reserves could also increase. In addition, the costs of exploration and development may materially exceed initial estimates. Risks Of Hedging And Trading Transactions. In order to manage our exposure to price risks in marketing our oil and gas and in connection with our trading activities, we have in the past entered into and may in the future enter into oil and gas futures contracts on the New York Mercantile Exchange, fixed price delivery contracts and financial swaps. Those transactions that are intended to reduce the effects of volatility of the price of oil and gas may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. For the year ended December 31, 2000, for example, our hedge positions reduced our overall receipts from oil and gas sales by $72.5 million, although the hedges provided substantial protection from a reduction in prices below the hedged price. As of January 1, 2001, all of our derivative instruments have been marked to market and the impact will be reflected in our financial statements as described in Notes 2 and 4 to the Financial Statements. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Management/Hedging." In addition, our hedging and trading may expose us to the risk of financial loss in certain circumstances, including instances in which: (i) production is less than expected and therefore is less than our hedged volumes; (ii) there is a widening of price differentials between delivery points for our production and the points at which the hedges are priced, such as Henry Hub in the case of NYMEX futures contracts or delivery points required by fixed price delivery contracts; (iii) our customers or the counterparties to our futures contracts fail to purchase or deliver the contracted quantities of oil or gas or to honor their financial commitments; (iv) a sudden, unexpected event materially affects oil or gas prices; or (v) a person connected with our trading activity fraudulently or otherwise circumvents our controls and causes losses from unauthorized hedging or trading activity. Governmental And Environmental Regulation. Our operations are subject to various federal, state and local governmental laws and regulations, which may be changed from time to time in response to economic or political factors. Matters subject to regulation include, but are not limited to, drilling and operations permits and approvals, performance bonds, reports concerning operations, discharge and other permitting requirements, the spacing of wells, distance from other structures or activities, unitization and pooling of properties, zoning or similar regulations and taxation. Our operations are also subject to complex and constantly changing environmental and health and safety laws and regulations adopted by federal, state and local governmental authorities. For example, our pipeline operations may be subject to recently adopted stricter emissions control and monitoring requirements under the Clean Air Act. Compliance with such laws has not had a material adverse effect 33 34 upon HSR to date. Nevertheless, the discharge of oil, gas or other pollutants into the air, soil or water or impacting wetlands may give rise to significant liabilities of HSR to the government and/or third parties, and may require us to incur substantial costs for remediation. Moreover, we have agreed to indemnify certain sellers of producing properties from whom we have acquired properties against certain liabilities for environmental claims associated with the acquired properties. We cannot assure you that existing environmental health or safety laws or regulations, as currently interpreted or as may be in the future, or future laws or regulations will not materially adversely affect our results of operations and financial condition or that material indemnity claims will not arise against us with respect to acquired properties. Many of the cities, towns and counties in Colorado affected by oil and gas development have also enacted ordinances and established regulations and procedures that affect oil and gas operations. In general, these measures make oil and gas development more difficult. While we believe that some of these measures are invalid, their existence may adversely affect our activities unless they are judicially invalidated or are repealed. California Energy Crisis. The majority of our oil and gas sales are made to companies with investment grade credit ratings, none of which, to our knowledge, are subject to the energy crisis in California and the credit problems that have developed as a result. Nevertheless, our sales are, for the most part, sold on an unsecured basis. If the companies to which we sell oil or gas should become subject to financial stress, we might not receive payment for sales of our product. Although we generally have the right to demand collateral once a credit problem is recognized, we might not become aware of a credit problem sufficiently early for these protections to be effective. Although we currently believe that our sales and revenue are not likely to be affected by problems resulting from the California energy crisis, or similar problems elsewhere, these types of problems are inherently unpredictable, could happen and could have a material adverse effect on us. High Prices and Price Regulation. The increase in the cost of oil and gas in 2000 has caused some people to call for new types of price controls on these products. While we are unaware of any significant political momentum behind these statements, there is a risk that such a political force could develop and could cause price or other controls to be placed on oil or gas. Such controls could have a material adverse effect on us. Operating Hazards; Uninsured Risks. Oil and gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the following: - no commercially productive oil or gas reservoir may be found; - oil and gas drilling and production activities may be delayed or canceled; - title problems may delay or prohibit drilling, cause a loss of ownership interest in a well, or cause other problems or losses; - weather problems may interfere with drilling or production; - mechanical difficulties or shortages or delays in the delivery of drilling rigs and other equipment may occur; and - pipeline and compressor equipment may fail, causing a reduction in or interruption of deliveries to market and the shutting in of wells. We cannot assure you that the new wells we drill will be productive or that we will recover all or any of our investment. Drilling for oil or gas may be unprofitable. Dry holes and wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs are unprofitable. In addition, our properties may be susceptible to oil and gas drainage from production by other operators on adjacent lands. Our operations are subject to hazards and risks inherent in drilling for and production and transportation of oil and gas, such as fires, natural disasters, explosions, encountering formations with 34 35 abnormal pressures, blowouts, cratering, pipeline or compressor failures and spills, equipment or vehicle accidents, any of which can result in loss of oil and gas, environmental pollution, personal injury claims and other damage or impacts to our properties and others, including suspension of operations. The business is also subject to environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, which could expose us to substantial liability due to pollution and other environmental damage. Our insurance coverages include, but are not limited to, comprehensive general liability, automobile, personal injury, bodily injury and property damage, pollution liability, physical damage on certain assets, workers' compensation and control of well insurance. We believe that our insurance is adequate and customary for companies of a similar size engaged in operations similar to ours, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Competition. The oil and gas industry is highly competitive. We compete in the areas of property acquisitions and the exploration, exploitation, development, production and marketing of oil and gas with major oil companies, other independent oil and gas concerns and individual producers and operators. We also compete with these companies in recruiting and retaining qualified employees. Many of these competitors have financial and other resources substantially greater than ours. 35 36 CERTAIN DEFINITIONS The terms defined in this section are used throughout this report. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bcf. Billion cubic feet of gas. Behind-pipe reserves. Proved reserves in a formation through which production casing has already been set in the wellbore, but from which production has not commenced. Boe. Barrels of oil equivalent, determined using the ratio of six Mcf of gas (including natural gas liquids) to one Bbl of crude oil or condensate. Btu. British thermal unit or units. One Btu is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit. COPAS charges. The fixed amount that an operator is allowed to charge nonoperators or itself to cover general and administrative expense. COPAS refers to the Council of Petroleum Accountants Societies, which prescribes the basic contract terms applicable to these charges and prescribes an annual escalation factor. Development location. A location on which a development well can be drilled. Development well, development drilling. Drilling of a well within the proved area of an oil or gas reservoir to the stratigraphic depth of a horizon known to be productive in an attempt to recover undeveloped reserves. Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Estimated future net revenues. Revenues from production of oil and gas, net of all production-related taxes, lease operating expenses and capital costs. Exploitation well or exploitation drilling. Drilling of wells in areas of known production. However, because of geologic, reservoir and other characteristics it is possible that an exploitation well may not encounter commercial quantities of reserves. Therefore such wells carry somewhat greater risk than development drilling. Oil and gas reserves associated with exploitation wells are not typically considered to be proved. Exploratory well or exploratory drilling. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir beyond existing defined limits. Finding cost. The capital costs associated with finding and developing oil and gas reserves. Gross acre. An acre in which a working interest is owned. Gross well. A well in which a working interest is owned. Held by production. Acreage covered by an oil and gas lease which has a producing well on it, or which is pooled with a lease or leases having one or more producing wells on them, so the lease is maintained in effect for the duration of such production. Henry Hub. The delivery point of the NYMEX gas contract, located in southern Louisiana. Infill or increased density drilling. Somewhat similar to development drilling, infill drilling involves wells drilled within the proved area of an oil or gas reservoir to a zone known to be productive. Infill drilling generally involves an increase in well density based on engineering and geological studies that demonstrate that the existing well density does not adequately drain the reservoir. 36 37 Lease operating expense or LOE. All direct costs associated with and necessary to operate a producing property. MBbl. One thousand barrels of crude oil or other liquid hydrocarbons. MBoe. One thousand barrels of oil equivalent. Mcf. One thousand cubic feet of gas. Mcfe. One thousand cubic feet of gas equivalent, determined using the ratio of one Bbl of crude oil equals six Mcfe (including natural gas liquids). MMBbl. One million barrels of crude oil or other liquid hydrocarbons. MMBoe. One million barrels of oil equivalent. MMBtu. One million Btu. MMcf. One million cubic feet of gas. MMcfe. One million cubic feet of gas equivalent. Multi-pay horizons. A wellbore with more than one zone that may potentially produce hydrocarbons. Net acres or net wells. The sum of the working interests owned in gross acres or gross wells. Net cash flow. Net cash flow is defined as net income plus geological and geophysical costs, exploratory and abandonment costs, depletion, depreciation and amortization, impairment and gain/loss on sale, income taxes and extraordinary items. Present value of estimated future net revenues, pretax present value at constant prices of estimated future net revenues. Estimated future net revenues before income taxes, discounted using a factor of ten percent per annum and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the Securities and Exchange Commission. Productive well. A well that is producing or that is capable of producing oil or gas. Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves. The estimated quantities of crude oil, 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. Proved undeveloped location. A site on which a development well can be drilled consistent with local spacing rules for the purpose of recovering proved reserves. Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to establish production. Recompletions. Within an existing wellbore, a recompletion involves completion for production of a formation other than those which have previously been productive. It is the mechanism by which behind-pipe reserves become productive. Refrac. Within an existing wellbore, a refrac involves a new hydraulic fracture stimulation of a formation that was previously fracture stimulated. Reserve replacement costs. Total costs incurred for exploration and development, divided by reserves added from all sources, including reserve discoveries, extensions and improved recovery additions, net of revisions to reserve estimates and purchases of reserves in place. Royalty interest, overriding royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and gas production free of costs of drilling, completion and production. 37 38 Tcf. One trillion cubic feet of gas. Tcfe. One trillion cubic feet of gas equivalent. 3-D seismic studies or projects. 3-D seismic projects involve the use of seismic reflections in three dimensions to assist in mapping the structural and stratigraphic aspects of certain reservoirs lending themselves to the application of this advanced technology. Particularly when coupled with advanced processing, interpretation, geostatistical techniques and interpretive geology, this technology can materially reduce the risk associated with some types of drilling. Undeveloped acres. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves. Wattenberg. The geographic region in the D-J Basin located approximately 35 miles north and east of Denver, where the J Sand formation is productive, as well as adjacent areas where the Codell, Niobrara, Sussex and Shannon formations are productive. Wellbore extension. A wellbore extension involves deepening an existing wellbore to a new and deeper formation. Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and entitles it to ownership of a share of production. 38 39 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders of HS Resources, Inc.: We have audited the accompanying consolidated balance sheets of HS Resources, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of HS Resources, Inc. and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Denver, Colorado, February 9, 2001. 39 40 HS RESOURCES, INC. CONSOLIDATED BALANCE SHEETS ASSETS

