<PAGE>   1

                       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 OR

[ ]      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
         EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

  For the fiscal year ended December 31, 1996 Commission File Number 0-18886

                               HS RESOURCES, INC.
             ------------------------------------------------------
             (Exact name of Registrant as specified in its charter)

DELAWARE                                                       94-3036864
--------------------------------                      -------------------
(State or other jurisdiction of                          (I.R.S. Employer
incorporation or organization)                        Identification No.)
                                                 
ONE MARITIME PLAZA, FIFTEENTH FLOOR              
SAN FRANCISCO, CA                                                   94111
----------------------------------------               ------------------
(Address of principal executive offices)                       (Zip Code)

      Registrant's telephone number, including area code:  (415) 433-5795

           SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT

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<S>                                                      <C>
Title of each class of stock                 
----------------------------                 
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 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 February 28, 1997:  $213,188,731

Number of shares of Common Stock outstanding as of the close of business on
February 28, 1997:  17,014,112 after deducting 121,952 shares in treasury.

                      DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Proxy Statement of HS Resources, Inc. to be dated on or before
April 30, 1997, are incorporated by reference into Part III.  (A definitive
proxy statement will be filed with the Commission within the prescribed
period.)
<PAGE>   2
                               TABLE OF CONTENTS


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                                                                                                  Page
                                                                                                  ----
Part I.
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         Item 1.          Business  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      3
         Item 2.          Properties  . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     12
         Item 3.          Legal Proceedings and Environmental Issues  . . . . . . . . . . . . .     21
         Item 4.          Submission of Matters to a Vote of Security Holders . . . . . . . . .     22

Part II.

         Item 5.          Market for Registrant's Common Equity and Related
                              Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . .     23
         Item 6.          Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . .     24
         Item 7.          Management's Discussion and Analysis of Financial
                              Condition and Results of Operations . . . . . . . . . . . . . . .     25
         Item 8.          Financial Statements and Supplementary Data . . . . . . . . . . . . .     40
         Item 9.          Changes in and Disagreements with Accountants on
                              Accounting and Financial Disclosure . . . . . . . . . . . . . . .     66

Part III.

         Items 10-13.           . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     66

Part IV.

         Item 14.         Exhibits  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     67
</TABLE>





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                                     PART I

Item 1.          BUSINESS

THE COMPANY

HS Resources, Inc. ("HSR" or "the Company") is a leading United States
independent energy company engaged in the development, acquisition,
exploitation, exploration, production and marketing of oil and natural gas.
Through its experienced management and technical staff, the Company has
consistently increased reserves and production, and has established itself as
one of the most efficient operators in the industry.  HSR has created a
diversified asset base in three core geographic areas:  the Denver-Julesburg
Basin ("D-J Basin") of the Rocky Mountains, the Anadarko and Arkoma Basins of
the Mid-Continent and the on-shore Gulf Coast area.  It has done so by
executing a large scale development drilling program focused in the Wattenberg
Field area of the D-J Basin and through the acquisition of all of the D-J Basin
properties owned by Basin Exploration, Inc. ("Basin") (the "Acquisitions"), the
merger with Tide West Oil Company (the "Merger") and the formation of Gulf
Coast joint ventures.  The Company believes that each core geographic area
presents operational and financial opportunities, positioning the Company to
maximize the benefits of its more predictable, long-lived D-J Basin production,
while providing meaningful exposure to potential exploitation and exploration
projects in the Mid-Continent and Gulf Coast which exhibit higher return
potential.  HSR has an inventory of growth opportunities that includes in
excess of 2,000 infill, development and exploratory drilling locations and over
1.1 million gross undeveloped acres.

The Company has achieved substantial growth in reserves, production, revenues
and operating cash flow over the past five years.  HSR has increased reserves
from 20.8 MMBoe as of December 31, 1990, to 142.0 MMBoe as of December 31,
1996.  HSR also increased production from 0.9 MMBoe for the year ended December
31, 1991, to 7.6 MMBoe for the year ended December 31, 1996.  Oil and natural
gas revenues and operating cash flow (defined as net income before
depreciation, depletion and amortization and deferred income taxes) also have
grown significantly, increasing from $12.8 million and $5.4 million,
respectively, for the year ended December 31, 1991, to $107.3 million and $56.5
million, respectively, for the year ended December 31, 1996.

