10-Q 1 a10q.txt FORM 10-Q PERIOD ENDING 3-2001 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2001 -------------------------------------------------- OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ---------------------- ----------------------- Commission file number 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 Identification No.) incorporation or organization) One Maritime Plaza, Fifteenth Floor San Francisco, California 94111 ---------------------------------------- ------------------------------------ (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (415) 433-5795 ----------------------------- ------------------------------------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) 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 --- --- APPLICABLE ONLY TO CORPORATE ISSUERS: Number of shares of Common Stock, $.001 par value, outstanding as of the close of business on April 30, 2001: 18,245,205 after deducting 1,838,801 shares in treasury. 1 HS RESOURCES, INC. INDEX Page PART I. FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Balance Sheets - March 31, 2001 (Unaudited) and December 31, 2000....................................................3 Unaudited Consolidated Statements of Operations - For the Three Months Ended March 31, 2001 and 2000.................................5 Consolidated Statements of Stockholders' Equity - For the Years Ended December 31, 2000 and 1999 and the Three Months Ended March 31, 2001 (Unaudited).....................................6 Unaudited Consolidated Statements of Cash Flows - For the Three Months Ended March 31, 2001 and 2000...................7 Notes to Unaudited Consolidated Financial Statements.................8 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations...............................................13 PART II. OTHER INFORMATION Item 1. Legal Proceedings & Environmental Issues............................29 Item 2. Changes in Securities...............................................30 Item 3. Defaults Upon Senior Securities.....................................30 Item 4. Submission of Matters to a Vote of Security Holders.................30 Item 5. Other Information...................................................30 Item 6. Exhibits and Reports on Form 8-K....................................31 2 PART I. FINANCIAL INFORMATION Item 1. Financial Statements HS RESOURCES, INC. CONSOLIDATED BALANCE SHEETS MARCH 31, 2001 AND DECEMBER 31, 2000 ASSETS

The accompanying notes are an integral part of these consolidated financial statements. 3 HS RESOURCES, INC. CONSOLIDATED BALANCE SHEETS MARCH 31, 2001 AND DECEMBER 31, 2000 LIABILITIES AND STOCKHOLDERS' EQUITY

The accompanying notes are an integral part of these consolidated financial statements. 4 HS RESOURCES, INC. CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2001 AND 2000 (UNAUDITED)

The accompanying notes are an integral part of these consolidated financial statements. 5 HS RESOURCES, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1999 AND 2000 AND THE THREE MONTHS ENDED MARCH 31, 2001 (IN THOUSANDS)

The accompanying notes are an integral part of these consolidated financial statements. 6 HS RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2001 AND 2000 (UNAUDITED)

The accompanying notes are an integral part of these consolidated financial statements. 7 HS RESOURCES, INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. GENERAL 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 wholly-owned 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. The interim financial data presented here is unaudited; however, all adjustments, which are of a normal and recurring nature, have been made which are, in the opinion of management, necessary for a fair and consistent statement of our financial position at March 31, 2001, and our results of operations and cash flows for the interim periods presented. Because of various factors, results of operations for these periods are not necessarily indicative of results to be expected for the full year. For a more complete understanding of our operations and financial position, these statements should be read in conjunction with audited financial statements and notes thereto included in our December 31, 2000 Report on Form 10-K filed with the Securities and Exchange Commission on March 2, 2001. Certain prior year amounts have been reclassified to conform with the current presentation. NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES SUCCESSFUL EFFORTS. 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 and calculated on a field-by-field basis. The depreciation of capitalized drilling costs is also based on the unit-of-production method using proved developed reserves on a field-by-field basis. 8 HS RESOURCES, INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 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. All derivatives are marked-to-market and recorded as an asset or liability each reporting period. Gains and losses on the effective portion of hedging positions designated as cash flow hedges are deferred in other comprehensive income and recognized in operations 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 are accounted for using the marked-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 derivatives 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 of trading derivatives 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. NOTE 3. NEW ACCOUNTING STANDARDS On January 1, 2001, we adopted SFAS 133, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." 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. 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. 