The accompanying notes are an integral part of these consolidated financial statements. 40 41 HS RESOURCES, INC. CONSOLIDATED BALANCE SHEETS LIABILITIES AND STOCKHOLDERS' EQUITY

The accompanying notes are an integral part of these consolidated financial statements. 41 42 HS RESOURCES, INC. CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31,

The accompanying notes are an integral part of these consolidated financial statements. 42 43 HS RESOURCES, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31,

The accompanying notes are an integral part of these consolidated financial statements. 43 44 HS RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,

The accompanying notes are an integral part of these consolidated financial statements. 44 45 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 -- THE COMPANY HS Resources, Inc. ("HSR"), a Delaware corporation, was organized in January 1987. We, directly or through subsidiaries, acquire, develop, exploit, explore for and produce oil and gas properties. Our primary properties are located in the Denver-Julesburg ("D-J") Basin, the onshore area of the Texas-Louisiana Gulf Coast, and to a lesser extent the Mid-Continent and Northern Rocky Mountains. Through our wholly-owned subsidiaries, HS Gathering L.L.C. and Resource Gathering Systems, Inc., we gather and transport our own and third party gas. Through our subsidiary, HS Energy Services, Inc. ("HSES"), we market our own gas production, market gas owned by third parties and actively trade both physical and financial positions in the gas commodities market. NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES We utilize the successful efforts method of accounting for our oil and gas properties. Consequently, leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas, and impairments in value are charged to expense. Exploratory costs, geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. Costs of developmental dry holes and proved leaseholds are amortized on the unit-of-production method based on proved reserves on a field by field basis. The depreciation of capitalized drilling costs is based on the unit-of-production method using proved developed reserves on a field by field basis. We follow Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS 121 requires us to assess the need for an impairment of capitalized costs of oil and gas properties and other assets. Oil and gas properties are generally assessed on a property-by-property basis. If an impairment is indicated based on undiscounted expected future net cash flows, it is recognized to the extent that net capitalized costs exceed discounted expected future net cash flows. During 2000 and 1998 we recorded impairments of $1.5 million and $5.3 million, respectively, whereas during 1999 no impairments were recorded. During 2000, 1999 and 1998 we capitalized $6.4 million, $7.1 million and $11.7 million, respectively, of interest relating to undeveloped acreage. Income Taxes. We follow the liability method of accounting for income taxes. Accordingly, deferred tax provisions or benefits are recognized in the financial statements for the change in deferred tax liabilities or assets during each year. The deferred liabilities or assets represent taxes payable or refundable in future years, as measured by the provisions of enacted tax laws, or as a result of temporary differences between the basis of assets and liabilities for financial reporting and tax reporting purposes. Such differences relate mainly to depreciable and depletable properties and intangible drilling costs. Cash Equivalents. Cash and cash equivalents include cash on hand, amounts held in banks and highly liquid investments purchased with an original maturity of three months or less. Margin Deposits. We use energy related financial instruments to reduce our exposure to price risk related to natural gas. Margin deposits consist of monies on deposit with brokers that are restricted to meet exchange trading requirements (see Note 4). Financial Instruments. We engage in price and location risk management activities for both hedging and trading purposes. We enter into derivative instruments for hedging purposes in order to manage our exposure to price and location risks in the marketing of our oil and gas production and, in the case of our marketing activities, third party gas. Gains and losses on hedging positions are deferred and recognized in the period the underlying physical transactions occur in "oil and gas sales" (for company-owned production) and "trading and transportation revenues" (for third party gas). Activities for trading purposes 45 46 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) are accounted for using the mark-to-market method. Under this method, changes in the market value of outstanding financial instruments are recognized as a gain or loss in the period of change on a net basis in "trading and transportation revenues." The market prices used to value these transactions reflect management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions. In the event energy related financial instruments are terminated prior to the period of physical delivery of the items being hedged, the gains or losses on the energy related financial instruments at the time of the termination remain deferred until the period of physical delivery unless both the energy related financial instruments and the items being hedged result in a loss. If this occurs, the loss is recorded immediately. Earnings Per Share. SFAS No. 128, "Earnings Per Share," provides computation, presentation and disclosure requirements for earnings per share ("EPS"). In the fiscal years ended December 31, 2000 and 1999, the dilutive impact was 672,000 and 191,000 shares, respectively. These dilutive securities are options and warrants. There was no dilutive impact to weighted average shares for the fiscal year ended December 31, 1998. Deferred Charges. Legal and accounting fees, printing costs and other expenses associated with the issuance of our debt have been capitalized and are being amortized over the remaining term of the debt. Gas Gathering And Transportation Facilities. Depreciation of gas gathering and transportation facilities is provided using the straight-line method over estimated useful lives of 20 years. Office And Transportation Equipment. Depreciation of office and transportation equipment is provided using the straight-line method over estimated useful lives which range from three to ten years. Goodwill. In connection with the 1996 merger with Tide West Oil Company, we recorded goodwill of $3.6 million attributable to its trading and marketing subsidiary, HSES. Such amount is amortized on a straight-line basis over 10 years. Gas Imbalances. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on actual production sold. At December 31, 2000, HSR's gas balancing position was approximately 59,024 MMBtu underproduced. Use Of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles 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. New Accounting Standards. In June 1998, the FASB issued SFAS 133, which has been amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of SFAS 133." SFAS 133 requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS 133 is effective for fiscal years beginning after June 15, 2000 and must be applied to: (a) derivative instruments; and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after December 31, 1998. Prior to January 1, 2001, we completed the process of identifying all derivative instruments, determining fair market values of derivatives, designating and documenting hedge relationships, and evaluating the effectiveness of those hedge relationships. As required, we adopted SFAS 133 as of January 1, 2001. 46 47 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) SFAS 133 requires that as of the date of initial adoption, the difference between the fair market value of derivative instruments recorded on the balance sheet and the previous carrying amount of those derivatives be reported as a transition adjustment in net income or other comprehensive loss, as appropriate, as the cumulative effect of a change in accounting principle in accordance with APB 20, "Accounting Changes." We use financial derivative instruments to mitigate commodity price risk related to the purchase or sale of natural gas. Many of these instruments are designated as hedges of the anticipated purchases or sales of the commodity. On January 1, 2001, the fair market values of these derivative instruments were recorded as assets and liabilities on the balance sheet and in the transition adjustment in accordance with the transition provisions of SFAS 133. Future changes in the fair market values of these instruments, to the extent that the hedges are effective at mitigating the underlying commodity risk, will be recorded in other comprehensive income. At the date the underlying transaction occurs, the amounts accumulated in other comprehensive loss will be reported in the Consolidated Statements of Operations. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value will be recorded directly in operations. The financial statement impact of recording the various SFAS 133 transactions at January 1, 2001 is as follows (in millions):