At December 31, 1996, the Company's reserves had an estimated pre-tax present
value (discounted at 10%) of $1,131 million.  Natural gas constituted
approximately 76% of the Company's reserves and approximately 76% of the
Company's reserves were classified as proved developed.  At December 31, 1996,
the Company operated approximately 74% of its 3,562 wells. Management believes
that its ability to control the operations of its wells and to minimize
overhead expenses has contributed to the Company achieving one of the lowest
cost structures in the industry.

The Company is a Delaware corporation organized in 1987 to consolidate
interests owned and/or managed by certain members of the current management
team.  The Company's principal subsidiaries are Orion Acquisition, Inc.
("Orion"), which holds the assets acquired in the Acquisitions, HSRTW, Inc.
("HSRTW"), which holds the assets acquired through the Merger, and Tide West
Trading & Transport Company ("TWTT") (the name of which the Company intends to
change to HS Energy Services, Inc. in the near future).  The Company's
principal executive office is located at One Maritime Plaza, Fifteenth Floor, 
San Francisco, California 94111 and its telephone number at such address is 
(415) 433-5795.





                                       3
<PAGE>   4
BUSINESS STRATEGY

HSR's objective is to maximize its long-term value through aggressive growth in
its oil and natural gas reserves and production.  The Company has successfully
achieved its goals through an ongoing strategy of (i) increasing its
diversified long-lived asset base, (ii) building a substantial inventory of
development, exploitation and exploration projects, (iii) utilizing
state-of-the-art exploration, drilling and production techniques, (iv)
effecting consolidation in its core geographic areas, (v) maintaining low
operating costs, (vi) capturing downstream value and (vii) maximizing financial
flexibility.

         o   Increase Diversified Long-lived Asset Base.  HSR has assembled a
             diversified portfolio of predictable, long-lived properties,
             which, in the aggregate, generate significant high margin
             production and cash flows.  HSR presently owns interests in 3,562
             gross wells and had an aggregate reserves-to-production ratio of
             15:1 as of December 31, 1996.  The Company's current reserve mix
             consists of approximately 76% natural gas and 24% oil, with most
             wells producing both oil and natural gas.  The Company is
             diversified geographically and geologically with core producing
             properties located in the D-J Basin and the Mid-Continent area and
             also owns extensive undeveloped leaseholds in the Gulf Coast and
             Rocky Mountain regions.

         o   Build a Substantial Inventory of Development, Exploitation and
             Exploration Projects.  The Company intends to continue expanding
             its substantial portfolio of development, exploitation and
             exploration projects. As of December 31, 1996, HSR had identified
             approximately 970 development drillsites and 750 potential infill
             drillsites in the D-J Basin.  The lower risk infill and
             development projects in the D-J Basin are complemented by
             relatively higher risk and potentially higher return exploitation
             and exploration projects in the Mid-Continent and Gulf Coast
             regions.  Based upon preliminary interpretation of seismic and
             geologic data, the Company has identified approximately 218
             exploitation and development drilling locations in the
             Mid-Continent area and approximately 60 exploitation and
             exploration projects and leads in its Gulf Coast project areas.

         o   Utilize Advanced Exploration, Drilling and Production Techniques.
             In the D-J Basin, the Company has tested and is evaluating the use
             of coiled tubing drilling and is using both sophisticated
             fracturing technologies and directional drilling to enhance
             production and obtain additional reserves from existing wellbores.
             In order to improve its exploitation and exploration drilling
             success rates, the Company utilizes 3-D seismic extensively,
             including advanced imaging techniques of coherence cube or
             continuity processing and advanced interpretation and
             geostatistical techniques.  The Company has acquired more than 470
             square miles of 3-D seismic data in its core geographic areas and
             plans to acquire an additional 180 square miles of 3-D seismic
             data in the Gulf Coast within the next nine months.  The Company,
             directly or indirectly, employs or contracts with 33 experienced
             geologists and geophysicists to develop its projects.