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. We also use interest rate swaps which are designated as hedges of the interest rate on our borrowings. Currently $80 million of our borrowings are hedged at a fixed LIBOR rate of 5.86% through December 15, 2006 and $50 million of our borrowings are hedged at a fixed LIBOR rate of 5.66% through March 31, 2004. On January 1, 2001, the fair market values of these derivative instruments and interest rate swaps were recorded as assets and liabilities on the balance sheet and in accumulated other comprehensive income in accordance with the transition provisions of SFAS 133. Future changes in the fair market values of these instruments and interest rate swaps, 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 9 HS RESOURCES, INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 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. For the quarters ended March 31, 2001 and 2000, hedging contracts for our production reduced our oil and gas sales by $49.0 million and by $4.7 million, respectively, whereas hedging contracts for third party gas increased trading and transportation revenues by $7.2 million and $0.1 million, respectively. Based on current futures market prices, which fluctuate daily, we currently anticipate that we will record losses over the next twelve months of $56.4 million in oil and gas sales and $1.4 million in trading and transportation revenues relating to hedging contracts. We also anticipate that we will record a loss over the next twelve months of $1.4 million on interest rate swaps based on current interest rates. 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. We implemented EITF Issue 00-10 in the fourth quarter of 2000 and all prior periods were restated with offsetting increases in oil and gas sales revenue and gas transportation costs resulting in no impact to net earnings. NOTE 4. ISSUANCE OF PERFORMANCE SHARES The 2000 Performance and Equity Incentive Plan (the "Plan") allows for the issuance of performance shares to employees, officers and directors. Accelerated vesting of such shares is dependent on our attainment of defined performance goals. These shares have a base vesting schedule over nine years with accelerated vesting of up to one-fourth of the shares in each of the first four years if the performance goals are achieved, and accelerated vesting upon a change of control. In the first quarter of 2001, we issued 60,000 performance shares under the Plan and recorded deferred compensation of approximately $2.5 million, which is being amortized based on management's evaluation regarding the attainment of the defined performance goals. NOTE 5. 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 and accrued interest were repaid in February 2001. 10 HS RESOURCES, INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 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 on or before December 31, 2001. The interest rate on these notes is at a fixed rate of 9.5%. In the first quarter of 2001 one of the notes and associated accrued interest was repaid. NOTE 6. SUBSEQUENT EVENT Effective April 1, 2001, we terminated our Section 29 tax credit agreements with two unaffiliated third parties. Under the agreements, we exercised our option to repurchase all of the oil and gas interests previously assigned to the third parties for $15.9 million at closing plus quarterly payments through December 31, 2002 in the amount of $0.8385 of each dollar of tax credits available to us under Section 29 of the Internal Revenue Code. We currently anticipate being able to utilize these tax credits against our current tax obligations, and therefore anticipate retaining a cash flow benefit of approximately $0.16 for each dollar of tax credits available to us under Section 29. 11 HS RESOURCES, INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 7. BUSINESS SEGMENT INFORMATION We are an independent energy company engaged in the following activities: o acquisition, development, exploitation, exploration and production of oil and gas o transportation, marketing and trading of oil and gas and oil and gas financial positions.

12 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations GENERAL. Our strategy centers around consolidation of assets in the 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 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 quarter ended March 31, 2001, 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 markets gas for third parties and trades financial positions in the gas commodities market. In December 1999, we furthered our consolidation strategy in the D-J Basin by acquiring from Kinder Morgan, Inc. ("KMI") the Wattenberg gas gathering and transmission assets ("WGS") 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. Although the transaction is scheduled to close in December 2001, 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. 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 Xcel Energy market, and seasonal fluctuations, the price more closely tracks Mid-Continent indices during the higher demand winter periods (generally November through 13 March). We are also working on creating a gas storage field in the D-J Basin that would likely help us reduce the seasonal volatility of gas prices in this area. 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. We have learned that BP is planning to take the NGL pipeline from Wattenberg to Bushton out of service late this summer for maintenance. We have begun implementation of a contingency plan that we can implement independently to allow the continued delivery of gas without reduction of volumes or interruption. We are also exploring with BP a contingency plan that involves a cooperative effort between HSR and BP. We believe that we will be able to continue delivery of D-J Basin gas volumes without reduction or interruption notwithstanding the expected maintenance shut down of the BP liquids line. RESULTS OF OPERATIONS. During 2001, 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. 