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                                 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)

<TABLE>
<S>                                            <C>
                   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)
</TABLE>

       Registrant's telephone number, including area code: (415) 433-5795
                             ---------------------
           SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT

<TABLE>
         TITLE OF EACH CLASS OF STOCK               NAME OF EXCHANGE ON WHICH REGISTERED
<S>                                            <C>
       Common Stock -- $.001 par value                    New York Stock Exchange
</TABLE>

        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.)
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<PAGE>   2

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                             PAGE
                                                                             ----
<S>            <C>                                                           <C>
Part I.
  Item 1.      Business....................................................    3
  Item 2.      Properties..................................................    8
  Item 3.      Legal Proceedings and Environmental Issues..................   14
  Item 4.      Submission of Matters to a Vote of Security Holders.........   14
Part II.
  Item 5.      Market for Registrant's Common Equity and Related
                 Stockholder Matters.......................................   15
  Item 6.      Selected Financial Data.....................................   16
  Item 7.      Management's Discussion and Analysis of Financial Condition
                 and Results of Operations.................................   17
  Item 8.      Financial Statements and Supplementary Data.................   39
  Item 9.      Changes in and Disagreements with Accountants on Accounting
                 and Financial Disclosure..................................   65
Part III.
  Items 10-13..............................................................   65
Part IV.
  Item 14.     Exhibits, Financial Statement Schedules, and Reports on Form
                 8-K.......................................................   65
</TABLE>

                                        2
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   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.

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<PAGE>   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
<PAGE>   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:

<TABLE>
<CAPTION>
                                                 SQUARE    MONTHLY        LEASE
LOCATION                                         FOOTAGE   RENTAL      EXPIRATION
--------                                         -------   -------   ---------------
<S>                                              <C>       <C>       <C>
San Francisco, CA(1)...........................   20,548   $  (698)  December, 2003
Denver, CO.....................................   52,749    68,500   June, 2003
Evans, CO......................................   17,985     9,600   February, 2009
Tulsa, OK......................................    6,766     7,981   March, 2002
Houston, TX....................................    5,362     4,200   July, 2003
Oklahoma City, OK..............................    2,248     1,557   January, 2002
                                                 -------   -------
                                                 105,658   $91,140
                                                 =======   =======
</TABLE>

---------------

(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.

<TABLE>
<CAPTION>
                                                               PROVED RESERVES
                                          ---------------------------------------------------------
                                                                  GAS          OIL       PERCENT OF
                                           OIL        GAS      EQUIVALENT   EQUIVALENT     TOTAL
                                          (MBBL)    (MMCF)      (MMCFE)       (MBOE)      RESERVES
                                          ------   ---------   ----------   ----------   ----------
<S>                                       <C>      <C>         <C>          <C>          <C>
D-J Basin...............................  43,632     994,066   1,255,856     209,309        96.9
Gulf Coast..............................   1,528      28,546      37,714       6,286         3.0
Mid-Continent and Northern Rockies......      28       1,699       1,868         311         0.1
                                          ------   ---------   ---------     -------        ----
          Total.........................  45,188   1,024,311   1,295,438     215,906         100
                                          ======   =========   =========     =======        ====
</TABLE>

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<TABLE>
<CAPTION>
                                                                OTHER INFORMATION
                                      ---------------------------------------------------------------------
                                                                    NET           GROSS       3-D SEISMIC
                                      TOTAL GROSS   PERCENT     PRODUCTION     UNDEVELOPED        DATA
                                       WELLS(1)     OPERATED   (MCFE/DAY)(2)   ACREAGE(3)    (SQUARE MILES)
                                      -----------   --------   -------------   -----------   --------------
<S>                                   <C>           <C>        <C>             <C>           <C>
D-J Basin...........................     4,098         72         189,939        184,176           124
Gulf Coast..........................        52         52          44,945        297,873         1,277
Mid-Continent and Northern
  Rockies...........................        13         38             736        268,762           451
                                         -----         --         -------        -------         -----
          Total.....................     4,163         71         235,620        750,811         1,852
                                         =====         ==         =======        =======         =====
</TABLE>

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(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
<PAGE>   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
<PAGE>   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.

<TABLE>
<CAPTION>
                                                         DEVELOPED ACRES    UNDEVELOPED ACRES(1)
                                                        -----------------   ---------------------
AREA                                                     GROSS      NET       GROSS        NET
----                                                    -------   -------   ---------   ---------
<S>                                                     <C>       <C>       <C>         <C>
D-J Basin.............................................  542,688   430,654    184,176     170,102
Gulf Coast............................................   15,536     3,577    297,873     124,452
Northern Rockies......................................    2,147     1,010    232,529     171,464
Mid-Continent.........................................      640       397     36,233      16,943
                                                        -------   -------    -------     -------
          Total.......................................  561,011   435,638    750,811     482,961
                                                        =======   =======    =======     =======
</TABLE>

---------------

(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.

<TABLE>
<CAPTION>
                                                                   NET PROVED RESERVES
                                                                 AS OF DECEMBER 31, 2000
                                                          -------------------------------------
                                                          DEVELOPED    UNDEVELOPED     TOTAL
                                                          ----------   -----------   ----------
<S>                                                       <C>          <C>           <C>
Oil and condensate (MBbl)...............................      26,690       18,498        45,188
Gas (MMcf)..............................................     672,867      351,444     1,024,311
Equivalent gas (MMcfe)..................................     833,008      462,430     1,295,438
Equivalent barrels (MBoe)...............................     138,834       77,072       215,906
Present value of estimated future net revenues before
  income taxes (discounted at 10%) (in thousands).......  $2,961,871   $1,213,347    $4,175,218
</TABLE>

     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
<PAGE>   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.

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              2000     1999     1998
                                                              -----    -----    -----
<S>                                                           <C>      <C>      <C>
Development:
  Productive................................................  54.2     22.9     59.4
  Non-productive............................................   0.0      0.0      0.0
                                                              ----     ----     ----
          Total.............................................  54.2     22.9     59.4
                                                              ----     ----     ----
Exploratory:
  Productive................................................   7.3      6.0      7.3
  Non-productive............................................   5.1      7.0      7.1
                                                              ----     ----     ----
          Total.............................................  12.4     13.0     14.4
                                                              ----     ----     ----
Total wells.................................................  66.6     35.9     73.8
                                                              ====     ====     ====
</TABLE>

                                        12
<PAGE>   13

                          PRODUCTIVE OIL AND GAS WELLS

     As of December 31, 2000, we owned interests in the following productive oil
and gas wells:

<TABLE>
<CAPTION>
                                         GROSS PRODUCTIVE WELLS(1)       NET PRODUCTIVE WELLS(1)
                                        ---------------------------   -----------------------------
                                                     NON-                          NON-
                                        OPERATED   OPERATED   TOTAL   OPERATED   OPERATED    TOTAL
                                        --------   --------   -----   --------   --------   -------
<S>                                     <C>        <C>        <C>     <C>        <C>        <C>
Oil...................................   1,475       171      1,646   1,441.0      37.8     1,478.8
Gas...................................   1,488        50      1,538   1,385.8      14.6     1,400.4
                                         -----       ---      -----   -------      ----     -------
          Total.......................   2,963       221      3,184   2,826.8      52.4     2,879.2
                                         =====       ===      =====   =======      ====     =======
</TABLE>

---------------

(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).

<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                              -----------------------------
                                                                2000      1999       1998
                                                              --------   -------   --------
<S>                                                           <C>        <C>       <C>
Acquisition costs:
  Unproved properties.......................................  $ 16,466   $12,908   $ 15,414
  Proved properties.........................................     7,281       201     12,615
Exploration costs...........................................    12,102     6,490     10,747
Development costs...........................................    87,424    67,760     78,736
                                                              --------   -------   --------
          Total costs incurred..............................  $123,273   $87,359   $117,512
                                                              ========   =======   ========
</TABLE>

                                        13
<PAGE>   14

                                   PRODUCTION

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

<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                              ------------------------------
                                                                2000       1999       1998
                                                              --------   --------   --------
<S>                                                           <C>        <C>        <C>
Net production:
  Oil and condensate (MBbl).................................     2,890      2,410      2,630
  Gas (MMcf)................................................    65,753     58,799     56,969
  Equivalent gas (MMcfe)....................................    83,091     73,257     72,750
  Equivalent barrels (MBoe).................................    13,849     12,210     12,125
Average net daily production(1):
  Oil and condensate (Bbl)..................................     8,206      6,959      6,378
  Gas (Mcf).................................................   186,385    165,371    141,336
  Equivalent gas (Mcfe).....................................   235,620    207,127    179,604
  Equivalent barrels (Boe)..................................    39,270     34,521     29,934
Average sales price per unit:
  Oil and condensate ($/Bbl)................................  $  25.51   $  15.70   $  14.58
  Gas ($/Mcf)...............................................  $   3.33   $   2.40   $   2.19
Lease operating expense ($/Mcfe)............................  $   0.36   $   0.38   $   0.42
Lease operating expense ($/Boe).............................  $   2.17   $   2.29   $   2.51
</TABLE>

---------------

(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
<PAGE>   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.