                                       4
<PAGE>   5
         o   Consolidate in Core Geographic Areas.  The Company is continuing
             to pursue its consolidation strategy in the D-J Basin, where the
             Company's net production represents approximately 24% of total D-J
             Basin natural gas production.  By effecting consolidation in the
             D-J Basin, the Company capitalizes on opportunities for further
             operating and administrative cost efficiencies and improves its
             product marketing position through control of increased volumes.
             HSR will pursue a similar consolidation strategy in various fields
             and basins within the Mid-Continent area.

         o   Maintain Low Operating Costs.  The Company is an industry leader
             in operational efficiencies and field management, historically
             ranking as one of the lowest cost operators in the United States.
             For the twelve months ended December 31, 1996, the Company's
             general and administrative expenses were $0.74 per Boe, and its
             lease operating expenses were $2.32 per Boe.  During 1995, HSR's
             general and administrative expenses were $0.80 per Boe, and its
             lease operating expenses were $1.95 per Boe.  The Company will
             continue to pursue efficient operations, although expenses are
             expected to increase modestly due to the differences in the mix of
             the Company's properties resulting from the Merger and the
             Company's Gulf Coast activities.

         o   Capture Downstream Value.  The Company seeks to enhance both its
             margins and operating flexibility through its marketing, trading
             and transportation business.  HSR is one of the most active
             natural gas producer/marketers in the Colorado Front Range area
             (the area from Denver north to Fort Collins and south to Colorado
             Springs) and directly markets approximately 60% of its D-J Basin
             natural gas production.  A significant portion of this production
             is sold directly to over 400 commercial and industrial end users.
             In the Mid-Continent area, the Company markets its own natural gas
             production and also purchases third party natural gas for resale.
             The Colorado Front Range and Mid-Continent marketing and trading
             operations are fully integrated, thus providing opportunities for
             HSR to improve product prices and profit from market imbalances
             and trading opportunities between the two regions and to
             capitalize on the combined expertise of the two groups.

         o   Maximize Financial Flexibility.  The Company is committed to
             maintaining substantial financial flexibility.  In funding its
             growth, HSR has employed a broad array of financing structures,
             divestitures and asset monetizations.  Management currently
             expects its 1997 capital expenditure budget to be fully funded by
             internally-generated cash flow.  Since the consummation of the
             Merger and the Acquisitions, the Company has been monetizing
             certain non-strategic properties with the proceeds reducing
             outstanding borrowings under the Chase Facility.  To date
             approximately $20 million of such monetization has occurred.

RECENT DEVELOPMENTS

Basin Property Acquisitions

In March and June of 1996, the Company completed the Acquisitions, acquiring
all of Basin's D-J Basin properties for aggregate cash consideration of $125.5
million.  The Acquisitions included a total of 850 gross wells which at
December 31, 1995, had approximately 35 MMBoe of net proved reserves and
approximately 5,500 Boe of net daily production.  The Acquisitions also
included





                                       5
<PAGE>   6
approximately 250 potential development drillsites. The acquired properties are
in the immediate vicinity of HSR's existing D-J Basin operations, and HSR has
integrated these assets into its property base with no material increase in
overhead, resulting in a substantial decrease in general and administrative
costs per Boe of production.  In addition to the improved economics associated
with consolidation, HSR increased its control of natural gas volumes in the D-J
Basin, strengthening the Company's active Colorado Front Range natural gas
marketing activities.  The Company believes that there remain significant
future exploitation and infill drilling opportunities to further develop
existing reserves in the D-J Basin through the application of developing
technologies, including directional drilling applications.  See "Item 2.
Properties - Oil and Gas Properties - Denver-Julesburg Basin."