In September 2000, the Emerging Issues Task Force reached consensus on Issue No. 00-10, "Accounting for Shipping and Handling Fees and Costs" ("EITF Issue 00-10"). EITF Issue 00-10 requires retroactive restatement of transportation costs as an expense rather than as a reduction to revenue. HSR implemented EITF Issue 00-10 in the fourth quarter of 2000 and all prior periods have been restated with offsetting increases in oil and gas sales revenue and gas transportation and gathering expenses, resulting in no impact to net earnings. NOTE 3 -- ACQUISITIONS AND DIVESTITURES Acquisition Of Gas Gathering And Transmission Assets. On November 26, 1999, we acquired certain gas gathering and transmission assets (the "WGS") from Kinder Morgan, Inc. and affiliated entities ("KMI") for an adjusted purchase price of approximately $48 million plus the future assumption of an operating lease which then had a present value of $19 million. WGS consists of a low pressure gathering system and a high pressure transmission system. The low pressure gathering system consists of more than 1,500 miles of pipeline and 3,000 horsepower of compression, located in five northeastern Colorado counties. Gas is delivered to the inlet of the high pressure transmission system, which consists of almost 60 miles of high pressure pipeline and almost 40,000 horsepower of compression. The acquisition is being accounted for using the purchase method of accounting. Along with the system, we acquired a 6.9% interest in the BP Wattenberg gas processing plant, and a right of first refusal to purchase the remaining interest in the plant. Sale Of HSRTW, Inc. On July 28, 1998, we announced the sale of our Mid-Continent oil and gas subsidiary, HSRTW, Inc., to Universal Resources Corp., a subsidiary of Questar Corp., for $157.5 million in 47 48 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) cash. HSRTW, Inc. owned interests in approximately 1,000 wells located in the Anadarko and Arkoma basins of Oklahoma and in Texas, with approximately 32 MMBoe of proved reserves as of year-end 1997. The transaction closed and was effective on September 1, 1998, with net proceeds applied to the repayment of bank debt. We retained our ownership of HSES, the Tulsa-based gas trading and marketing subsidiary of HSRTW, Inc. NOTE 4 -- RISK MANAGEMENT We use financial instruments to reduce our exposure to market fluctuations in the price and transportation cost of oil and gas. Our general strategy is to hedge price and location risk of a portion of our production with swap, collar, floor and ceiling arrangements. We generally enter into hedges for delivery into one of several pipelines located near our producing regions, Panhandle Eastern Pipeline Company ("PEPL"), Northwest Pipeline Corporation ("NW"), Colorado Interstate Gas Company ("CIG"), or at the New York Mercantile Exchange ("NYMEX") prices settled at the Henry Hub. With respect to the NYMEX hedged volumes that exceed our Gulf Coast volumes, we usually hedge basis to our producing regions, although perfect hedges are not always available. Gains and losses on hedging positions are recognized in the period during which the underlying transactions occur and are booked in "oil and gas sales" (for company-owned production) and "trading and transportation revenues" (for third party gas). Hedging contracts for our production reduced our oil and gas sales by $72.5 million and by $6.1 million in 2000 and 1999, respectively and increased our oil and gas sales by $9.0 million in 1998. Hedging contracts for third party gas increased trading and transportation revenues by approximately $0.8 million, $0.04 million and $0.3 million in 2000, 1999 and 1998, respectively. 48 49 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) As of December 31, 2000, we held specific swap positions as follows: GAS HEDGES

GAS BASIS HEDGES

49 50 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Additionally, with respect to the hedging of third party gas, we have hedged 80.1 Bcf from January 2001 through October 2002 with offsetting physical positions at settlement prices that are based upon NYMEX future prices or other published indices. The fair market value of these hedges at December 31, 2000 was a gain of approximately $17.6 million, which will be recorded in our financial statements at the expiration of the underlying contracts. In addition to using financial instruments to reduce our exposure to market fluctuations in the price of oil and gas, we have also entered into future sales contracts to be settled by physical delivery covering a portion of our production as follows: GAS SALES

OIL SALES

Trading Activities. We engage in the trading of various energy related financial instruments that require payments to (or receipt of payments from) counterparties based on the differential between a fixed and a variable price for the commodity, swap or other contractual arrangement. We have established policies with respect to open positions which limit our exposure to market risk and require daily reporting to management of the potential financial exposure resulting from both hedging and trading activities. Our policy requires that, within defined trading limits, financial instrument purchase and sales contracts be balanced in terms of contract volumes and the timing of performance and delivery obligations. Activities for trading purposes are accounted for using the mark-to-market method. Under this method, changes in the market value of outstanding financial instruments are recognized in "trading and transportation revenues" as a net gain or loss in the period of change. The market prices used to value these transactions reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions. For the years ended December 31, 2000, 1999 and 1998, net gains of $4.4 million, $3.3 million and $2.8 million, respectively, were recognized in connection with financial trading activities and are included in "trading and transportation revenues." Credit Risk. While notional amounts are used to express the volume of various derivative financial instruments, the amounts potentially subject to credit risk in the event of nonperformance by the third parties are substantially smaller. Counterparties to the swap, collar, floor and ceiling arrangements discussed above are generally investment grade institutions. Accordingly, we do not anticipate any material impact to our financial position or results of operations as a result of nonperformance by the third parties to financial instruments related to hedging activities or trading activities. See also "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Considerations -- California Energy Crisis." 50 51 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 5 -- LONG-TERM DEBT Long-term Bank And Other Debt. Debt at December 31, 2000 and 1999 consisted of the following (in thousands):