<TABLE>
<CAPTION>
QUARTER ENDED                                                  HIGH          LOW
-------------                                                 -------      -------
<S>                                                           <C>          <C>
March 31, 1998..............................................  15 5/8       12 13/16
June 30, 1998...............................................  17           13 9/16
September 30, 1998..........................................  15 1/4        7 1/2
December 31, 1998...........................................  11 15/16      6 1/4
March 31, 1999..............................................   8 7/8        5 1/2
June 30, 1999...............................................  14 3/4        8 1/4
September 30, 1999..........................................  17 1/4       13 1/8
December 31, 1999...........................................  17 1/4       12 1/2
March 31, 2000..............................................  21 1/8       14 5/16
June 30, 2000...............................................  33 13/16     18 5/8
September 30, 2000..........................................  36           24 5/8
December 31, 2000...........................................  44 3/8       28 5/8
</TABLE>

     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
<PAGE>   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.

<TABLE>
<CAPTION>
                                                          FOR THE YEARS ENDED DECEMBER 31,
                                             -----------------------------------------------------------
                                                2000         1999        1998        1997        1996
                                             -----------   ---------   ---------   ---------   ---------
                                             (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND AVERAGE PRICES)
<S>                                          <C>           <C>         <C>         <C>         <C>
STATEMENT OF OPERATIONS DATA
  Revenues
  Oil and gas sales........................  $  292,733    $179,016    $162,878    $142,496    $112,696
  Trading and transportation...............     139,914      52,662      54,144      90,062      46,373
  Gathering and transmission system
    revenues...............................      14,697       1,286          --          --          --
  Other revenues...........................      11,239      10,742       9,965       6,392       3,302
                                             ----------    --------    --------    --------    --------
         Total revenues....................     458,583     243,706     226,987     238,950     162,371
                                             ----------    --------    --------    --------    --------
  Expenses
  Production taxes.........................      26,118      10,309      10,422       9,703       8,195
  Lease operating..........................      30,069      28,014      30,410      24,848      17,692
  Cost of trading and transportation.......     132,505      49,567      50,451      88,402      45,699
  Gas transportation and gathering
    expenses...............................      15,448      14,356      12,791       5,245       5,415
  Gathering and transmission system
    operating expense......................       5,422         386          --          --          --
  Depreciation, depletion and
    amortization...........................      60,367      54,400      61,223      45,757      36,600
  Exploratory and abandonment..............      16,720      13,525      15,420      13,438       5,927
  Geological and geophysical...............      13,079       6,837      14,308      17,049       4,262
  Impairment and loss (gain) on sales of
    oil and gas properties.................       2,427      (1,171)     11,986      15,710       2,909
  General and administrative...............       8,612       5,823       8,061      11,550       8,497
  Interest.................................      49,239      42,781      41,990      32,297      23,594
                                             ----------    --------    --------    --------    --------
         Total expenses....................     360,006     224,827     257,062     263,999     158,790
                                             ----------    --------    --------    --------    --------
  Income (loss) before provision (benefit)
    for income taxes.......................      98,577      18,879     (30,075)    (25,049)      3,581
  Provision (benefit) for income taxes.....      37,952       7,193     (11,459)     (9,544)      1,364
                                             ----------    --------    --------    --------    --------
  Net income (loss)........................  $   60,625    $ 11,686    $(18,616)   $(15,505)   $  2,217
                                             ----------    --------    --------    --------    --------
  Diluted earnings (loss) per share........  $     3.18    $   0.62    $  (1.00)   $  (0.91)   $   0.15
                                             ----------    --------    --------    --------    --------
  Weighted average number of common shares
    outstanding assuming dilution..........      19,092      18,888      18,609      17,119      14,552
                                             ----------    --------    --------    --------    --------
BALANCE SHEET DATA
  Working capital (deficiency).............  $  (42,565)   $(38,507)   $(18,899)   $ (8,329)   $ 13,749
  Oil and gas properties, net..............     802,960     764,643     748,934     877,467     613,119
  Gas gathering and transportation
    facilities,
    net....................................      57,929      52,611       4,274       4,541       4,674
  Total assets.............................   1,043,824     908,792     832,439     956,306     695,644
  Long-term debt...........................     495,252     560,140     534,917     636,699     398,563
  Deferred income taxes....................      89,824      53,246      44,138      61,933      72,487
  Stockholders' equity.....................     221,582     165,007     152,861     173,477     169,424
OPERATING DATA
  Average sales price per barrel of oil....  $    25.51    $  15.70    $  14.58    $  19.71    $  20.90
  Average sales price per thousand cubic
    feet of gas............................  $     3.33    $   2.40    $   2.19    $   2.31    $   2.12
PRODUCTION
  Oil (Bbl)................................       2,890       2,410       2,630       2,400       1,923
  Gas (Mcf)................................      65,753      58,799      56,969      41,125      34,163
  Mcfe.....................................      83,091      73,257      72,750      55,524      45,702
  Boe......................................      13,849      12,210      12,125       9,254       7,617
NET CASH PROVIDED BY OPERATING
  ACTIVITIES...............................  $  186,209    $ 65,011    $ 60,505    $ 65,071    $ 38,549
</TABLE>

                                        16
<PAGE>   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
<PAGE>   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)

<TABLE>
<CAPTION>
                                                                2000       1999       1998
                                                              --------   --------   --------
<S>                                                           <C>        <C>        <C>
Production:
  Oil (Bbl).................................................     2,267      2,159      2,382
  Gas (Mcf).................................................    55,413     53,066     48,628
  Mcfe......................................................    69,013     66,018     62,920
  Boe.......................................................    11,502     11,003     10,487
Prices(1):
  Average realized oil price ($/Bbl)........................  $  24.16   $  15.33   $  14.78
  Average realized gas price ($/Mcf)........................  $   3.08   $   2.38   $   2.22
Operating Revenues:
  Oil and gas sales.........................................  $225,240   $159,393   $143,392
  Other gas revenues........................................     8,189     10,132      8,658
                                                              --------   --------   --------
                                                               233,429    169,525    152,050
                                                              --------   --------   --------
Operating Costs and Expenses:
  Production taxes..........................................    22,345      9,206      9,120
  Lease operating...........................................    28,685     27,139     25,938
  Gas transportation and gathering expense..................    15,448     14,356     12,791
  Depreciation, depletion and amortization..................    49,719     49,655     50,735
  Exploratory and abandonment...............................       526        952      1,188
  Geological and geophysical................................       461        307      1,892
  Impairment and loss (gain) on sales of oil and gas
     properties.............................................        --         71     (1,152)
                                                              --------   --------   --------
                                                               117,184    101,686    100,512
                                                              --------   --------   --------
Operating Income............................................  $116,245   $ 67,839   $ 51,538
                                                              ========   ========   ========
</TABLE>

---------------

(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
<PAGE>   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
<PAGE>   20

                                   GULF COAST

             OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)

<TABLE>
<CAPTION>
                                                               2000       1999       1998
                                                              -------   --------   --------
<S>                                                           <C>       <C>        <C>
Production:
  Oil (Bbl).................................................      620        251         30
  Gas (Mcf).................................................   10,214      5,566        883
  Mcfe......................................................   13,936      7,072      1,061
  Boe.......................................................    2,323      1,179        177
Prices (1):
  Average realized oil price ($/Bbl)........................  $ 30.45   $  18.90   $  11.99
  Average realized gas price ($/Mcf)........................  $  4.70   $   2.63   $   2.25
Operating Revenues:
  Oil and gas sales.........................................  $66,890   $ 19,365   $  2,344
Operating Costs and Expenses:
  Production taxes..........................................    3,724      1,047        131
  Lease operating...........................................    1,154        662        160
  Depreciation, depletion and amortization..................    8,161      3,158        510
  Exploratory and abandonment...............................   14,346     11,530      9,127
  Geological and geophysical................................    8,509      5,670     10,826
  Impairment and loss on sales of oil and gas properties....       97         --      1,061
                                                              -------   --------   --------
                                                               35,991     22,067     21,815
                                                              -------   --------   --------
Operating Income (Loss).....................................  $30,899   $ (2,702)  $(19,471)
                                                              =======   ========   ========
</TABLE>

---------------

(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
<PAGE>   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)

<TABLE>
<CAPTION>
                                                               2000      1999     1998(1)
                                                              -------   -------   --------
<S>                                                           <C>       <C>       <C>
Production:
  Oil (Bbl).................................................        3        --        218
  Gas (Mcf).................................................      126       166      7,459
  Mcfe......................................................      142       166      8,768
  Boe.......................................................       24        28      1,461
Prices(2):
  Average realized oil price ($/Bbl)........................  $ 29.62   $    --   $  12.80
  Average realized gas price ($/Mcf)........................  $  4.16   $  1.51   $   1.92
Operating Revenues:
  Oil and gas sales.........................................  $   603   $   258   $ 16,983
  Other gas revenues........................................       --        --         62
                                                              -------   -------   --------
                                                                  603       258     17,045
                                                              -------   -------   --------
Operating Costs and Expenses:
  Production taxes..........................................       50        55      1,172
  Lease operating...........................................      230       213      4,311
  Depreciation, depletion and amortization..................      131        70      8,042
  Exploratory and abandonment...............................    1,849     1,043      5,104
  Geological and geophysical................................    4,108       860      1,591
  Impairment and loss (gain) on sales of oil and gas
     properties.............................................    2,329    (1,241)    12,077
                                                              -------   -------   --------
                                                                8,697     1,000     32,297
                                                              -------   -------   --------
Operating Loss..............................................  $(8,094)  $  (742)  $(15,252)
                                                              =======   =======   ========
</TABLE>