14 COMPARISON OF THREE MONTHS ENDED MARCH 31, 2001 AND 2000 D-J BASIN OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES) March 31, ------------------------- 2001 2000 ---------- --------- Production: Oil (Bbl) 572 594 Gas (Mcf) 15,173 14,023 Mcfe 18,607 17,585 Boe 3,101 2,931 Prices (1): Average realized oil price ($/Bbl) $ 26.95 $ 18.83 Average realized gas price ($/Mcf) $ 4.62 $ 2.98 Operating Revenues: Oil and gas sales $ 85,463 $ 53,017 Other gas revenues 1,972 2,007 ---------- --------- 87,435 55,024 ---------- --------- Operating Costs and Expenses: Production taxes 7,016 4,859 Lease operating 7,678 6,729 Gas transportation costs 4,528 3,907 Depreciation, depletion and amortization 12,712 12,884 Exploratory and abandonment 283 47 Geological and geophysical 90 94 ---------- --------- 32,307 28,520 ---------- --------- Operating Income $ 55,128 $ 26,504 ========== ========= (1) Includes effects of hedging activities. 15 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 December 1997 Amoco acquisition, the 1999 acquisition of WGS and the 2000 acquisition of interests in 60 wells and associated mineral rights. For the three months ended March 31, 2001 and 2000 exploitation programs consisted of 120 and 136 separate activities, respectively. Activities include drilling, deepening, recompleting and refracing. OPERATING REVENUES. Our D-J Basin oil and gas production and revenues have increased primarily as the result of the success of our ongoing exploitation and development activities and increased product prices. Other gas revenues related to the sale of tax credits decreased for the three months ended March 31, 2001 compared to the prior year period mainly due to natural production declines and significantly less refrac activity on wells eligible for tax credits. Other gas revenue related to the sale of tax credits will not continue after March 31, 2001 since we have terminated our Section 29 tax credit monetization transactions, although we expect to benefit from the direct utilization of Section 29 tax credits from April 1, 2001 through December 2002. See Note 6 to Unaudited Consolidated Financial Statements - Subsequent Event. PRODUCTION EXPENSES. Total lease operating expense ("LOE") increased both on an absolute and an Mcfe basis for the three months ended March 31, 2001 compared to the prior year period. LOE per Mcfe was $0.41 compared to $0.38 for the quarter ended March 31, 2001 and 2000, respectively. The increase was mainly due to the timing of incentive compensation awards, some of which are reclassified as lease operating expense when the awards are made. Production taxes increased in 2001 as a result of higher realized product prices. DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization ("DD&A"), a non-cash expense, decreased slightly for the three months ended March 31, 2001 compared to the prior year period because a decrease in the depletion rate more than offset an increase in production. The decrease in the depletion rate was the result of the addition of proved reserves due to higher year-end product prices. The weighted average depletion rate per Mcfe for the D-J Basin was $0.68 and $0.73 for the three months ended March 31, 2001, and 2000, respectively. We annually adjust our DD&A rate based on year-end engineering and, if material changes in our reserves warrant, on an interim basis. EXPLORATORY AND ABANDONMENT COSTS. Exploratory and abandonment costs include the costs of exploratory dry holes, delay rentals, plugging and abandonment ("P&A") costs, expired acreage and salaries and overhead ("overhead") costs directly related to exploratory activities. Exploratory and abandonment costs increased modestly for the three months ended March 31, 2001 compared to the prior year period mainly due to expired acreage written off during the quarter. GEOLOGICAL AND GEOPHYSICAL COSTS. Geological and geophysical ("G&G") costs include costs for seismic activity as well as overhead costs directly attributable to G&G activity. For the three months ended March 31, 2001 G&G costs remained relatively flat compared to the prior year period. 16 GULF COAST OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES) March 31, ----------------------- 2001 2000 --------- ---------- Production: Oil (Bbl) 166 116 Gas (Mcf) 2,845 1,995 Mcfe 3,838 2,694 Boe 640 449 Prices (1): Average realized oil price ($/Bbl) $ 21.85 $ 28.51 Average realized gas price ($/Mcf) $ 5.11 $ 2.83 Operating Revenues: Oil and gas sales $ 18,157 $ 8,977 Operating Costs and Expenses: Production taxes 536 604 Lease operating 394 240 Depreciation, depletion and amortization 2,981 1,361 Exploratory and abandonment 2,640 2,504 Geological and geophysical 3,385 1,595 Loss on sale of oil and gas properties -- 100 --------- ---------- 9,936 6,404 --------- ---------- Operating Income $ 8,221 $ 2,573 ========= ========== (1) Includes effects of hedging activities. 17 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 for the three months ended March 31, 2001 compared to the prior year period due to an increase both in production and in product prices. We drilled or participated in a total of 11 gross (5.9 net) wells in the first quarter of 2001 compared to 7 gross (3.3 net) wells in the first quarter of 2000. Of the total wells drilled to date, 11 gross (6.35 net) are currently awaiting testing or pipeline hookup. PRODUCTION EXPENSES. Aggregate LOE increased in the first quarter of 2001 compared to the prior year period because of the greater number of producing wells and an increase in workover costs. LOE per Mcfe was $0.10 and $0.09 for the three months ended March 31, 2001 and 2000, respectively. Production taxes decreased in the first quarter of 2001 compared to the first quarter of 2000 as a result of an adjustment recorded in the first quarter of 2001 related to a severance tax relief program for certain qualifying wells. DEPRECIATION, DEPLETION AND AMORTIZATION. Total DD&A increased in the first quarter of 2001 compared to the first quarter of 2000 as a result of 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 these wells. The weighted average DD&A rate per Mcfe in the Gulf Coast was $0.78 and $0.51 for the three months ended March 31, 2001 and 2000, respectively. EXPLORATORY AND ABANDONMENT COSTS. During the first quarter of 2001, we incurred $0.3 million for three exploratory dry holes, $1.7 million for expired acreage, $0.4 million for delay rentals and $0.2 million for overhead costs. During the first quarter of 2000, we