Tide West Merger

On June 17, 1996, the Company completed the Merger with Tide West Oil Company
("Tide West").  The total consideration of $187.7 million consisted of $119.8
million in cash and net liabilities assumed and HSR common stock with an
aggregate market value of approximately $67.9 million.  The Merger added 1,259
gross wells, approximately 39.1 MMBoe of net proved reserves as of December 31,
1995 and approximately 9,985 Boe of net daily production to the Company.
Through the Merger, the Company diversified its property base into the
Mid-Continent area, acquired a large inventory of exploitation, development and
exploration opportunities, and acquired TWTT, an active natural gas trading and
transportation operation.  The geographical location of the Tide West
properties and the proximity of such properties to the Mid- Continent markets
and Henry Hub provide the Company with product market and price
diversification.  Tide West's undrilled locations have a relatively higher
reserve potential than HSR's D-J Basin properties, but with a slightly higher
risk profile.  To date, HSR has identified approximately 218 potential
exploitation and development drillsites on properties acquired in the Merger.
See "Item 2. Properties - Oil and Gas Properties - Mid-Continent."

Gulf Coast Joint Ventures

The Company's strategy in establishing operations in the Gulf Coast region has
been to establish joint ventures with experienced Gulf Coast exploration
organizations which have in inventory existing projects and positions, and are
at the forefront of applied technologies, including advanced imaging
applications of 3-D seismic data.  To date, the Company has formed two joint
ventures that are complementary in approach and geographic coverage.  As a
result, the Company has accelerated its cycle time in generating, analyzing and
exploiting 3-D seismic projects in the Gulf Coast. Entry into the Gulf Coast is
a key component of the Company's diversification strategy.  High rate,
shorter-lived production from this area will complement the Company's existing
long-lived production profile.  Furthermore, the higher return potential of the
Gulf Coast provides greater balance to the Company's overall risk profile.

SouthTech.  The Company entered into its first Gulf Coast joint venture in
November 1995 by forming SouthTech Exploration, L.L.C. ("SouthTech") on an
equal ownership basis with Aspect Resources Limited-Liability Company, a
recognized leader in 3-D seismic technology.  SouthTech has acquired
approximately 140 square miles of 3-D seismic data and employs, directly or on
a consulting retainer basis, seven geotechnical professionals.  At December 31,
1996, SouthTech had identified approximately 60 exploration prospects and leads
in four of its ten project areas.  Management believes that this joint venture
will expose the Company to significant reserve





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<PAGE>   7
potential on a near-term basis and that completed and planned 3-D seismic
surveys will meaningfully expand future growth opportunities.

Chenier.  In May 1996, the Company entered into Chenier Exploration
("Chenier"), a joint venture arrangement with Chenier Exploration, Inc.
("CEI").  The geological and geophysical staff of CEI also makes extensive use
of advanced 3-D seismic imaging techniques in the on-shore Gulf Coast area. CEI
employs, directly or on a full-time retainer basis, five geotechnical
professionals. The Company anticipates that Chenier will engage in various 3-D
seismic surveys covering at least 110 square miles in 1997.  Geologic and
geophysical efforts are underway, and leases, options and seismic rights are
currently being acquired in major project areas.  See "Item 2. Properties - Oil
and Gas Properties - Gulf Coast."

MARKETING, TRADING AND TRANSPORTATION

Gas Marketing

The Company directly markets about 50% of its natural gas production from the
D-J Basin and the Mid-Continent to a variety of purchasers, including
intrastate and interstate pipelines, their marketing affiliates, independent
marketing companies and other purchasers.  These sales are primarily arranged
on a monthly or daily basis or under index pricing arrangements usually with a
term of less than one year.

In addition, the Company sells approximately 10% of its production pursuant to
a marketing strategy that capitalizes on its ability to deliver its D-J Basin
natural gas to Colorado Front Range commercial and industrial end user
customers.  The proximity of the Company's D-J Basin natural gas reserves to
the local markets and its ability to deliver product to over 400 commercial and
industrial end user customers at times of peak demand provide it with a
competitive advantage over natural gas suppliers who do not have significant
local reserves.  These factors enable the Company to provide superior service
at competitive prices.  The Company believes that its marketing strategy
provides it with the ability to increase its margins above those available on
bulk sales to wholesale remarketers. In addition, the Company believes its
ability to deliver product during peak demand periods enables it to negotiate
annual contracts at prices consistently in excess of annual average spot market
prices, generally resulting in premium weighted average annual pricing and a
more stabilized sales portfolio. As a result of its implementation of this
strategy, in 1996 the Company delivered approximately 5 Bcf of gas pursuant to
these arrangements.