---------------

(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
<PAGE>   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)

<TABLE>
<CAPTION>
                                                                2000       1999       1998
                                                              --------   --------   --------
<S>                                                           <C>        <C>        <C>
Operating Revenues:
  Trading and transportation(1).............................  $348,680   $170,232   $142,374
Operating Costs and Expenses:
  Cost of trading and transportation(1).....................   337,124    164,665    136,245
  Depreciation and amortization.............................       434        434        416
                                                              --------   --------   --------
                                                               337,558    165,099    136,661
                                                              --------   --------   --------
Operating Income............................................  $ 11,122   $  5,133   $  5,713
                                                              ========   ========   ========
</TABLE>

---------------

(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
<PAGE>   23

                         GAS GATHERING AND TRANSMISSION

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                               2000      1999    1998
                                                              -------   ------   ----
<S>                                                           <C>       <C>      <C>
Operating Revenues
  Gathering and transmission system revenues................  $12,485   $1,216   $--
  Income from interest in gathering plant...................    2,212       70    --
                                                              -------   ------   ---
                                                               14,697    1,286    --
Operating Costs and Expenses:
  Gathering and transmission system operating expenses......    5,422      386    --
  Depreciation and amortization.............................    1,117       92    --
  Interest expense..........................................    4,522      474    --
                                                              -------   ------   ---
                                                               11,061      952    --
                                                              -------   ------   ---
Operating Income............................................  $ 3,636   $  334   $--
                                                              =======   ======   ===
</TABLE>

     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)

<TABLE>
<CAPTION>
                                                               2000      1999      1998
                                                              -------   -------   -------
<S>                                                           <C>       <C>       <C>
Interest income and other...................................  $ 3,050   $   610   $ 1,405
General and administrative..................................  $ 8,612   $ 5,823   $ 8,061
Interest....................................................  $44,717   $42,307   $41,990
Depreciation................................................  $   805   $   991   $ 1,520
</TABLE>

     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
<PAGE>   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)

<TABLE>
<CAPTION>
                                                               2000      1999       1998
                                                              -------   -------   --------
<S>                                                           <C>       <C>       <C>
Current provision (benefit).................................  $(1,111)  $(2,100)  $  5,300
Deferred provision (benefit)................................   39,063     9,293    (16,759)
                                                              -------   -------   --------
Provision (benefit) for taxes...............................  $37,952   $ 7,193   $(11,459)
                                                              =======   =======   ========
Effective tax rate..........................................    38.5%     38.1%      38.1%
                                                              =======   =======   ========
</TABLE>

     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
<PAGE>   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
<PAGE>   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
<PAGE>   27

     As of December 31, 2000, we held specific swap positions as follows:

GAS HEDGES

<TABLE>
<CAPTION>
                                             AVERAGE DAILY                              MARK-TO-MARKET
                                               QUANTITY      SETTLEMENT      PRICE      PRESENT VALUE
TIME PERIOD                                     (MMBTU)       LOCATION    (PER MMBTU)        LOSS
-----------                                  -------------   ----------   -----------   --------------
<S>                                          <C>             <C>          <C>           <C>
January 2001-March 2001....................     20,000         NW           $2.3700     $ (11,806,121)
January 2001-March 2001....................     15,000         NW           $2.4310     $  (8,773,594)
January 2001-March 2001....................     20,000         NW           $2.4449     $ (11,673,517)
January 2001-March 2001....................     10,000         NW           $2.4520     $  (5,830,473)
January 2001-March 2001....................      5,000         NW           $2.4740     $  (2,905,499)
January 2001-March 2001....................     10,000         NW           $2.4790     $  (5,806,573)
January 2001-March 2001....................      5,000         NW           $2.4840     $  (2,901,073)
January 2001-March 2001....................     15,000         NW           $2.5050     $  (8,675,336)
April 2001-October 2001....................     20,000        NYMEX         $2.4230     $ (12,474,949)
April 2001-October 2001....................     10,000        NYMEX         $2.4400     $  (6,203,146)
April 2001-October 2001....................     10,000        NYMEX         $2.4950     $  (6,092,082)
April 2001-October 2001....................      5,000         NW           $2.2000     $  (2,692,655)
April 2001-October 2001....................     15,000         NW           $2.2130     $  (8,038,588)
April 2001-October 2001....................     45,000         NW           $2.4100     $ (23,861,327)
April 2001-October 2001....................      5,000         NW           $2.3500     $  (2,541,204)
April 2001-October 2001....................      5,000         NW           $2.4000     $  (2,490,720)
November 2001-December 2001................     15,000         NW           $2.1000     $  (2,547,427)
November 2001-December 2001................      5,000         NW           $2.1500     $    (835,290)
January 2002-March 2002....................     15,000         NW           $2.1500     $  (3,303,710)
January 2002-March 2002....................      5,000         NW           $2.2001     $  (1,081,164)
April 2002-October 2002....................     10,000        NYMEX         $2.5410     $  (3,053,512)
April 2002-October 2002....................      5,000        NYMEX         $2.6010     $  (1,471,918)
April 2002-October 2002....................     10,000        NYMEX         $2.9060     $  (2,386,315)
April 2002-October 2002....................     10,000        NYMEX         $3.1160     $  (2,002,448)
April 2002-October 2002....................     20,000         NW           $2.2240     $  (5,090,692)
April 2002-October 2002....................      5,000         NW           $2.2360     $  (1,261,705)
April 2002-October 2002....................     10,000         NW           $2.2590     $  (2,481,368)
April 2002-October 2002....................     25,000         NW           $2.2730     $  (6,139,442)
April 2002-October 2002....................     10,000         NW           $2.2860     $  (2,432,014)
April 2002-October 2002....................      5,000         NW           $2.3360     $  (1,170,308)
                                                                                        -------------
          Total............................                                             $(158,024,170)
                                                                                        =============
</TABLE>

GAS BASIS HEDGES

<TABLE>
<CAPTION>
                                                                                          MARK-TO-MARKET
                                             AVERAGE DAILY                   BASIS         PRESENT VALUE
                                               QUANTITY      SETTLEMENT   DIFFERENTIAL   DECEMBER 31, 2000
TIME PERIOD                                     (MMBTU)       LOCATION      (MMBTU)         GAIN (LOSS)
-----------                                  -------------   ----------   ------------   -----------------
<S>                                          <C>             <C>          <C>            <C>
November 2001-March 2002...................     30,000         NW           $-0.3100         $ (19,733)
January 2002-March 2002....................     15,000         NW           $-0.3000         $  14,679
November 2002-December 2002................     15,000         NW           $-0.3000         $ (28,231)
November 2002-March 2003...................     40,000         NW           $-0.3100         $(233,175)
April 2003 -March 2008.....................     10,000        CIG           $-0.3800         $  79,818
                                                                                             ---------
          Total............................                                                  $(186,642)
                                                                                             =========
</TABLE>

                                        27
<PAGE>   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

<TABLE>
<CAPTION>
                                                              AVERAGE DAILY
                                                                QUANTITY      SETTLEMENT    PRICE
TIME PERIOD                                                      (MMBTU)       LOCATION    (MMBTU)
-----------                                                   -------------   ----------   -------
<S>                                                           <C>             <C>          <C>
January 2001-December 2001..................................     20,000        NYMEX       $2.8875
</TABLE>

OIL SALES

<TABLE>
<CAPTION>
                                                              AVERAGE MONTHLY
                                                                 QUANTITY       SETTLEMENT   PRICE
TIME PERIOD                                                        (BBL)         LOCATION    (BBL)
-----------                                                   ---------------   ----------   ------
<S>                                                           <C>               <C>          <C>
January 2001-December 2001..................................      60,833         WTI         $18.59
</TABLE>

     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
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   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
<PAGE>   40

                               HS RESOURCES, INC.