Bank Debt. On June 7, 1996, we entered into a revolving senior term credit facility with The Chase Manhattan Bank, as Agent (the "Chase Facility") which has been subsequently amended. The interest rates payable thereunder are, at HSR's election, The Chase Manhattan Bank Base Rate plus 0% to 0.625%, or LIBOR plus 0.75% to 1.625%. Under the terms of the Chase Facility, no principal payments are required until December 15, 2002, assuming we maintain a borrowing base sufficient to support the outstanding loan balance. The borrowing base is currently $325.0 million and is based on the underlying value of our oil and gas properties. This borrowing base is usually reviewed for potential revision annually. Payable To KMI. Payments to KMI are specified in an operating services agreement, with certain contractual obligations between HSR and KMI. As specified in the agreement, actual payment amounts will be made monthly through December 2001 with amounts varying depending upon system throughput. The obligation to KMI represents the present value of contractually defined net payments based on an assumed volume of throughput discounted at an imputed interest rate of approximately 11.8%. Interest Rate Swaps. During the fourth quarter of 1998, we entered into an interest rate exchange agreement with a financial institution to hedge the interest rate on $80 million of our borrowings at 5.86% through December 15, 2006. In the first quarter of 1999, we entered into an interest rate exchange agreement with a financial institution to hedge $50 million of our borrowings at 5.66% through March 31, 2004. Under the terms of the agreements, the difference between our fixed rate and the one-month LIBOR rate is received or paid by us. The mark-to-market value of our interest rate swaps as of December 31, 2000 was $0.2 million. Market risk related to borrowings from a one percent change in interest rates would result in an approximate $0.6 million annual impact on pre-tax income based on the quarter end borrowing level and the amount of such borrowings which are not subject to interest rate swaps. Senior Subordinated Notes. In November 1993, we issued $75 million of our 9 7/8% senior subordinated notes due in 2003. The notes pay interest semi-annually on June 1 and December 1. In November 1996, we issued $150 million of our 9 1/4% senior subordinated notes due in 2006. The notes pay interest semi-annually on May 15 and November 15. In December 1998, we issued $85 million of our 9 1/4% Series B 51 52 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) senior subordinated notes due in 2006. The notes pay interest semi-annually on May 15 and November 15. The proceeds of the notes were used to replace with fixed rate term debt a portion of the outstanding indebtedness under our bank credit facility. Carrying Values. At December 31, 2000 and 1999, the carrying amount of our 9 7/8% senior subordinated notes was $74.8 million and $74.8 million and the estimated fair value was $75.8 million and $74.8 million, respectively. At December 31, 2000 and 1999, the carrying amount of the 9 1/4% Series A senior subordinated notes was $149.5 million and $149.5 million and the estimated fair value was $151.1 million and $148.5 million, respectively. At December 31, 2000 and 1999, the carrying amount of the 9 1/4% Series B senior subordinated notes was $81.9 million and $81.3 million and the estimated fair value was $85.2 million and $84.0 million. The fair value is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. Due to the unique nature of the KMI indebtedness, the fair value is not determinable. Based on borrowing rates available for bank loans with similar collateral, the fair value of the borrowing under the bank debt at December 31, 2000, is estimated to be its carrying value of $189.0 million. Our credit facility currently prohibits payment of dividends and the indentures governing our outstanding 9 1/4% and 9 7/8% senior subordinated notes due in 2006 and 2003, respectively, also limit our ability to pay dividends. Maturities of debt are as follows at December 31, 2000:

NOTE 6 -- STOCKHOLDERS' EQUITY Series A Convertible Participating Preferred Stock. We have authorized 15 million shares of $.001 par value Series A convertible preferred stock, of which no shares are currently issued or outstanding. The stock has a stated value of $13.50 per share and a liquidation preference of $1.00 per share. Series A Junior Preferred Stock. In February 1996, we authorized 300,000 shares of Series A junior preferred stock. The stock shall be issuable upon exercise of rights (the "Rights") issued pursuant to the agreement dated as of February 28, 1996, between HSR and Harris Trust Company of California, as Rights Agent (the "Rights Agreement"). The Rights Agreement was designed to protect our shareholders in the event of takeover action that would deny them the full value of their investment (the "Rights Plan"). Terms of the Rights Plan provide for a dividend distribution of one right for each share of HSR common stock to holders of record at the close of business on March 14, 1996. The Rights will automatically become part of and traded with existing and future shares of our common stock. The Rights will become exercisable only in the event, with certain exceptions, an acquiring party accumulates 15% or more of HSR's voting stock, or if a party announces an offer to acquire 30% or more of our voting stock. No separate rights certificates will be issued until at least one of these thresholds is met. The Rights will expire on March 14, 2006. 52 53 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Under the Rights Plan, if any person or group becomes the beneficial owner of 15% or more of our common stock, or in the event of a merger or other business combination, each right will entitle the holder other than the acquiring party to purchase either our stock or shares in an "acquiring entity" at a 50% discount of the then current market value. We will be entitled to redeem the rights at $0.01 per right at any time prior to such time that a person or group acquires a 15% position in our voting stock. Warrants. All outstanding warrants were exercised in 2000. As of December 31, 1999 and 1998, 6,000 warrants were outstanding and exercisable at $6.67 per share. Restricted Stock. In 2000, 1999 and 1998 we issued 26,483, 33,984 and 32,126 shares of restricted stock and recorded approximately $524,000, $301,000 and $428,000 of deferred compensation, respectively. The amounts recorded as deferred compensation represent the difference between the deemed fair value for accounting purposes and the stock price as determined by us at the date of grant. Such amounts are presented as a reduction of stockholders' equity and will be amortized over the vesting period of the related stock. In 2000, 1999 and 1998 we amortized approximately $260,000, $220,000 and $136,000, respectively. Issuance Of Performance Shares. In May 1998, our stockholders approved amendments to the Amended and Restated 1997 Performance and Equity Incentive Plan (the "Plan"). The Plan allows for the issuance of performance shares to employees, officers and directors. Accelerated vesting of such shares is dependent on the attainment by us of defined performance goals. These shares have a base vesting schedule over nine years with accelerated vesting to occur no earlier than one-fourth of the shares in each of the first four years. In 1998, we issued 106,234 performance shares. In connection with this issuance, we recorded deferred compensation of $1.5 million, which is being amortized based on management's evaluation regarding the attainment of the defined performance goals. In April 1999, following our change to successful efforts accounting, the earnings measure for determining return on equity as originally stated in the 1998 amendments to the Plan was changed to allow that value measure to operate as originally intended. Following that change, the Board of Directors determined that the 1998 value measures applicable to the performance shares issued in 1998 were fully met. As a result, one fourth of these performance shares have now vested. Additional amortization expense of approximately $214,000 was recorded in the first quarter of 1999 related to the vesting of these shares. In 2000 and 1999, we issued 100,500 and 132,000 performance shares and recorded deferred compensation of approximately $2.5 million and $1.0 million. In 2000 and 1999, we amortized deferred compensation of approximately $1.2 million and $0.6 million for all performance shares issued assuming full achievement of defined performance goals. The Board of Directors has determined that all performance goals in 1999 and 2000 have been satisfied. Total Return Equity Swaps. In 1999, we entered into three total return equity swap agreements with financial institutions. Under the terms of the first agreement, entered into on February 25, 1999, the financial institution acquired 732,000 shares of our common stock from another investor at a price of $6.0625. Effective April 20, 2000 we repurchased the 732,000 shares of our common stock and recorded the shares into treasury stock. On May 24, 1999, we entered into a second agreement whereby the financial institution acquired 100,000 shares of our common stock from another investor at a price of $11.9875. In addition, on December 1, 1999, we entered into a third agreement whereby a financial institution agreed to acquire on the open market up to 300,000 shares of our common stock at the current market price over a three month period beginning December 2, 1999. As of March 2000 the financial institution had acquired 308,100 shares at a weighted average price of $14.55 per share. In October 2000, we repurchased the 408,100 shares under the second and third agreements and recorded the shares into treasury stock. There are no commitments that remain related to these swaps. 53 54 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 7 -- RELATED PARTY TRANSACTIONS In February 1999, we instituted the 1999 Non-Compensatory Stock Purchase Plan. This plan is designed to enable our officers to purchase stock at fair market value in transactions exempt from Section 16(b) of the Securities Exchange Act of 1934. There have been 500,000 shares of common stock allocated to the plan. The plan is administered by the Compensation Committee of the Board of Directors. In 1999, 235,000 shares of common stock were purchased at prices ranging from $5.625 to $6.50. In connection with the stock purchases, 76,000 shares were purchased for cash. The remaining shares were purchased with the officers paying 15% of the purchase price in cash, and the remainder in the form of full recourse promissory notes. The notes mature on March 3, 2001 and bear interest at the annual rate of 8.5%. In June 1998, in connection with the exercise of stock options, certain of our officers issued to HSR full recourse notes in the amount of $2.1 million. The notes and accrued interest were repaid on or before June 1, 2000. In addition, in December 2000, full recourse notes in the amount of $1.6 million were issued to HSR by certain of our officers in connection with the exercise of stock options. The notes and accrued interest are due and payable to HSR on or before December 31, 2001. The interest rate on these notes is at a fixed rate of 9.5%. Subsequent to December 31, 2000, officer notes and interest in the amount of $1.16 million were repaid to HSR. NOTE 8 -- PROVISION FOR INCOME TAXES The provision for income taxes consists of the following (in thousands):

The deferred income tax expense during the years ended December 31, 2000, 1999, and 1998 results from the following (in thousands):

54 55 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The components of the net deferred tax liability as of December 31, 2000 and 1999 are as follows (in thousands):

The effective tax rate during 2000, 1999 and 1998 differs from the statutory rate of 35% principally because of the effects of state income taxes, net of federal tax benefit. We have net tax operating loss carryforwards aggregating approximately $27.0 million available at December 31, 2000, to offset future taxable income. These carryforwards, if not previously utilized, expire in 2011 through 2019. During 2000, tax benefits resulting from the exercise of stock options by employees resulted in HSR receiving a benefit in our income tax liability of approximately $2.5 million. This resulted in a lower utilization of operating loss carryforwards. We have an alternative minimum tax ("AMT") credit carryforward of approximately $1.6 million. AMT credits can be carried forward indefinitely and may only be used to reduce regular tax liabilities in future years when regular tax payable exceeds AMT payable. We also have a percentage depletion carryforward of approximately $6.0 million which can be used to reduce taxable income in the future and is not subject to expiration. NOTE 9 -- EMPLOYEE BENEFIT PLANS 401(k) And Profit Sharing Plans. Effective June 30, 1989, we adopted two qualified defined contribution plans, the HS Resources, Inc. Employee Investment 401(k) Plan and the HS Resources, Inc. Profit Sharing Plan. Effective August 1, 1998, the two plans were merged together to form the 401(k) and Profit Sharing Plan. Under the new plan employees are eligible to participate upon date of hire. From January 1, 1998 through July 31, 1998, participants could make pretax contributions up to 10%. Effective August 1, 1998 under the new plan pretax contributions increased to 15%. After tax contributions of 1% to 5% remained the same. All annual contributions are subject to IRS annual limitations. Employees may receive matching contributions from us on pre tax dollars only in an amount determined by the Board of Directors. All 401(k) matching contributions are vested 100%. We can also make profit sharing contributions. Such contributions are determined by the Board of Directors and are vested to participants over five years of service. Our contributions are included in general and administrative expenses in the accompanying statements of operations. At December 31, 2000, we accrued approximately $1.3 million for the 2000 401(k) matching contribution. Contributions to the plans were $1.1 million and $0.8 million in 1999 and 1998, respectively. Stock Option Plan. The 1997 and 2000 Performance and Equity Incentive Plans provide for the award of benefits of various types to salaried employees and directors of HSR and our affiliates. These include stock options, stock appreciation rights, restricted shares of our stock, performance shares, performance- 55 56 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) based cash awards and other performance-based stock awards. At year end, 8,152 shares of stock remained authorized for grant under the 1997 Plan and 896,000 shares remained authorized for grant under the 2000 Plan. A prior stock option plan was in effect until April 1997. We have one Director Stock Option Plan, the 1992 Plan, with 38,250 shares of stock remaining authorized for grant at year end. We account for these plans under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations, under which no compensation cost was recognized during 2000, 1999 and 1998. SFAS No. 123, "Accounting for Stock Based Compensation," defines a fair value based method of accounting for employee stock options or similar equity instruments. However, SFAS 123 allows the continued measurement of compensation cost for such plans using the intrinsic value based method prescribed by APB No. 25, provided that pro forma disclosures are made of net income or loss and net income or loss per share, assuming a fair value based method of SFAS 123 had been applied. The following table summarizes activity with respect to outstanding stock options for the years 2000, 1999 and 1998:

56 57 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table reflects the pro forma financial statements, had compensation cost for the stock option plans been determined consistent with SFAS 123, net of the effect of forfeitures and tax (in thousands except per share amounts):

The assumptions used to determine the fair value of each option grant are as follows:

The following table summarizes information about the stock options outstanding at December 31, 2000:

NOTE 10 -- COMMITMENTS AND CONTINGENCIES Environmental Matters. In May 1995, we were named by the Environmental Protection Agency ("EPA") pursuant to a Resource Conservation and Recovery Act administrative order as one of two respondents in addition to the owner/operator of an oilfield production water evaporation facility. The order requires that work be performed to abate a perceived endangerment to wildlife, the environment or public welfare. We and other non-operator respondents have worked together with the EPA to develop characterization studies of the site, and have caused the facility to be permanently closed. HSR and other non-operator respondents have completed substantially all work at the site. We have incurred approximately $1.3 million as of December 31, 2000 for our portion of the costs. This amount has been recorded in our financial statements as of December 31, 2000 and we believe that no substantial liability remains. Additionally, in March of 1999 we became subject to an enforcement action handled by the EPA and the Department of Justice for alleged violations of Section 404 of the Clean Water Act concerning wetlands in Louisiana. The consent decree order resolving the matter has been entered by the federal court in Louisiana. The settlement will not have a material adverse effect on us. In 1999 we accrued an amount in our financial statements that is sufficient to cover the settlement costs. 57 58 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Finally, the gathering and transmission properties we are acquiring from KMI contain numerous areas of polluted soil and ground water. These conditions have been reported to the appropriate jurisdictional agencies. In December 2000, we settled the environmental liability with KMI for $3.3 million (which will be paid as an offset to the purchase price) and have entered into a turnkey agreement with an environmental cleanup company to complete the work. We are subject to minor lawsuits incidental to operations in the oil and gas industry. We believe we have meritorious defenses to all lawsuits in which we are a defendant and will vigorously defend against them. We do not believe that the resolution of such lawsuits will have a material adverse effect on our financial position or results of operations. Operating Leases. We are obligated under noncancelable operating leases for office space, certain equipment and WGS. Total rental expense related to these leases was $3.2 million, $2.4 million and $2.6 million for December 31, 2000, 1999 and 1998, respectively. Future minimum lease payments as of December 31, 2000 are as follows (in thousands):

Wattenberg Gathering System Lease Agreements. In connection with the acquisition of WGS, we will likely assume the operating lease for the gathering system on December 15, 2001. Once the lease is assumed we will be required to make quarterly payments of $1.1 million from March 30, 2002 through March 30, 2003. As of March 30, 2003 we will have the following options: exercise the option to purchase the equipment for $19.9 million, terminate the lease and return the equipment, or renegotiate and extend the lease. As of December 31, 2000, we are also obligated to make quarterly supplemental interest payments on the outstanding lease balance for the difference between the fixed rate of 6.65% and the three month LIBOR rate plus 2.00%. In December 2000, we entered into a second operating lease for WGS. Under the terms of the agreement the lessor will reimburse HSR for up to $15 million of gas gathering, processing and transmission equipment. The original lease term is one year with up to nine one year renewals. Interest is payable monthly at LIBOR plus 1.9% on the equipment purchased until March 31, 2001 at which time HSR will begin making monthly lease payments of $178,175. NOTE 11 -- OTHER GAS REVENUES HSR and our subsidiaries continue to enter into transactions designed to monetize our Section 29 tax credits. In fifteen separate transactions through December 31, 2000, the first of which was entered into on December 1, 1995, we have sold to unaffiliated third parties our right, title and interest in certain of our oil and gas leases and mineral interests while retaining a volumetric production payment that entitles us to 100% of the net cash flows from the properties until certain volumes are produced. The sale will enable the third parties to earn tax credits associated with future oil and gas production. In 1999 and 1998 we received approximately $0.3 million and $6.4 million, respectively, in prepaid tax credit payments. No prepaid tax credits were received in 2000. We recorded the proceeds as deferred revenue and are amortizing the amount to other gas revenues as the gas is produced and the credits are generated. We recognized 58 59 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) approximately $8.2 million, $10.1 million and $8.6 million of other gas revenues associated with all tax credits during the years ended December 31, 2000, 1999, and 1998, respectively. NOTE 12 -- OIL AND GAS ACTIVITIES Major Purchasers. In 2000, sales to BP, Duke Energy Field Services and Conoco, Inc., accounted for approximately $75.1 million, $52.8 million and $44.5 million or 21.3%, 14.9% and 12.6% of total oil and gas sales, respectively. In 1999, sales to Duke Energy Field Service, BP and Ultramar Diamond Shamrock Corporation accounted for approximately $30.6 million, $22.1 million and $15.4 million or 18.6%, 13.4% and 9.3% of total oil and gas sales, respectively. In 1998, sales to Duke Energy Field Service, BP and Ultramar Diamond Shamrock Corporation accounted for approximately $26.4 million, $15.7 million and $15.2 million or 17.6%, 10.5% and 10.1% of total oil and gas sales, respectively. Sales to Duke Energy Field Services are subject to an arrangement that allows our subsidiary, HS Energy Services, Inc. to reacquire and market this gas. See Item 1. Business -- Marketing. Costs Incurred. Costs incurred in oil and gas operations and the related depreciation, depletion, and amortization per equivalent barrel of oil production are as follows (in thousands except DD&A rate):