The remaining 40% of the Company's D-J Basin and Mid-Continent natural gas
production is sold to gathering and/or processing companies on a
percent-of-proceeds or a percent-of-index basis. Under the terms of the
percent-of-proceeds contracts, the Company receives a fixed percentage of the
resale price received by the purchaser for sales of residue natural gas and
natural gas liquids recovered after gathering and processing.  The revenue
received by the Company from the sale of natural gas liquids is included in
natural gas revenues. Under the terms of the percent-of-index contracts, the
Company receives a fixed percentage of a natural gas index price.

In June 1996, the Company acquired TWTT through the Merger.  TWTT is a wholly
owned subsidiary of HSRTW, Inc., which in turn is wholly owned by the Company.
TWTT is responsible for natural gas marketing services, including commodity
price structuring and contract administration for the Company's operations in
the Mid-Continent and Gulf Coast regions. In addition to marketing the
Company's natural gas, TWTT also purchases third party natural gas for





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<PAGE>   8
resale.  The Company generally attempts to balance its positions so that
margins are captured and exposure to market price movement is minimized.

See "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Natural Gas Price Considerations."

Oil Marketing and Trading

Substantially all of the Company's oil production is sold at crude oil-based
prices under contracts having a term of one year or less.  Oil is sold to 12
different purchasers at generally market sensitive rates.  The most significant
purchaser of the Company's oil production currently is Amoco Production
Company, which purchases 48% of the Company's oil production.  The Company
believes that there are a sufficient number of crude oil purchasers in the
market so that the loss of any one particular customer would not have an
adverse effect on the Company.  Additionally, the Company has recently formed
HS Trading & Transport, Inc. ("HS Trading").  HS Trading will be engaged in the
purchase, sale, transportation and exchange of crude oil.  At the present time,
the Company expects to trade volumes in the range of 2,500 Bbls of oil per day.

SECTION 29 TAX CREDITS

The Company and certain of its subsidiaries continue to enter into transactions
designed to monetize the Company's Section 29 tax credits.  Through these
transactions, the Company has preserved a portion of the value of the Section
29 tax credits from tight gas sand reservoirs that would otherwise be lost
because of the Company's tax position.  In each transaction, the Company or
subsidiary conveys the working interest in credit-qualified properties to a
limited liability company owned by one or more large East Coast financial
institutions.  The Company retains a production payment in the properties and
an option to reacquire the properties.  The investor makes an initial payment
to the Company, and 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 obtain private letter rulings covering
the Company's transactions specifically.  Through these recent transactions,
the Company has received initial payments of approximately $5.6 million
(including $1.5 million received in January 1997) and anticipates receiving
additional aggregate payments through 2002 of approximately $26 million.
During 1996 and 1995 the Company monetized $2.7 million and $1.8 million,
respectively, in tax credits.  Although the Company believes the possibility is
remote, the Internal Revenue Service ("IRS") could decide to challenge the
validity of the transactions that are not directly protected by a letter
ruling.  The Company, however, would generally not have to refund payments that
had been made by the investor even if the IRS challenge were to succeed.

COMPETITION

The oil and natural gas industry is highly competitive.  The Company competes
in the areas of property acquisitions and the development, production and
marketing of oil and natural gas with major oil companies, other independent
oil and natural gas concerns and individual producers and operators.  The
Company also competes with major and independent oil and natural gas concerns
in recruiting and retaining qualified employees.  Many of these competitors
have substantially greater financial and other resources than the Company.





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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
operations of the Company 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
will not enact price controls in the future.

Federal Regulation of First Sales and Transportation of Natural Gas.
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act
("NGA"), the Natural Gas Policy Act ("NGPA"), and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission ("FERC").  Maximum
selling prices of certain categories of natural gas sold in "first sales,"
whether sold in interstate or intrastate commerce, were regulated pursuant to
the NGPA.  On July 26, 1989, the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act") was enacted which removed, as of January 1, 1993, all
remaining federal price controls from natural gas sold in "first sales."  The
FERC's jurisdiction over natural gas transportation was unaffected by the
Decontrol Act.