                          CONSOLIDATED BALANCE SHEETS

                                     ASSETS

<TABLE>
<CAPTION>
                                                                   DECEMBER 31,
                                                              ----------------------
                                                                 2000        1999
                                                              ----------   ---------
                                                                  (IN THOUSANDS)
<S>                                                           <C>          <C>
Current Assets
  Cash and cash equivalents.................................  $    1,790   $     518
  Margin deposits...........................................       1,889         935
  Accounts receivable
     Oil and gas sales......................................      73,161      31,602
     Trading and transportation.............................      63,760      18,518
     Trade..................................................      12,714       3,089
     Ad valorem and production taxes........................       2,562      11,845
     Other..................................................       2,097       4,366
  Lease and well equipment inventory, at cost...............         904       1,249
  Mark-to-market receivable relating to trading activity....       6,466       2,841
  Prepaid expenses and other................................       1,260         613
  Imbalance receivable......................................         942         512
                                                              ----------   ---------
          Total current assets..............................     167,545      76,088
                                                              ----------   ---------
Oil and Gas Properties, at cost, using the successful
  efforts method Undeveloped acreage........................      90,231      99,358
  Costs subject to depreciation, depletion and
     amortization...........................................     997,466     892,976
  Less accumulated depreciation, depletion and
     amortization...........................................    (284,737)   (227,691)
                                                              ----------   ---------
          Net oil and gas properties........................     802,960     764,643
                                                              ----------   ---------
Gas Gathering and Transportation Facilities, at cost, net of
  accumulated depreciation of $4,897 and $2,016 at December
  31, 2000 and 1999, respectively...........................      57,929      52,611
                                                              ----------   ---------
Other Assets
  Deferred charges and other, net...........................       7,697       9,672
  Mark-to-market receivable relating to trading activity....       2,840         398
  Office and transportation equipment and other property,
     net of accumulated depreciation of $6,396 and $6,552 at
     December 31, 2000 and 1999, respectively...............       2,873       3,040
  Goodwill, net of accumulated amortization of $1,620 and
     $1,260 at December 31, 2000 and 1999, respectively
     (Note 2)...............................................       1,980       2,340
                                                              ----------   ---------
          Total other assets................................      15,390      15,450
                                                              ----------   ---------
          Total Assets......................................  $1,043,824   $ 908,792
                                                              ==========   =========
</TABLE>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.

                                        40
<PAGE>   41

                               HS RESOURCES, INC.

                          CONSOLIDATED BALANCE SHEETS

                      LIABILITIES AND STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                  2000          1999
                                                              ------------   ----------
                                                              (IN THOUSANDS, EXCEPT PER
                                                                     SHARE DATA)
<S>                                                           <C>            <C>

Current Liabilities
  Accounts payable
     Trade..................................................   $   39,681     $ 26,653
     Revenue................................................       85,109       36,897
     Gas purchases..........................................       35,035        9,290
  Accrued expenses
     Ad valorem and production taxes........................       12,119       10,624
     Interest...............................................        4,802        5,233
     Other..................................................        8,945        5,389
  Income taxes payable......................................           --          958
  Payable to KMI............................................       24,419       19,551
                                                               ----------     --------
          Total current liabilities.........................      210,110      114,595
                                                               ----------     --------
Accrued Ad Valorem Taxes and Other..........................       27,056       15,804
                                                               ----------     --------
Payable to KMI..............................................           --       27,556
                                                               ----------     --------
Long-Term Bank Debt.........................................      189,000      227,000
                                                               ----------     --------
9 7/8% Senior Subordinated Notes, due 2003, net of
  unamortized discount of $171 and $229 at December 31, 2000
  and 1999, respectively....................................       74,829       74,771
                                                               ----------     --------
9 1/4% Series A Senior Subordinated Notes, due 2006, net of
  unamortized discount of $456 and $534 at December 31, 2000
  and 1999, respectively....................................      149,544      149,466
                                                               ----------     --------
9 1/4% Series B Senior Subordinated Notes, due 2006, net of
  unamortized discount of $3,121 and $3,653 at December 31,
  2000 and 1999, respectively...............................       81,879       81,347
                                                               ----------     --------
Deferred Income Taxes.......................................       89,824       53,246
                                                               ----------     --------
Commitments and Contingencies
Stockholders' Equity (Note 6)
  Preferred stock...........................................           --           --
  Common stock, $.001 per share par value, 50,000 shares
     authorized; 19,920 and 19,528 shares issued and
     outstanding at December 31, 2000 and 1999,
     respectively...........................................           20           20
  Additional paid-in capital................................      201,850      191,406
  Retained earnings (deficit)...............................       46,323      (14,302)
  Notes receivable from officers for exercise of stock
     options (Note 7).......................................       (2,476)      (2,386)
  Deferred compensation.....................................       (3,459)      (1,981)
  Treasury stock, at cost, 1,841 and 731 shares at December
     31, 2000 and 1999, respectively........................      (20,676)      (7,750)
                                                               ----------     --------
          Total stockholders' equity........................      221,582      165,007
                                                               ----------     --------
          Total Liabilities and Stockholders' Equity........   $1,043,824     $908,792
                                                               ==========     ========
</TABLE>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.

                                        41
<PAGE>   42

                               HS RESOURCES, INC.

                     CONSOLIDATED STATEMENTS OF OPERATIONS
                        FOR THE YEARS ENDED DECEMBER 31,

<TABLE>
<CAPTION>
                                                                  2000           1999           1998
                                                              ------------   ------------   ------------
                                                               (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                                                           <C>            <C>            <C>
Revenues
  Oil and gas sales.........................................    $292,733       $179,016       $162,878
  Trading and transportation................................     139,914         52,662         54,144
  Other gas revenues........................................       8,189         10,132          8,560
  Gathering and transmission system revenues................      12,485          1,216             --
  Income from interest in gathering plant...................       2,212             70             --
  Interest income and other.................................       3,050            610          1,405
                                                                --------       --------       --------
          Total revenues....................................     458,583        243,706        226,987
                                                                --------       --------       --------
Expenses
  Production taxes..........................................      26,118         10,309         10,422
  Lease operating...........................................      30,069         28,014         30,410
  Cost of trading and transportation........................     132,505         49,567         50,451
  Gas transportation and gathering expense..................      15,448         14,356         12,791
  Gathering and transmission system operating expenses......       5,422            386             --
  Depreciation, depletion and amortization..................      60,367         54,400         61,223
  Exploratory and abandonment...............................      16,720         13,525         15,420
  Geological and geophysical................................      13,079          6,837         14,308
  Impairment and loss (gain) on sales of oil and gas
     properties.............................................       2,427         (1,171)        11,986
  General and administrative................................       8,612          5,823          8,061
  Interest, net of amounts capitalized......................      49,239         42,781         41,990
                                                                --------       --------       --------
          Total expenses....................................     360,006        224,827        257,062
                                                                --------       --------       --------
Income (loss) before provision (benefit) for income taxes...      98,577         18,879        (30,075)
Provision (benefit) for income taxes........................      37,952          7,193        (11,459)
                                                                --------       --------       --------
Net income (loss)...........................................    $ 60,625       $ 11,686       $(18,616)
                                                                ========       ========       ========
Basic earnings (loss) per share.............................    $   3.29       $   0.63       $  (1.00)
                                                                ========       ========       ========
Diluted earnings (loss) per share...........................    $   3.18       $   0.62       $  (1.00)
                                                                ========       ========       ========
Weighted average number of common shares outstanding........      18,420         18,697         18,609
                                                                ========       ========       ========
Weighted average number of common shares outstanding
  assuming dilution.........................................      19,092         18,888         18,609
                                                                ========       ========       ========
</TABLE>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.

                                        42
<PAGE>   43

                               HS RESOURCES, INC.

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                        FOR THE YEARS ENDED DECEMBER 31,