59 60 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 13 -- BUSINESS SEGMENT INFORMATION We are an independent energy company engaged in the following activities: - acquisition, development, exploitation, exploration and production of oil and gas - transportation, marketing and trading of oil and gas and oil and gas financial positions

60 61 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 14 -- SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil And Gas Net Reserves. The following unaudited tables set forth the estimated quantities of net proved oil and gas reserves for HSR and the changes in total proved reserves as of December 31, 2000, 1999 and 1998. All such reserves are located in the United States. The amounts as of December 31, 2000, 1999 and 1998, were prepared by us and were reviewed by Netherland, Sewell & Associates, Inc., an independent petroleum engineering consulting firm. For a discussion of the extent of such review see Item 2. "Properties -- Oil and Gas Reserves." ANALYSIS OF CHANGES IN PROVED RESERVES

61 62 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Standardized Measure. The standardized measure of discounted future net cash flows, and changes therein related to proved oil and gas reserves are as follows (in thousands):

The impact of hedging has not been included in the calculation of the standardized measure or the changes in the standardized measure. The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties. For standardized measure purposes, future income taxes are estimated using the "year-by-year" method. The following are the principal sources of change in the standardized measure of discounted future net cash flows (in thousands):

62 63 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Estimated future cash inflows are computed by applying year-end prices of oil and gas to year-end quantities of proved reserves. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves held by us as of the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Estimated future income tax expenses are calculated by applying year-end statutory tax rates (adjusted for permanent differences) to estimated future pretax net cash flows related to proved oil and gas reserves, less the tax basis of the properties involved. No deductions were made for general overhead, depreciation and other indirect costs. The average year-end prices used in the projections were $25.29/Bbl of oil and $8.91/Mcf of gas at December 31, 2000, $23.55/Bbl of oil and $2.49/Mcf of gas at December 31, 1999 and $9.99/Bbl of oil and $1.94/Mcf of gas at December 31, 1998. These estimates were determined in accordance with SFAS 69. Because of unpredictable variances in expenses and capital forecasts, crude oil and gas price changes, and the fact that the basis for such estimates vary significantly, management believes that the usefulness of these projections of cash flow is limited. Estimates of future net cash flows do not represent management's assessment of future profitability or future cash flow to HSR. Management's investment and operating decisions may be based upon reserve estimates that include price, cost and production assumptions that are different from those used here. Applying current costs and prices and a 10% standard discount rate allows for comparability but does not convey absolute value. The discounted amounts arrived at are only one measure of financial quantification of proved reserves. Reservoir engineering is a process of making educated estimates of underground accumulations of oil and gas and the amounts and timing of recovery thereof, which cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, reserve estimates are often materially different from the quantities of oil and gas which are ultimately recovered. Future development of the properties in which we have an interest, including additional drilling activities, production results from wells not yet producing, and additional production results from currently producing wells, may provide information which justifies revisions, either upward or downward, of reserve estimates. Such adjustments may be material. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Disclosure Regarding Forward Looking Statements" and "Certain Considerations -- Estimation of Reserves." NOTE 15 -- QUARTERLY FINANCIAL DATA (UNAUDITED) Our quarterly results of operations are summarized as follows (in thousands, except per share data):

63 64 HS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 16 -- RATIO OF EARNINGS TO FIXED CHARGES (UNAUDITED) As of December 31, our ratio of earnings to fixed charges was as follows: 2000...................................................... 2.64 to 1 1999...................................................... 1.25 to 1 1998...................................................... n/a (1) 1997...................................................... n/a (1) 1996...................................................... 1.07 to 1

--------------- (1) Earnings were insufficient to cover fixed charges by $38.8 million and $28.0 million at December 31, 1998 and 1997, respectively. 64 65 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEMS 10-13, INCLUSIVE: These items have been omitted in accordance with the instructions of Form 10-K. Pursuant to Regulation 14A of the Securities Exchange Act, the Registrant will file with the Commission on or before April 30, 2001, a definitive proxy statement that will include information responsive to the above Items. Such information is incorporated into Part III of this Form 10-K by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, AND REPORTS ON FORM 8-K (a) The following documents are filed as a part of this Report: 1. FINANCIAL STATEMENTS: The financial statements are included in Item 8 of this Report. 2. FINANCIAL STATEMENT SCHEDULES: None. 3. EXHIBITS.

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--------------- * Filed herewith (b) Reports on Form 8-K. On November 8, 2000 we filed a Current Report on Form 8-K, attaching, under Item 5, a press release of the same date and setting forth under Item 9 our current estimates of certain significant operating and financial data for the fourth quarter of 2000 and calendar year 2001. 69 70 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 2nd day of March. HS RESOURCES, INC. By /s/ NICHOLAS J. SUTTON ----------------------------------- Nicholas J. Sutton Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities indicated on this 2nd day of March.

70 71 EXHIBIT INDEX

--------------- * Filed herewith

HS RESOURCES INC 10-K