Commencing in the mid-1980s and continuing until the present, the FERC
promulgated a series of orders designed to correct 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 natural gas markets in the United States and have, among other
things, fostered the development of a large spot market for gas and increased
competition for gas markets.  As a result of the FERC orders, producers have
direct access to natural gas markets but face increased competition for those
markets and must operate under complex transportation tariffs in order to take
advantage of the opportunity to directly access natural gas markets.

Interstate pipelines continue to be regulated by the FERC under the NGA.
Various state commissions also regulate the rates and services of pipelines
whose operations are purely intrastate in nature.  Some state utility
commissions, such as the Colorado Public Utilities Commission, now require that
state 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 natural 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 and
taxation.  The states in which the Company operates have enacted statutes and
regulations governing a number of environmental and conservation matters,
including the unitization or pooling of oil and gas properties.  A few states
also prorate production to the market demand for oil and gas.  Some states have
also enacted statutes establishing maximum rates of production from oil and gas
wells.





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<PAGE>   10
Recently there has been an increased level of regulation of oil and natural gas
activities in Colorado.  For example, the Colorado Oil and Gas Conservation
Commission adopted, and is considering the adoption of additional, stricter
regulation of matters such as groundwater protection, safety regulation, soil
conservation, surface use, land reclamation, fluid disposal and bonding of oil
and natural gas companies.  Additionally, various cities and counties are
currently reviewing their ordinances to determine the level of regulatory
authority, if any, they should assert over such matters.  At present, it cannot
be determined to what degree stricter regulations, if adopted, would adversely
affect the Company's operations.

Environmental Regulations. The Company's operations are subject to complex and
constantly changing environmental laws and regulations adopted by Federal,
state and local governmental authorities.  Compliance with such laws has not
had a material adverse effect upon the Company to date and the Company is not
aware of any matter that is likely to have a material adverse effect on the
Company in the future.  However, in May 1995, the Company was named as a
respondent by the United States Environmental Protection Agency ("EPA") in an
administrative order brought under the Resource Conservation and Recovery Act
("RCRA") by the EPA against the owner/operator of an oilfield production water
evaporation facility.  The Company does not believe that its share of
reclamation costs will have a material impact on its financial position or
results of operations.  See Item 3.  "Legal Proceedings--Environmental Issues",
and Note 10 to Consolidated Financial Statements.  Also, the discharge of oil,
natural gas or other pollutants into the air, soil or water may give rise to
significant liabilities of the Company to the government and/or third parties.
Moreover, the Company has agreed to indemnify certain sellers of producing
properties from whom the Company has acquired properties against certain
liabilities for environmental claims associated with the properties purchased
by the Company.  No assurance can be given that existing environmental laws or
regulations, as currently interpreted or as may be interpreted in the future,
or future laws or regulations will not materially adversely affect the
Company's results of operations and financial condition or that material
indemnity claims will not arise against the Company with respect to properties
acquired by the Company.

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.
Moreover, on certain federal leases, prior approval of drillsite operations
must be obtained from the Environmental Protection Agency.

TITLE TO PROPERTIES

A title opinion is obtained prior to the commencement of drilling operations on
properties.  The Company has obtained title opinions on substantially all of
its producing properties and believes that it has satisfactory title to such
properties in accordance with standards generally accepted in the oil and gas
industry.  The Company's properties are subject to customary royalty interests,
liens for current taxes and other burdens which the Company believes do not
materially interfere with the use or affect the value of such properties.  A
portion of the Company's oil and gas properties are mortgaged to secure
borrowings under the Company's credit facilities.  Title investigation before
acquiring undeveloped properties is thorough but less rigorous than that
conducted prior to drilling, consistent with standard industry practice.





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<PAGE>   11
OPERATIONAL HAZARDS AND INSURANCE

The Company's operations are subject to the usual hazards incident to the
drilling and production of oil and natural gas, such as blowouts, cratering,
explosions, uncontrollable flows of oil, natural gas or well fluids, 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.