<TABLE>
<CAPTION>
                                  COMMON STOCK     ADDITIONAL   RETAINED        NOTES                        TREASURY STOCK
                                 ---------------    PAID-IN     EARNINGS     RECEIVABLE       DEFERRED     ------------------
                                 SHARES   AMOUNT    CAPITAL     (DEFICIT)   FROM OFFICERS   COMPENSATION   SHARES     AMOUNT
                                 ------   ------   ----------   ---------   -------------   ------------   -------   --------
                                                                        (IN THOUSANDS)
<S>                              <C>      <C>      <C>          <C>         <C>             <C>            <C>       <C>
BALANCE, DECEMBER 31, 1997.....  18,655    $ 19    $ 183,191    $ (7,372)      $    --        $  (144)        (160)  $ (2,217)
  Purchase of treasury stock...      --      --         (115)         --            --             --         (680)    (5,941)
  Transfer of treasury stock to
    40l(k) Plan................      --      --            7          --            --             --           39        542
  Issuance of restricted
    stock......................      32      --          428          --            --           (428)          --         --
  Amortization of deferred
    compensation...............      --      --           --          --            --            307           --         --
  Issuance of performance
    shares.....................     106      --        1,534          --            --         (1,534)          --         --
  Exercise of stock options,
    including income tax
    benefit....................     337      --        3,201          --        (2,142)            --           --         --
  Interest on notes
    receivable.................      --      --           --          --          (104)            --           --         --
  Restricted stock forfeited...      (3)     --          (50)         --            --             50           --         --
  Net loss.....................      --      --           --     (18,616)           --             --           --         --
                                 ------    ----    ---------    --------       -------        -------      -------   --------
BALANCE, DECEMBER 31, 1998.....  19,127      19      188,196     (25,988)       (2,246)        (1,749)        (801)    (7,616)
                                 ======    ====    =========    ========       =======        =======      =======   ========
  Purchase of treasury stock...      --      --          492          --            --             --           (5)      (846)
  Transfer of treasury stock to
    40l(k) Plan................      --      --           50          --            --             --           75        712
  Issuance of restricted
    stock......................      34      --          301          --            --           (301)          --         --
  Amortization of deferred
    compensation...............      --      --           --          --            --          1,067           --         --
  Issuance of performance
    shares.....................     132       1          997          --            --           (998)          --         --
  Issuance of common stock.....     235      --        1,370          --          (759)            --           --         --
  Interest on notes
    receivable.................      --      --           --          --          (204)            --           --         --
  Payment of officer notes and
    interest...................      --      --           --          --           823             --           --         --
  Net income...................      --      --           --      11,686            --             --           --         --
                                 ------    ----    ---------    --------       -------        -------      -------   --------
BALANCE, DECEMBER 31, 1999.....  19,528      20      191,406     (14,302)       (2,386)        (1,981)        (731)    (7,750)
                                 ======    ====    =========    ========       =======        =======      =======   ========
  Purchase of treasury stock...      --      --          746          --            --             --       (1,172)   (13,598)
  Transfer of treasury stock to
    40l(k) Plan................      --      --          385          --            --             --           62        672
  Issuance of restricted
    stock......................      26      --          524          --            --           (524)          --         --
  Amortization of deferred
    compensation...............      --      --           --          --            --          1,507           --         --
  Issuance of performance
    shares.....................     100      --        2,519          --            --         (2,519)          --         --
  Restricted stock and
    performance shares
    forfeited..................      (9)     --          (58)         --            --             58           --         --
  Exercise of warrants and
    options....................     275      --        6,328          --        (1,601)            --           --         --
  Interest on notes
    receivable.................      --      --           --          --          (113)            --           --         --
  Payment of officer notes and
    interest...................      --      --           --          --         1,624             --           --         --
  Net income...................      --      --           --      60,625            --             --           --         --
                                 ------    ----    ---------    --------       -------        -------      -------   --------
BALANCE, DECEMBER 31, 2000.....  19,920    $ 20    $ 201,850    $ 46,323       $(2,476)       $(3,459)      (1,841)  $(20,676)
                                 ======    ====    =========    ========       =======        =======      =======   ========
</TABLE>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.

                                        43
<PAGE>   44

                               HS RESOURCES, INC.

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                        FOR THE YEARS ENDED DECEMBER 31,

<TABLE>
<CAPTION>
                                                                2000        1999       1998
                                                              ---------   --------   ---------
                                                                       (IN THOUSANDS)
<S>                                                           <C>         <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net income (loss).........................................  $  60,625   $ 11,686   $ (18,616)
  Adjustments to reconcile net income (loss) to net cash
    provided by operating activities
    Depreciation, depletion and amortization................     60,367     54,400      61,223
    Depreciation expense offset against income..............      1,444         --          --
    Impairment and loss (gain) on sales of oil and gas
      properties............................................      2,427     (1,171)     11,986
    Amortization of deferred charges, debt issue costs and
      deferred compensation.................................      4,255      4,210       2,621
    Surrendered and expired acreage.........................      6,674      5,211      10,422
    Transfer of treasury stock to 401(k) Plan...............      1,057        763         549
    Gain on sale of fixed assets............................         --         --        (235)
    Deferred income tax provision (benefit).................     39,063      7,008     (14,106)
    Increase in accounts and notes receivable...............    (84,873)   (22,523)     (1,186)
    Increase in accounts payable and accrued expenses.......    103,142     18,524      10,069
    Decrease in deferred revenue, net.......................         --     (8,908)       (965)
    Other...................................................     (7,972)    (4,189)     (1,257)
                                                              ---------   --------   ---------
         Net cash provided by operating activities..........    186,209     65,011      60,505
                                                              ---------   --------   ---------
CASH FLOWS FROM INVESTING ACTIVITIES
  Exploration, development and leasehold costs..............    (97,175)   (75,209)    (98,307)
  Purchase of unproved and proved properties................     (7,281)        --      (4,754)
  Gas gathering and transportation facilities additions.....     (8,176)    (1,629)        (28)
  Other property additions..................................       (858)    (1,228)       (859)
  Net (payment) proceeds from the sale of oil and gas
    properties..............................................       (530)     3,026     151,031
  Proceeds from the sale of fixed assets and other
    property................................................         --         --       1,234
  (Increase) decrease in property related payables..........     (4,544)     2,809       3,694
                                                              ---------   --------   ---------
         Net cash (used in) provided by investing
           activities.......................................   (118,564)   (72,231)     52,011
                                                              ---------   --------   ---------
CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds from bank debt...................................    180,000     81,000     154,750
  Repayments of bank debt...................................   (218,000)   (84,000)   (256,000)
  Repayment of KMI debt.....................................    (19,388)        --          --
  Debt issuance costs.......................................         --         --      (2,460)
  Issuance of common stock..................................         --        611          --
  Exercise of options and warrants..........................      4,677      1,701         468
  Purchase of treasury stock................................    (15,286)    (2,055)     (6,524)
  Payment of officer note and interest......................      1,624        823          --
                                                              ---------   --------   ---------
         Net cash used in financing activities..............    (66,373)    (1,920)   (109,766)
                                                              ---------   --------   ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........      1,272     (9,140)      2,750
  Cash and cash equivalents, beginning of year..............        518      9,658       6,908
                                                              ---------   --------   ---------
  Cash and cash equivalents, end of year....................  $   1,790   $    518   $   9,658
                                                              =========   ========   =========
SUPPLEMENTAL CASH FLOW DISCLOSURE
  Interest paid, net of capitalized interest................  $  46,888   $ 40,542   $  36,481
  Cash paid for income taxes, net of reimbursements.........  $   1,195   $    (68)  $   3,135
  Schedule of noncash investing and financing activities:
    Issuance of stock for officer notes.....................  $   1,601   $     --   $      --
    Tax benefit on stock option exercise....................  $   2,485   $     --   $      --
    Purchase of Wattenberg Gathering System for a note
      payable...............................................  $      --   $ 48,070   $      --
</TABLE>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.

                                        44
<PAGE>   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
<PAGE>   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
<PAGE>   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):

<TABLE>
<CAPTION>
FINANCIAL STATEMENT ACCOUNT                                    AMOUNT
---------------------------                                    -------
<S>                                                            <C>
Current asset...............................................   $  38.5
Long-term asset.............................................   $   5.4
Current liability...........................................   $(148.0)
Long-term liability.........................................   $ (36.8)
Deferred taxes..............................................   $  54.2
Cumulative effect of a change in accounting principle (other
  comprehensive income).....................................   $  86.7
</TABLE>

     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
<PAGE>   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
<PAGE>   49
                               HS RESOURCES, INC.

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     As of December 31, 2000, we held specific swap positions as follows:

GAS HEDGES

<TABLE>
<CAPTION>
                                            AVERAGE DAILY                              MARK-TO-MARKET
                                              QUANTITY      SETTLEMENT      PRICE      PRESENT VALUE
TIME PERIOD                                    (MMBTU)       LOCATION    (PER MMBTU)        LOSS
-----------                                 -------------   ----------   -----------   --------------
<S>                                         <C>             <C>          <C>           <C>
January 2001-March 2001...................     20,000            NW        $2.3700     $ (11,806,121)
January 2001-March 2001...................     15,000            NW        $2.4310     $  (8,773,594)
January 2001-March 2001...................     20,000            NW        $2.4449     $ (11,673,517)
January 2001-March 2001...................     10,000            NW        $2.4520     $  (5,830,473)
January 2001-March 2001...................      5,000            NW        $2.4740     $  (2,905,499)
January 2001-March 2001...................     10,000            NW        $2.4790     $  (5,806,573)
January 2001-March 2001...................      5,000            NW        $2.4840     $  (2,901,073)
January 2001-March 2001...................     15,000            NW        $2.5050     $  (8,675,336)
April 2001-October 2001...................     20,000         NYMEX        $2.4230     $ (12,474,949)
April 2001-October 2001...................     10,000         NYMEX        $2.4400     $  (6,203,146)
April 2001-October 2001...................     10,000         NYMEX        $2.4950     $  (6,092,082)
April 2001-October 2001...................      5,000            NW        $2.2000     $  (2,692,655)
April 2001-October 2001...................     15,000            NW        $2.2130     $  (8,038,588)
April 2001-October 2001...................     45,000            NW        $2.4100     $ (23,861,327)
April 2001-October 2001...................      5,000            NW        $2.3500     $  (2,541,204)
April 2001-October 2001...................      5,000            NW        $2.4000     $  (2,490,720)
November 2001-December 2001...............     15,000            NW        $2.1000     $  (2,547,427)
November 2001-December 2001...............      5,000            NW        $2.1500     $    (835,290)
January 2002-March 2002...................     15,000            NW        $2.1500     $  (3,303,710)
January 2002-March 2002...................      5,000            NW        $2.2001     $  (1,081,164)
April 2002-October 2002...................     10,000         NYMEX        $2.5410     $  (3,053,512)
April 2002-October 2002...................      5,000         NYMEX        $2.6010     $  (1,471,918)
April 2002-October 2002...................     10,000         NYMEX        $2.9060     $  (2,386,315)
April 2002-October 2002...................     10,000         NYMEX        $3.1160     $  (2,002,448)
April 2002-October 2002...................     20,000            NW        $2.2240     $  (5,090,692)
April 2002-October 2002...................      5,000            NW        $2.2360     $  (1,261,705)
April 2002-October 2002...................     10,000            NW        $2.2590     $  (2,481,368)
April 2002-October 2002...................     25,000            NW        $2.2730     $  (6,139,442)
April 2002-October 2002...................     10,000            NW        $2.2860     $  (2,432,014)
April 2002-October 2002...................      5,000            NW        $2.3360     $  (1,170,308)
                                                                                       -------------
          Total...........................                                             $(158,024,170)
                                                                                       =============
</TABLE>