incurred $0.2 million for one exploratory dry hole, $1.7 million for expired acreage, $0.3 million for delay rentals and $0.3 million for overhead costs. GEOLOGICAL AND GEOPHYSICAL COSTS. Of total G&G costs, we incurred $1.9 million and $1.2 million for the three months ended March 31, 2001 and 2000, respectively, for seismic permits and processing costs in the Gulf Coast. The remaining G&G of $1.5 million and $0.4 million relates to overhead costs directly attributable to G&G activity. The increase in overhead costs in the first quarter of 2001 compared to the prior year was due to compensation payments made to joint interest partners. LOSS ON SALE OF OIL AND GAS PROPERTIES. As of March 31, 2000, we recorded a loss of $100,000 on the sale of one well. 18 MID-CONTINENT AND NORTHERN ROCKIES OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES) March 31, ----------------------- 2001 2000 -------- --------- Production: Oil (Bbl) 3 -- Gas (Mcf) 81 21 Mcfe 97 21 Boe 16 4 Prices: Average realized oil price ($/Bbl) $ 28.62 $ -- Average realized gas price ($/Mcf) $ 7.47 $ -- Operating Revenues: Oil and gas sales $ 683 $ 51 Operating Costs and Expenses: Production taxes 54 5 Lease operating 37 55 Depreciation, depletion and amortization 68 20 Exploratory and abandonment 216 117 Geological and geophysical 145 1,860 -------- --------- 520 2,057 -------- --------- Operating (Loss) Income $ 163 $ (2,006) ======== ========= GENERAL. Information for this segment includes activity for both the Mid-Continent and Northern Rockies areas. Our current strategy in the Mid-Continent is to pursue technology-oriented grass-roots 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. EXPLORATORY AND ABANDONMENT COSTS. The majority of exploratory and abandonment costs in the first quarter of 2001 and 2000 represent costs incurred for delay rentals and overhead costs for projects in the Northern Rockies. GEOLOGICAL AND GEOPHYSICAL COSTS. The decrease in G&G costs in the first quarter of 2001 compared to 2000 is the result of a reduction in seismic activity in the Mid-Continent due to completion of processing of seismic data on several projects as well as a reimbursement received in the first quarter of 2001 for a seismic shoot that was not completed due to permitting issues. 19 TRADING AND TRANSPORTATION (IN THOUSANDS) March 31, --------------------------- 2001 2000 ----------- ----------- Operating Revenues: Trading and transportation (1) $ 206,127 $ 54,220 Operating Costs and Expenses: Cost of trading and transportation (1) 200,644 52,019 Depreciation and amortization 132 107 ----------- ----------- 200,776 52,126 ----------- ----------- Operating Income $ 5,351 $ 2,094 =========== =========== (1) Includes intercompany revenues of $105.8 million and $35.6 million and expenses of $103.5 million and $34.9 million in the first quarter of 2001 and 2000, respectively. Such amounts are attributable to our volumes which are marketed by HSES and have been eliminated in our 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 the first quarter of 2001 compared to 2000 primarily as a result of an increase in the margins per MMBtu due to the volatility of natural gas physical and financial markets. For the quarters ended March 31, 2001 and 2000, gains of $2.4 million and $1.4 million, respectively, were recognized in connection with financial trading activities. 20 GAS GATHERING AND TRANSMISSION (IN THOUSANDS) March 31, ---------------------- 2001 2000 --------- -------- Operating Revenues Gathering and transmission system revenues $ 4,992 $ 4,591 Gas purchases and transportation expense (3,526) (1,483) --------- -------- Gross Margin 1,466 3,108 Income (loss) from interest in gathering plant (109) 365 --------- -------- 1,357 3,473 --------- -------- Operating Costs and Expenses Gathering and transmission system operating expenses 1,644 1,215 Depreciation and amortization 301 277 Interest expense 988 1,344 --------- -------- 2,933 2,836 --------- -------- Operating Income $ (1,576) $ 637 ========= ======== 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 March 31, 2001, WGS transported an average of approximately 223 MMcf of gas per day. Final construction has been completed on a new compressor station, with both 3,000 horsepower compressors now operational and adding approximately 50 MMcf per day of incremental throughput. In addition, we are completing the installation of 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. 21 OTHER INCOME AND EXPENSES (IN THOUSANDS) March 31, ------------------------ 2001 2000 ---------- ---------- Interest income and other $ 392 $ 259 General and administrative $ 1,493 $ 2,026 Interest $ 10,127 $ 10,818 Depreciation $ 221 $ 206 INTEREST INCOME AND OTHER INCOME. Interest and other income remained relatively flat for the first quarter of 2001 compared to the first quarter of 2000. 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 $0.07 and $0.10 in the first quarter of 2001 compared to the first quarter of 2000. On both an absolute and an Mcfe basis, G&A decreased as a result of the timing of incentive compensation awards allocated to LOE. INTEREST EXPENSE. Interest expense decreased for the first quarter of 2001 compared to the first quarter of 2000 due to a decrease in debt outstanding on our bank facility and a decrease in the interest rate on our bank facility. For the three months ended March 31, 2001 and 2000, we capitalized $1.4 million and $1.6 million, respectively, of interest related to undeveloped acreage. 