GAS BASIS HEDGES

<TABLE>
<CAPTION>
                                                                                         MARK-TO-MARKET
                                            AVERAGE DAILY                   BASIS         PRESENT VALUE
                                              QUANTITY      SETTLEMENT   DIFFERENTIAL   DECEMBER 31, 2000
TIME PERIOD                                    (MMBTU)       LOCATION      (MMBTU)         GAIN (LOSS)
-----------                                 -------------   ----------   ------------   -----------------
<S>                                         <C>             <C>          <C>            <C>
November 2001-March 2002..................     30,000           NW         $-0.3100         $ (19,733)
January 2002-March 2002...................     15,000           NW         $-0.3000         $  14,679
November 2002-December 2002...............     15,000           NW         $-0.3000         $ (28,231)
November 2002-March 2003..................     40,000           NW         $-0.3100         $(233,175)
April 2003-March 2008.....................     10,000          CIG         $-0.3800         $  79,818
                                                                                            ---------
          Total...........................                                                  $(186,642)
                                                                                            =========
</TABLE>

                                        49
<PAGE>   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

<TABLE>
<CAPTION>
                                                             AVERAGE DAILY
                                                               QUANTITY      SETTLEMENT    PRICE
TIME PERIOD                                                     (MMBTU)       LOCATION    (MMBTU)
-----------                                                  -------------   ----------   -------
<S>                                                          <C>             <C>          <C>
January 2001-December 2001.................................     20,000         NYMEX      $2.8875
</TABLE>

OIL SALES

<TABLE>
<CAPTION>
                                                             AVERAGE MONTHLY
                                                                QUANTITY       SETTLEMENT   PRICE
TIME PERIOD                                                       (BBL)         LOCATION    (BBL)
-----------                                                  ---------------   ----------   ------
<S>                                                          <C>               <C>          <C>
January 2001-December 2001.................................      60,833           WTI       $18.59
</TABLE>

     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
<PAGE>   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):

<TABLE>
<CAPTION>
                                                                2000       1999
                                                              --------   --------
<S>                                                           <C>        <C>
Bank debt...................................................  $189,000   $227,000
Payable to KMI..............................................    24,419     47,107
                                                              --------   --------
                                                               213,419    274,107
Less-current portion of payable to KMI......................   (24,419)   (19,551)
                                                              --------   --------
Long-term bank debt and payable to KMI, net of current
  portion...................................................  $189,000   $254,556
                                                              ========   ========
9 7/8% Senior Subordinated notes, due 2003, net of
  unamortized discount of $171 and $229 at December 31, 2000
  and 1999, respectively....................................  $ 74,829   $ 74,771
                                                              ========   ========
9 1/4% Series A Senior Subordinated notes, due 2006, net of
  unamortized discount of $456 and $534 at December 31, 2000
  and 1999, respectively....................................  $149,544   $149,466
                                                              ========   ========
9 1/4% Series B Senior Subordinated notes, due 2006, net of
  unamortized discount of $3,121 and $3,653 at December 31,
  2000 and 1999, respectively...............................  $ 81,879   $ 81,347
                                                              ========   ========
</TABLE>

     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
<PAGE>   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:

<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31,                                          AMOUNT
------------------------                                      --------------
                                                              (IN THOUSANDS)
<S>                                                           <C>
2001........................................................     $ 24,419
2002........................................................      189,000
2003........................................................       74,829
2004........................................................           --
2005........................................................           --
Thereafter..................................................      231,423
                                                                 --------
                                                                 $519,671
                                                                 ========
</TABLE>

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
<PAGE>   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
<PAGE>   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):

<TABLE>
<CAPTION>
                                                          2000      1999       1998
                                                         -------   -------   --------
<S>                                                      <C>       <C>       <C>
Current:
  Federal..............................................  $   132   $(2,300)  $  3,100
  State................................................   (1,243)      200      2,200
                                                         -------   -------   --------
                                                          (1,111)   (2,100)     5,300
                                                         -------   -------   --------
Deferred:
  Federal..............................................   34,370     8,420    (14,955)
  State................................................    4,693       873     (1,804)
                                                         -------   -------   --------
                                                          39,063     9,293    (16,759)
                                                         -------   -------   --------
                                                         $37,952   $ 7,193   $(11,459)
                                                         =======   =======   ========
</TABLE>

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

<TABLE>
<CAPTION>
                                                         2000      1999       1998
                                                        -------   -------   --------
<S>                                                     <C>       <C>       <C>
TYPE OF TEMPORARY DIFFERENCE
Alternative minimum tax...............................  $  (518)  $ 2,600   $ (3,100)
Depreciation, depletion and amortization..............   (4,862)   (6,895)   (16,903)
Intangible drilling costs.............................   32,317    12,192     25,428
Sales of properties...................................     (270)     (667)   (28,174)
Operating loss carryforwards..........................   12,396     2,063      5,990
                                                        -------   -------   --------
Deferred tax provision (benefit)......................  $39,063   $ 9,293   $(16,759)
                                                        =======   =======   ========
</TABLE>

                                        54
<PAGE>   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):

<TABLE>
<CAPTION>
                                                                2000       1999
                                                              --------   --------
<S>                                                           <C>        <C>
DEFERRED TAX LIABILITIES
Depreciation and basis difference...........................  $104,236   $ 60,817
                                                              --------   --------
Deferred tax liability......................................   104,236     60,817
DEFERRED TAX ASSETS
Tax effect of regular net operating loss....................    10,391      3,855
Alternative minimum tax credit..............................     1,634      1,396
Statutory depletion carryforwards...........................     2,387      2,320
                                                              --------   --------
Deferred tax assets.........................................    14,412      7,571
                                                              --------   --------
Net deferred tax liability..................................  $ 89,824   $ 53,246
                                                              ========   ========
</TABLE>

     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
<PAGE>   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:

<TABLE>
<CAPTION>
                                                                             WEIGHTED AVERAGE
                                                            SHARES             OPTION PRICE
                                                            ------           ----------------
                                                          (SHARES IN
                                                          THOUSANDS)
<S>                                                  <C>                     <C>
Outstanding at December 31, 1997
  (635 shares exercisable).........................            889               $ 11.39
  Granted..........................................            713               $ 11.26
  Exercised........................................           (379)              $  6.95
  Forfeited........................................           (198)              $ 14.14
                                                             -----               -------
Outstanding at December 31, 1998
  (448 shares exercisable).........................          1,025               $ 13.89
  Granted..........................................            509               $  9.59
  Exercised........................................           (123)              $ 12.32
  Forfeited........................................            (20)              $ 14.76
                                                             -----               -------
Outstanding at December 31, 1999
  (526 shares exercisable).........................          1,391               $ 12.44
  Granted..........................................            403               $ 20.12
  Exercised........................................           (420)              $ 14.83
  Forfeited........................................            (71)              $ 11.46
                                                             -----               -------
Outstanding at December 31, 2000
  (396 shares exercisable at a
  weighted average price of $12.15)................          1,303               $ 14.09
                                                             -----               -------
</TABLE>

                                        56
<PAGE>   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):

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31,
                                                         ----------------------------
                                                          2000      1999       1998
                                                         -------   -------   --------
<S>                                                      <C>       <C>       <C>
Net income (loss) applicable to common stockholders:
  As reported..........................................  $60,625   $11,686   $(18,616)
                                                         =======   =======   ========
  Pro forma............................................  $59,941   $10,700   $(19,423)
                                                         =======   =======   ========
Net income (loss) per share
  As reported..........................................  $  3.18   $  0.62   $  (1.00)
                                                         =======   =======   ========
  Pro forma............................................  $  3.14   $  0.57   $  (1.04)
                                                         =======   =======   ========
</TABLE>

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

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2000     1999     1998
                                                              ------   ------   ------
<S>                                                           <C>      <C>      <C>
Risk-free interest rates....................................   6.1%    5.51%    4.62%
Expected dividend yield rates...............................  0.00%    0.00%    0.00%
Expected volatility.........................................    56%      46%      45%
</TABLE>