22 INCOME TAXES (IN THOUSANDS) March 31, ------------------------ 2001 2000 ----------- ---------- Current provision $ 7,230 $ --- Deferred provision 13,388 6,227 ----------- ---------- Provision for taxes $ 20,618 $ 6,227 =========== ========== Effective tax rate 38.5% 38.1% =========== ========== 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% and 38.1% in the first quarter of 2001 and 2000, respectively. Due primarily to net operating loss carryforwards and significant intangible drilling costs, which are deductible for income tax purposes, substantially all of our tax provision in 2000 was deferred. Based on current operating projections, we anticipate a current tax liability for 2001 after utilization of all regular net operating loss carryforwards of approximately $27.9 million, all alternative minimum tax loss carryforwards of approximately $17.4 million, and Section 29 tax credits (see Note 6 to Unaudited Consolidated Financial Statements - Subsequent Event). Additionally, we project utilization of percentage depletion carryforwards of approximately $6.2 million and alternative minimum tax credit carryforwards of $1.6 million. 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. 23 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, acceleration of capital projects or acquisitions. 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 March 31, 2001, $124.0 million was outstanding under the Chase facility compared to $189.0 million at December 31, 2000. As of March 31, 2001 and 2000, our ratio of earnings to fixed charges was 5.09x and 2.07x, respectively. 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 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 quarter ended March 31, 2001, we incurred total costs for exploration, development, leasehold, exploratory and abandonment, geological and geophysical activities and improvements on WGS of $38.2 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 $155 to $175 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 $20.8 million for the quarter ended March 31, 2001 for leasehold and geological and geophysical costs and to drill, deepen, recomplete and refrac our D-J Basin properties as well as $3.4 million on WGS. We anticipate allocating approximately 65% 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 quarter ended March 31, 2001, we 24 incurred total expenditures of $14.0 million for seismic, leasehold and drilling costs in the Gulf Coast. We anticipate allocating approximately 30% 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 and our second well was spud in April 2001. For the quarter ended March 31, 2001, we incurred $0.6 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 $107.0 million at March 31, 2001, $18.8 million represents the amount payable to KMI for the purchase of WGS and $59.9 million relates to the marked-to-market fair value of cash flow hedges that will settle in the next year at the same time as the related production volumes occur. 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 quarter ended March 31, 2001 was $107.6 million, up from $45.1 million for the same period in 2000 as a result of an increase in production and product prices. 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"), Colorado Interstate Gas ("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 25 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. All derivatives are marked-to-market and recorded as an asset or liability each reporting period. Gains and losses on the effective portion of hedging positions designated as cash flow hedges are deferred in other comprehensive income and recognized in operations 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 $49.0 million and by $4.7 million for the quarters ended March 31, 2001 and 2000, respectively. Hedging contracts for third party gas increased trading and transportation revenues by approximately $7.2 million and $0.1 million for the quarters ended March 31, 2001 and 2000, respectively. As of March 31, 2001, we held hedge swap positions as follows: GAS HEDGES

Additionally, with respect to the hedging of third party gas, we have hedged 61.5 Bcf from April 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 March 31, 2001 was a loss of approximately $4.7 million, of which $4.4 million and $0.3 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: 26 GAS SALES Average Daily Quantity Settlement Price Time Period (MMBtu) Location (per MMBtu) ------------------------------- ------------- ------------- ------------- April 2001 - December 2001 20,000 NYMEX $2.8875 OIL SALES Average Monthly Quantity Settlement Price Time Period (Bbl) Location (per Bbl) --------------- -------------- ------------ ----------- April 2001 - December 2001 60,883 WTI $18.59 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 marked-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 derivatives 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 of trading derivatives 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 quarters ended March 31, 2001 and 2000, gains of $2.4 million and $1.4 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. INTEREST RATE SWAPS. During the fourth quarter of 1998, we entered into an interest rate exchange agreement with a financial institution to hedge the LIBOR interest rate on $80 million 27 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 LIBOR 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 marked-to-market value of our interest rate swaps as of March 31, 2001 was a loss of $3.0 million. 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. See Part II. Other Information. Item 1. Legal Proceedings and Environmental Issues for a further discussion of this matter. The gathering and transmission properties we are acquiring from KMI (WGS) 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 by KMI as an offset to the purchase price of WGS) and have entered into a turnkey agreement with an environmental cleanup company to complete the work. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Form 10-Q 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-Q or otherwise stated by HSR are forward-looking statements, including without limitation, statements under "Legal Proceedings and Environmental Issues," "Management's Discussion and Analysis of Financial Condition and Results of Operations," and "Notes to Unaudited Consolidated Financial Statements." These statements may concern, among other things: - planned capital expenditures and allocations; - planned expansions of gathering, transmission and processing facilities; - ability to continue D-J Basin operations without material reduction or interruption notwithstanding the planned maintenance shutdown of the BP liquids pipeline to Bushton, Kansas; - trends or expectations concerning oil and gas prices or market characteristics; - marketing, hedging and trading risks, strategies, policies and procedures; - the anticipated effect on revenues and expenses from hedging positions; 28 - our financial position, stability of cash flow, debt service capabilities and capital availability; - anticipated tax liabilities for 2001; - the anticipated effect on cash flow from Section 29 tax credits; - the ability to manage risk through hedging and similar activities; - business strategy and other plans and objectives for future operations; - 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-Q 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" described in our Report on Form 10-K filed March 2, 2001. PART II. OTHER INFORMATION Item 1. Legal Proceedings and Environmental Issues 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 March 31, 2001 for our portion of the costs. This amount has been recorded in our financial statements as of March 31, 2001 and we believe that no substantial liability remains. In March 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. 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 estimated settlement. 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 29 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 of WGS) and have entered into a turnkey agreement with an environmental cleanup company to complete the work. Certain portions of these properties contain contamination for which KMI's predecessor, Panhandle Eastern Pipeline Company, was liable. Panhandle's successor, Duke Energy, is now responsible for this cleanup, which has been underway for several years under the supervision of the Colorado Oil and Gas Conservation Commission. KMI has provided broad indemnity protection to HSR against any liability for the Panhandle contamination. 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 such lawsuits, regardless of the outcome, will not have a material adverse effect on our results of operations or our financial position. Item 2. Changes in Securities: None. Item 3. Defaults Upon Senior Securities: None. Item 4. Submission of Matters to a Vote of Security Holders: None. Item 5. Other Information: None. 30 Item 6. Exhibits and Reports on Form 8-K a. Exhibits. Exhibit Number Description ------- ----------- 3.1 Amended and Restated Certificate of Incorporation of the Company. (Incorporated herein by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-1, No. 33-52774, filed October 2, 1992.) 3.2 Certificate of Amendment of Certificate of Incorporation filed November 30, 1998. (Incorporated by reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, filed May 14, 1999.) 3.3 Third Amended and Restated Bylaws of the Company adopted December 16, 1996. (Incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-4, No 333-19433, filed January 8, 1997.) 4.1 Form of Indenture dated December 1, 1993, entered into between the Company and the Trustee. (Incorporated by reference to Exhibit 4.7 to Amendment No. 3 to the Company's Registration Statement on Form S-3, No. 33-70354, filed November 23, 1993.) 4.2 Indenture dated November 27, 1996, among the Company, Orion Acquisition, Inc., HSRTW, Inc., and Harris Trust and Savings Bank as Trustee. (Incorporated by reference to Exhibit 4.2 to the Company's Registration Statement on Form S-4, No 333-19433, filed January 8, 1997.) 4.3 First Supplemental Indenture dated November 25, 1996 among the Company, Orion Acquisition, Inc., HSRTW, Inc., and Harris Trust and Savings Bank as Trustee. (Incorporated by reference to Exhibit 4.3 to the Company's Registration Statement on Form S-4, No 333-19433, filed January 8, 1997.) 4.4 Indenture dated as of December 11, 1998 among the Company and Harris Trust and Savings Bank as Trustee. (Incorporated by reference to Exhibit 4.1 to the Company's Report on Form 8-K, filed December 11, 1998.) 4.5 Supplemental Indenture dated as of March 1, 1999, among the Company and Harris Trust and Savings Bank as Trustee, amending Indenture dated as of December 1, 1993, concerning 9-7/8% Senior Subordinated Notes due 2003. (Incorporated by reference to Exhibit 10.43 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1998, filed March 31, 1999.) 4.6 Supplemental Indenture dated as of March 1, 1999, among the Company and Harris Trust and Savings Bank as Trustee, amending Indenture dated as of 31 November 27, 1996, concerning 9-1/4% Series A Senior Subordinated Notes due 2006. (Incorporated by reference to Exhibit 10.44 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1998, filed March 31, 1999.) 4.7 Supplemental Indenture dated as of March 1, 1999, among the Company and Harris Trust and Savings Bank as Trustee, amending Indenture dated as of December 11, 1998, concerning 9-1/4% Series B Senior Subordinated Notes due 2006. (Incorporated by reference to Exhibit 10.45 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1998, filed March 31, 1999.) 10.1 HS Resources, Inc. Rule 701 Compensatory Benefit Plan. (Incorporated by reference to Exhibit 10.5.2 to the Form 8, Second Amendment to Form 10, filed April 8, 1991.) 10.2 1992 Directors' Stock Option Plan. (Incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Company's Registration Statement on Form S-1, No. 33-52774, filed November 9, 1992.) 10.3 Form of Indemnification Agreement for Directors of the Company. (Incorporated by reference to Exhibit 10.16 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1995, filed March 25, 1996.) 10.4 Lease Agreement dated October 6, 1993, between the Company and JMB Group Trust IV and Endowment and Foundation Realty, Ltd. -- JMB III for the premises at One Maritime Plaza, San Francisco, California. (Incorporated by reference to Exhibit 10.13 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, filed March 31, 1994 (as amended by Form 10-K/A-1 on April 8, 1994.)) 10.5 Lease Agreement dated March 28, 1994, between the Company and 1999 Broadway Partnership for the premises at 1999 Broadway, Denver, Colorado. (Incorporated by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1994, filed August 12, 1994.) 10.6 Purchase and Sale Agreement, dated December 1, 1995, between the Company and Wattenberg Gas Investments, LLC. (Incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1995, filed March 25, 1996.) 10.7 Rights Agreement, dated as of February 28, 1996, between the Company and Harris Trust Company of California as Rights Agent. (Incorporated by reference to Exhibit 1 to the Company's Form 8-A, filed March 11, 1996.) 10.8 Purchase and Sale Agreement dated March 25, 1996, between Orion, the Company and Wattenberg Resources Land, L.L.C. (Incorporated by reference to 32 Exhibit 10.28 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1996, filed May 15, 1996.) 10.9 Amended and Restated Credit Agreement dated as of June 14, 1996, among the Company, Chase as agent, and the Banks signatory thereto. (Incorporated by reference to Exhibit 10.21 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.) 10.10 First Amendment to Amended and Restated Credit Agreement dated as of June 17, 1996, by and among the Company and Chase in its individual capacity and as agent for the Lenders. (Incorporated by reference to Exhibit 10.22 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.) 10.11 Second Amendment to Amended and Restated Credit Agreement dated as of November 27, 1996 among the Company and Chase in its individual capacity and as agent for the Lenders. (Incorporated by reference to Exhibit 10.22 to the Company's Registration Statement on Form S-4, No 333-19433, filed January 8, 1997.) 10.12 Purchase and Sale Agreement between the Company and Wattenberg Gas Investments, LLC dated April 25, 1996. (Incorporated by reference to Exhibit 10.32 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.) 10.13 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C. and Wattenberg Gas Investments, LLC dated May 21, 1996. (Incorporated by reference to Exhibit 10.33 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.) 10.14 Purchase and Sale Agreement between Orion and Wattenberg Gas Investments, LLC dated June 14, 1996. (Incorporated by reference to Exhibit 10.34 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.) 10.15 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C. and Wattenberg Gas Investments, LLC dated June 14, 1996. (Incorporated by reference to Exhibit 10.35 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.) 10.16 Purchase and Sale Agreement between Orion and Wattenberg Gas Investments, LLC dated June 14, 1996. (Incorporated by reference to Exhibit 10.36 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.) 10.17 Purchase and Sale Agreement between the Company and Wattenberg Gas Investments, LLC dated June 28, 1996. (Incorporated by reference to 33 Exhibit 10.37 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.) 10.18 Purchase and Sale Agreement between the Company and Amoco Production Company dated November 25, 1997. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed December 23, 1997.) 10.19 Side Letter Agreement between the Company and Amoco Production Company dated November 25, 1997. (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed December 23, 1997.) 10.20 Closing Side Agreement between the Company and Amoco Production Company dated December 15, 1997. (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed December 23, 1997.) 10.21 Third Amendment to Amended and Restated Credit Agreement dated as of December 15, 1997, among the Company and The Chase Manhattan Bank as agent for the Lenders signatory thereto. (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed December 23, 1997.) 10.22 Purchase and Sale Agreement dated December 15, 1997, by and between HS Resources, Inc. as Seller and WestTide Investments, LLC as Buyer. (Incorporated by reference to Exhibit 10.46 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1997, filed March 31, 1998.) 10.23 Fifth Amendment and Supplement to Amended, Restated and Consolidated Mortgage, Assignment of Production, Security Agreement and Financing Statement between HS Resources (Mortgagor) and The Chase Manhattan Bank, as agent for the Lenders, effective as of December 15, 1997. (Incorporated by reference to Exhibit 10.37 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, filed May 14, 1998.) 10.24 Agreement and Plan of Merger between Orion Acquisition, Inc. and HS Resources, Inc. dated April 20, 1998, but effective May 1, 1998. (Incorporated by reference to Exhibit 10.38 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, filed May 14, 1998.) 10.25 First Amendment to Agreement of Lease between 1999 Broadway Partnership (Landlord) and HS Resources, Inc. (Tenant), dated March 21, 1997. (Incorporated by reference to Exhibit 10.39 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, filed May 14, 1998.) 10.26 HS Resources, Inc. Form of Key Employee Severance Agreement (March 27, 1998). (Incorporated by reference to Exhibit 10.40 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, filed May 14, 1998.) 34 10.27 Fourth Amendment to Amended and Restated Credit Agreement dated as of June 16, 1998, among the Company and The Chase Manhattan Bank in its individual capacity and as agent for the Lenders. (Incorporated by reference to Exhibit 10.41 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, filed August 14, 1998.) 10.28 Stock Purchase and Sale Agreement between the Company and Universal Resources Corporation dated July 27, 1998. (Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K, filed August 6, 1998.) 10.29 Fifth Amendment to Amended and Restated Credit Agreement dated as of September 1, 1998, among the Company and The Chase Manhattan Bank in its individual capacity and as agent for the lenders. (Incorporated by reference to Exhibit 10.37 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, filed November 16, 1998.) 