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

<TABLE>
<CAPTION>
                                               OPTIONS OUTSTANDING
                                              ----------------------      OPTIONS EXERCISABLE
                                               WEIGHTED                -------------------------
                                                AVERAGE     WEIGHTED                    WEIGHTED
                                 NUMBER        REMAINING    AVERAGE        NUMBER       AVERAGE
RANGE OF                      OUTSTANDING     CONTRACTUAL   EXERCISE    EXERCISABLE     EXERCISE
EXERCISE PRICES              (IN THOUSANDS)      LIFE        PRICE     (IN THOUSANDS)    PRICE
---------------              --------------   -----------   --------   --------------   --------
<S>                          <C>              <C>           <C>        <C>              <C>
$6.06 to $10.13............       436         5.01 years     $ 9.02         133          $ 9.32
$11.00 to $14.63...........       435         5.10 years     $13.46         256          $13.47
$14.75 to $39.00...........       432         6.37 years     $19.85           7          $17.62
</TABLE>

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
<PAGE>   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):

<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31,
------------------------
<S>                                                            <C>
2001........................................................   $ 5,377
2002........................................................     9,556
2003........................................................     5,694
2004........................................................     2,855
2005........................................................     2,518
Thereafter..................................................    11,832
                                                               -------
          Total minimum lease payments......................   $37,832
                                                               =======
</TABLE>

     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
<PAGE>   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):

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31,
                                                         ---------------------------
                                                          2000      1999      1998
                                                         -------   -------   -------
<S>                                                      <C>       <C>       <C>
Property acquisition costs
  Unproved.............................................  $16,466   $12,908   $15,414
  Proved...............................................  $ 7,281   $   201   $12,615
                                                         -------   -------   -------
Exploration costs......................................  $12,102   $ 6,490   $10,747
                                                         -------   -------   -------
Development costs......................................  $87,424   $67,760   $78,736
                                                         -------   -------   -------
Depreciation, depletion and amortization...............  $57,568   $52,435   $58,992
                                                         -------   -------   -------
Depreciation, depletion and amortization per equivalent
  barrel of oil production.............................  $  4.16   $  4.30   $  4.87
                                                         =======   =======   =======
</TABLE>

                                        59
<PAGE>   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

<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                             -------------------------------
                                                               2000        1999       1998
                                                             ---------   --------   --------
                                                                     (IN THOUSANDS)
<S>                                                          <C>         <C>        <C>
Operating Revenues:
  Oil and gas sales D-J Basin..............................  $ 233,429   $169,525   $152,050
  Oil and gas sales Gulf Coast.............................     66,890     19,365      2,344
  Oil and gas sales Mid-Continent and other................        603        258     17,045
  Gas gathering and transportation facilities..............     14,697      1,286         --
  Trading and transportation...............................    348,680    170,232    142,374
  Intersegment eliminations................................   (208,766)  (117,570)   (88,231)
                                                             ---------   --------   --------
                                                             $ 455,533   $243,096   $225,582
                                                             =========   ========   ========
Operating Income (Loss):
  D-J Basin................................................  $ 116,245   $ 67,839   $ 51,538
  Gulf Coast...............................................     30,899     (2,702)   (19,471)
  Mid-Continent and other..................................     (8,094)      (742)   (15,252)
  Gas gathering and transportation facilities..............      3,636        334         --
  Trading and transportation...............................     11,122      5,133      5,713
  Intersegment eliminations................................     (4,147)    (2,472)    (2,436)
                                                             ---------   --------   --------
Operating Income...........................................    149,661     67,390     20,092
  Other income and expense.................................    (51,084)   (48,511)   (50,167)
                                                             ---------   --------   --------
Income (Loss) before income taxes..........................  $  98,577   $ 18,879   $(30,075)
                                                             =========   ========   ========
Identifiable Assets (net) (at December 31):
  Oil and gas properties D-J Basin.........................  $ 755,047   $728,494   $723,133
  Oil and gas properties Gulf Coast........................     41,976     30,918     21,535
  Oil and gas properties Mid-Continent and other...........      6,927      6,063      4,266
  Gas gathering and transportation facilities..............     57,929     52,612      4,275
  Trading and transportation...............................      2,053      2,450      2,803
  Corporate................................................      1,810      2,097      2,914
                                                             ---------   --------   --------
                                                             $ 865,742   $822,634   $758,926
                                                             =========   ========   ========
Depreciation, Depletion and Amortization Expense:
  Oil and gas properties D-J Basin.........................  $  49,719   $ 49,655   $ 50,735
  Oil and gas properties Gulf Coast........................      8,161      3,158        510
  Oil and gas properties Mid-Continent and other...........        131         70      8,042
  Gas gathering and transportation facilities..............      1,117         92         --
  Trading and transportation...............................        434        434        416
  Corporate................................................        805        991      1,520
                                                             ---------   --------   --------
                                                             $  60,367   $ 54,400   $ 61,223
                                                             =========   ========   ========
Capital Expenditures and Acquisitions:
  Oil and gas properties D-J Basin.........................  $  77,006   $ 56,682   $ 71,139
  Oil and gas properties Gulf Coast........................     25,692     16,739     14,418
  Oil and gas properties Mid-Continent and other...........      2,023      2,663     17,504
  Gas gathering and transportation facilities..............      8,199     48,736         28
  Trading and transportation...............................         20         62         51
  Corporate................................................        550        446        838
                                                             ---------   --------   --------
                                                             $ 113,490   $125,328   $103,978
                                                             =========   ========   ========
</TABLE>

                                        60
<PAGE>   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

<TABLE>
<CAPTION>
                                                               OIL        GAS
PROVED DEVELOPED AND UNDEVELOPED RESERVES                     (MBBL)    (MMCF)
-----------------------------------------                     ------   ---------
<S>                                                           <C>      <C>
Balance, December 31, 1997..................................  45,358     879,854
  Revision of previous estimates............................  (7,025)    (54,286)
  Extensions, discoveries and other additions...............   5,878     185,208
  Production................................................  (2,630)    (56,969)
  Purchases of reserves in place............................     392       7,672
  Sales of reserves in place................................  (4,529)   (164,430)
                                                              ------   ---------
Balance, December 31, 1998..................................  37,444     797,049
  Revision of previous estimates............................   2,600       7,230
  Extensions, discoveries and other additions...............   2,975     128,768
  Production................................................  (2,410)    (58,799)
  Purchases of reserves in place............................     443       5,627
  Sales of reserves in place................................    (424)    (12,094)
                                                              ------   ---------
Balance, December 31, 1999..................................  40,628     867,781
  Revision of previous estimates............................   2,547      20,430
  Extensions, discoveries and other additions...............   4,613     190,711
  Production................................................  (2,890)    (65,753)
  Purchases of reserves in place............................     290      11,150
  Sales of reserves in place................................      --          (8)
                                                              ------   ---------
Balance, December 31, 2000..................................  45,188   1,024,311
                                                              ======   =========
Proved developed reserves
  December 31, 1998.........................................  23,558     561,410
                                                              ======   =========
  December 31, 1999.........................................  24,268     585,465
                                                              ======   =========
  December 31, 2000.........................................  26,690     672,867
                                                              ======   =========
</TABLE>

                                        61
<PAGE>   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):

<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                                -------------------------------------
                                                   2000          1999         1998
                                                -----------   ----------   ----------
<S>                                             <C>           <C>          <C>
Future cash inflows...........................  $10,266,093   $3,117,797   $1,923,811
Future production costs.......................   (1,225,809)    (595,244)    (460,431)
Future development costs......................     (503,652)    (398,115)    (335,904)
                                                -----------   ----------   ----------
Undiscounted future pre-tax cash flows........    8,536,632    2,124,438    1,127,476
Undiscounted future income taxes..............   (2,749,572)    (549,471)    (215,320)
                                                -----------   ----------   ----------
Undiscounted future pre-tax cash flows, net of
  future income taxes.........................    5,787,060    1,574,967      912,156
10% discount factor...........................   (2,957,618)    (794,918)    (476,276)
                                                -----------   ----------   ----------
Standardized measure of discounted future net
  cash flows..................................  $ 2,829,442   $  780,049   $  435,880
                                                -----------   ----------   ----------
Discounted pre-tax future cash flows..........  $ 4,175,218   $1,051,064   $  531,905
                                                ===========   ==========   ==========
</TABLE>

     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):