10.30 Sixth Amendment and Supplement to Amended, Restated and Consolidated Mortgage, Assignment of Production, Security Agreement and Financing Statement dated as of July 22, 1998, among the Company and The Chase Manhattan Bank in its individual capacity and as agent for the Lenders. (Incorporated by reference to Exhibit 10.38 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, filed November 16, 1998.) 10.31 Sixth Amendment to Amended and Restated Credit Agreement dated as of December 10, 1998, among the Company and The Chase Manhattan Bank in its individual capacity and as agent for the Lenders. (Incorporated by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1998, filed March 31, 1999.) 10.32 Seventh Amendment to Amended and Restated Credit Agreement dated as of December 31, 1998, among the Company and The Chase Manhattan Bank in its individual capacity and as agent for the Lenders. (Incorporated by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1998, filed March 31, 1999.) 10.33 1999 Non-Compensatory Stock Purchase Plan. (Incorporated by reference as Exhibit 4.1 to Form S-8 filed January 25, 1999.) 10.34 Seventh Amendment and Supplement to Amended, Restated and Consolidated Mortgage, Assignment of Production, Security Agreement and Financing Statement dated as of September 1, 1999 among the Company and The Chase Manhattan Bank in its individual capacity, and as agent to the Lenders. (Incorporated by reference to Exhibit 10.41 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, filed November 15, 1999.) 35 10.35 Eighth Amendment to Amended and Restated Credit Agreement dated as of August 27, 1999 among the Company and The Chase Manhattan Bank in its individual capacity, and as agent for the Lenders. (Incorporated by reference to Exhibit 10.42 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, filed November 15, 1999.) 10.36 Exchange Agreement dated August 27, 1999 between HS Resources, Inc. and Patina Oil & Gas Corporation. (Incorporated by reference to Exhibit 10.43 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, filed November 15, 1999.) 10.37 Ninth Amendment to Amended and Restated Credit Agreement dated as of October 28, 1999 among the Company and The Chase Manhattan Bank in its individual capacity, and as agent for the Lenders. (Incorporated by reference to Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, filed March 24, 2000.) 10.38 Tenth Amendment to Amended and Restated Credit Agreement dated as of May 16, 2000 among the Company and The Chase Manhattan Bank in its individual capacity, and as agent for the Lenders. (Incorporated by reference to Exhibit 10.42 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2000, filed August 11, 2000.) 10.39 Lease Agreement dated as of May 22, 2000, by and between HS Resources, Inc. and Cooley Godward LLP for the premises located at One Maritime Plaza, 15th Floor, San Francisco, California. (Incorporated by reference to Exhibit 10.43 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, filed November 13, 2000.) 10.40 Master Lease Agreement dated as of December 14, 2000 by and between HS Gathering, L.L.C. and LaSalle National Leasing Corporation. (Incorporated by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, filed March 2, 2001.) 10.41 Eleventh Amendment to Amended and Restated Credit Agreement dated as of November 28, 2000 among the Company and the Chase Manhattan Bank in its individual capacity and as agent for the Lenders. (Incorporated by reference to Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, filed March 2, 2001.) 10.42 Employee Stock Purchase Plan approved by the Board of Directors March 12, 2001. (Incorporated herein by reference to Exhibit B to the Company's Definitive Proxy Statement filed April 10, 2001.) 10.43* Representative Form of Key Employee Severance Agreement with certain officers of HS Resources dated as of March 12, 2001. 36 10.44* Twelfth Amendment to Amended and Restated Credit Agreement dated as of April 23, 2000 among the Company and the Chase Manhattan Bank in its individual capacity and as agent for the Lenders. 10.45* Agreement for Exercise of Options; Assignment of Oil and Gas Interests and Grant of Production Payment dated as of April 1, 2001 by and between the Company and Westtide Investments, LLC. 10.46* Agreement for Exercise of Options; Assignment of Oil and Gas Interests and Grant of Production Payment dated as of April 1, 2001 by and between the Company and Wattenberg Gas Investments, LLC. * Filed herewith b. Reports on Form 8-K. On February 15, 2001 we filed a Current Report on Form 8-K, attaching under Item 9, our current estimates of certain significant operating and financial data for the first and second quarters of 2001 and calendar year 2001. On March 20, 2001, we filed a Current Report on Form 8-K, attaching under Item 5, quarterly information of restatement of transportation costs in accordance with EITF 00-10 "Accounting for shipping and handling costs." 37 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, HS Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. HS RESOURCES, INC. Dated: May 9, 2001 By: /s/ JAMES E. DUFFY ----------------------------------------------- James E. Duffy Vice President and Chief Financial Officer By: /s/ ANNETTE MONTOYA ----------------------------------------------- Annette Montoya Vice President and Principal Accounting Officer 38 INDEX TO EXHIBITS Exhibit Number Description ------- ----------- 10.43 Representative Form of Key Employee Severance Agreement with certain officers of HS Resources dated as of March 12, 2001. 10.44 Twelfth Amendment to Amended and Restated Credit Agreement dated as of April 23, 2000 among the Company and the Chase Manhattan Bank in its individual capacity and as agent for the Lenders. 10.45 Agreement for Exercise of Options; Assignment of Oil and Gas Interests and Grant of Production Payment dated as of April 1, 2001 by and between the Company and Westtide Investments, LLC. 10.46 Agreement for Exercise of Options; Assignment of Oil and Gas Interests and Grant of Production Payment dated as of April 1, 2001 by and between the Company and Wattenberg Gas Investments, LLC. 39

HS RESOURCES INC 10-Q