<TABLE>
<CAPTION>
                                                        YEAR ENDED DECEMBER 31,
                                                  -----------------------------------
                                                     2000         1999        1998
                                                  -----------   ---------   ---------
<S>                                               <C>           <C>         <C>
Standardized measure of discounted future net
  cash flows, beginning of the year.............  $   780,049   $ 435,880   $ 629,451
Sales and transfers of oil and gas produced, net
  of production costs...........................     (285,446)   (124,467)   (108,623)
Sales of reserves in place......................          (10)     (5,738)   (157,547)
Net changes in prices and production costs on
  beginning of year reserves....................    2,359,779     373,733    (199,052)
Extensions, discoveries and improved recovery,
  less related costs............................      747,641     159,851     162,530
Changes in future development costs.............      (59,484)    (70,528)      2,808
Development costs incurred during the period
  that reduced future development costs.........       94,663      67,937      78,540
Revisions of previous quantity estimates........      120,233      24,374     (55,618)
Purchase of reserves in place...................       43,979       9,153       6,328
Accretion of discount...........................      105,107      53,191      73,099
Net change in income taxes......................   (1,074,761)   (174,990)      5,518
Changes in production rates (timing) and
  other.........................................       (2,308)     31,653      (1,554)
                                                  -----------   ---------   ---------
Standardized measure of discounted future net
  cash flows, end of the year...................  $ 2,829,442   $ 780,049   $ 435,880
                                                  ===========   =========   =========
</TABLE>

                                        62
<PAGE>   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):

<TABLE>
<CAPTION>
                                                              2000
                                             ---------------------------------------
                                             MAR. 31   JUNE 30   SEPT. 30   DEC. 31
                                             -------   -------   --------   --------
<S>                                          <C>       <C>       <C>        <C>
Operating revenues.........................  $86,170   $98,757   $108,771   $161,834
Operating expenses.........................   55,899    66,584     73,554    106,117
                                             -------   -------   --------   --------
Operating income...........................   30,271    32,173     35,217     55,717
                                             -------   -------   --------   --------
Net income.................................  $10,116   $11,417   $ 13,796   $ 25,296
                                             -------   -------   --------   --------
Diluted earnings per share.................  $  0.53   $  0.60   $   0.72   $   1.34
                                             -------   -------   --------   --------
</TABLE>

                                        63
<PAGE>   64
                               HS RESOURCES, INC.

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
                                                              1999
                                             ---------------------------------------
                                             MAR. 31   JUNE 30   SEPT. 30   DEC. 31
                                             -------   -------   --------   --------
<S>                                          <C>       <C>       <C>        <C>
Operating revenues.........................  $51,473   $54,870   $ 60,958   $ 75,795
Operating expenses.........................   39,619    43,215     41,146     52,242
                                             -------   -------   --------   --------
Operating income...........................   11,854    11,655     19,812     23,553
                                             -------   -------   --------   --------
Net income.................................  $   106   $   119   $  4,809   $  6,652
                                             -------   -------   --------   --------
Diluted earnings per share.................  $  0.01   $  0.01   $   0.25   $   0.35
                                             -------   -------   --------   --------
</TABLE>

<TABLE>
<CAPTION>
                                                              1998
                                             ---------------------------------------
                                             MAR. 31   JUNE 30   SEPT. 30   DEC. 31
                                             -------   -------   --------   --------
<S>                                          <C>       <C>       <C>        <C>
Operating revenues.........................  $66,410   $54,863   $ 52,147   $ 52,162
Operating expenses.........................   47,401    47,341     52,655     59,614
                                             -------   -------   --------   --------
Operating income (loss)....................   19,009     7,522       (508)    (7,452)
                                             -------   -------   --------   --------
Net income (loss)..........................  $ 4,081   $(3,257)  $ (8,134)  $(11,307)
                                             -------   -------   --------   --------
Diluted earnings (loss) per share..........  $  0.22   $ (0.18)  $  (0.43)  $  (0.61)
                                             -------   -------   --------   --------
</TABLE>

NOTE 16 -- RATIO OF EARNINGS TO FIXED CHARGES (UNAUDITED)

     As of December 31, our ratio of earnings to fixed charges was as follows:

<TABLE>
<S>                                                         <C>
2000......................................................  2.64 to 1
1999......................................................  1.25 to 1
1998......................................................   n/a (1)
1997......................................................   n/a (1)
1996......................................................  1.07 to 1
</TABLE>

---------------

(1) Earnings were insufficient to cover fixed charges by $38.8 million and $28.0
    million at December 31, 1998 and 1997, respectively.

                                        64
<PAGE>   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.

<TABLE>
<CAPTION>
     EXHIBIT NUMBER                              DESCRIPTION
     --------------                              -----------
<C>                      <S>
         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             -- 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.)
</TABLE>

                                        65
<PAGE>   66

<TABLE>
<CAPTION>
     EXHIBIT NUMBER                              DESCRIPTION
     --------------                              -----------
<C>                      <S>
         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 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.)
         4.6             -- Supplemental Indenture dated as of March 1, 1999, among
                            the Company and Harris Trust and Savings Bank as Trustee,
                            amending Indenture dated as of 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             -- Common Stock Purchase Warrant dated July 12, 1990 by the
                            Company to James E. Duffy. (Incorporated by reference to
                            Exhibit 10.5 to the Form 8, Second Amendment to Form 10,
                            filed April 8, 1991.)
        10.2             -- 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.)
        10.3             -- 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.)
        10.4             -- 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.)
        10.5             -- 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.))
        10.6             -- 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.)
        10.7             -- 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.)
        10.8             -- 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.)
        10.9             -- Purchase and Sale Agreement dated March 25, 1996, between
                            Orion, the Company and Wattenberg Resources Land, L.L.C.
                            (Incorporated by reference to Exhibit 10.28 to the
                            Company's Quarterly Report on Form 10-Q for the quarter
                            ended March 31, 1996, filed May 15, 1996.)
        10.10            -- 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.)
</TABLE>

                                        66
<PAGE>   67

<TABLE>
<CAPTION>
     EXHIBIT NUMBER                              DESCRIPTION
     --------------                              -----------
<C>                      <S>
        10.11            -- 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.)
        10.12            -- 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.)
        10.13            -- 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.)
        10.14            -- 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.)
        10.15            -- 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.)
        10.16            -- 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.)
        10.17            -- 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.)
        10.18            -- Purchase and Sale Agreement between the Company and
                            Wattenberg Gas Investments, LLC dated June 28, 1996.
                            (Incorporated by reference to Exhibit 10.37 to the
                            Company's Quarterly Report on Form 10-Q for the quarter
                            ended June 30, 1996, filed August 14, 1996.)
        10.19            -- 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.)
        10.20            -- 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.)
        10.21            -- 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.)
        10.22            -- 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.)
</TABLE>

                                        67
<PAGE>   68

<TABLE>
<CAPTION>
     EXHIBIT NUMBER                              DESCRIPTION
     --------------                              -----------
<C>                      <S>
        10.23            -- 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.)
        10.24            -- 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.)
        10.25            -- 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.)
        10.26            -- 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.)
        10.27            -- 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.)
        10.28            -- 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.)
        10.29            -- 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.)
        10.30            -- 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.)
        10.31            -- 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.)
        10.32            -- 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.)
</TABLE>

                                        68
<PAGE>   69

<TABLE>
<CAPTION>
     EXHIBIT NUMBER                              DESCRIPTION
     --------------                              -----------
<C>                      <S>
        10.33            -- 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.)
        10.34            -- 1999 Non-Compensatory Stock Purchase Plan. (Incorporated
                            by reference as Exhibit 4.1 to Form S-8 filed January 25,
                            1999.)
        10.35            -- 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.)
        10.36            -- 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.)
        10.37            -- 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.)
        10.38            -- 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.)
        10.39            -- 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.)
        10.40            -- Sublease 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.
        10.41*           -- Master Lease Agreement dated as of December 14, 2000 by
                            and between HS Gathering, L.L.C. and LaSalle National
                            Leasing Corporation.
        10.42*           -- 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.
        23.1*            -- Consent of Arthur Andersen LLP
        23.2*            -- Consent of Netherland, Sewell & Associates, Inc.
</TABLE>

---------------

* 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
<PAGE>   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.

<TABLE>
<CAPTION>
                      SIGNATURE                                             TITLE
                      ---------                                             -----
<C>                                                      <S>

               /s/ NICHOLAS J. SUTTON                    Chairman of the Board, Chief Executive
-----------------------------------------------------      Officer (Principal Executive Officer)
                 Nicholas J. Sutton

                /s/ P. MICHAEL HIGHUM                    President and Director
-----------------------------------------------------
                  P. Michael Highum

                 /s/ JAMES E. DUFFY                      Chief Financial Officer and Director
-----------------------------------------------------      (Principal Financial Officer)
                   James E. Duffy

                 /s/ ANNETTE MONTOYA                     Vice President -- Accounting and Controller
-----------------------------------------------------      (Principal Accounting Officer)
                   Annette Montoya

                                                         Director
-----------------------------------------------------
                  Michael J. Savage

                                                         Director
-----------------------------------------------------
                     Barry Reder

               /s/ ROBERT G. VANNEMAN                    Director
-----------------------------------------------------
                 Robert G. Vanneman
</TABLE>

                                        70
<PAGE>   71

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
        10.41*           -- Master Lease Agreement dated as of December 14, 2000 by
                            and between HS Gathering, L.L.C. and LaSalle National
                            Leasing Corporation.
        10.42*           -- 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.
        23.1*            -- Consent of Arthur Andersen LLP
        23.2*            -- Consent of Netherland, Sewell & Associates, Inc.
</TABLE>

---------------

*  Filed herewith