The Company has engaged Aon Risk Services, one of the world's largest insurance
brokerage firms, to maintain various types of coverage for its operations,
including a $2 million general liability insurance policy, a $5 million
pollution policy, and an excess liability policy totaling $25 million.  In
addition, the Company has in place operator extra expense coverage, with a $5
million per occurrence limit and oil lease property coverage which protects the
Company's equipment and stored products.  The Company's insurance does not
cover every potential risk associated with the drilling, production, storage
and transportation of oil and natural 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 the
Company's financial condition and results of operations.  Moreover, no
assurance can be given that the Company will be able to maintain adequate
insurance in the future at rates it considers to be reasonable.

EMPLOYEES

At December 31, 1996, the Company had 233 employees, with 29 located in San
Francisco, 63 in Denver, 55 in Tulsa and 86 in Evans, Colorado.  None of the
Company's employees are subject to a collective bargaining agreement.  The
Company considers its relations with its employees to be good.  The Company
anticipates that it will hire additional personnel consistent with its current
development drilling programs and other activities.

OFFICES

The Company leases its headquarters office at One Maritime Plaza, Fifteenth
Floor, San Francisco, California under a lease currently covering 20,548 square
feet expiring in December 2003, at an average monthly rental of $35,753.  In
1994, the Company entered into a new five-year lease, with options, in Denver,
Colorado which covers 35,200 square feet at a monthly rental of $17,583.  The
Company is currently negotiating an amendment of its lease that would extend
the lease six years at a rental rate of $6.00 to $16.00 per square foot for the
existing 35,200 square feet, and would add one floor of contiguous space
covering approximately 17,500 square feet at a rental rate of from $13.25 per
square foot to $18.25 per square foot.  The Company is currently leasing 17,692
square feet in Tulsa, Oklahoma for $16,429 per month.  This lease will
terminate March 31, 1997, except as to 3,500 square feet which will terminate
August 31, 1997.  The Company entered into a new lease in Tulsa effective
December 11, 1996, which covers 24,581 square feet at a monthly rental of
$29,224 per month.  The Company also leases a field office in Evans, Colorado
consisting of 7,900 square feet of office space and 2,200 square feet of
warehouse space for $5,500 per month.





                                       11
<PAGE>   12
Item 2.          PROPERTIES

OIL AND GAS PROPERTIES

         The following table summarizes certain information with respect to
each of the Company's areas of operations and production.  All information is
presented as of December 31, 1996.

<TABLE>
<CAPTION>
                                                                 RESERVES
                                                -----------------------------------------
                                                                    OIL       PERCENT OF                   GROSS      3-D SEISMIC
                               TOTAL  PERCENT    OIL      GAS    EQUIVALENT    TOTAL      PRODUCTION    UNDEVELOPED     DATA
                               WELLS  OPERATED  (MBBLS)   MMCF)    (MBOE)     RESERVES    BOE/DAY) (1)  ACREAGE (2)  (SQUARE MILES)
                               -----  --------  -------  ------  ----------  ----------   ------------  -----------  --------------
<S>                            <C>          <C>  <C>     <C>         <C>             <C>        <C>          <C>                 
D-J Basin
     Wattenberg Field Area     1,811        88   26,332  373,095     88,515          62         14,750       74,650            --
     Greater D-J Basin           449        92    1,570   41,972      8,565           6          1,255      194,960              70
Mid-Continent                                                   
     Anadarko Basin              804        37    2,008   99,612     18,610          13          5,146       22,413              13
     Arkoma Basin                205        60       37   57,785      9,668           7          1,833        8,720            --
     Southern Oklahoma            95        66    2,745   27,026      7,249           5          1,458        1,943            --
     New Mexico/Texas            170        74    1,765   41,019      8,601           6          1,474       26,982              24
Gulf Coast                         2        50       24       75         37        --             --        130,094             176
Northern Rocky Mountains          26        96      133    3,837        773           1             26      652,022             193
                               -----  --------  -------  ------- ----------  ----------   ------------  -----------  --------------
           Total:              3,562        74   34,614  644,421    142,018         100%        25,942    1,111,784             476
                               =====  ========  =======  ======= ==========  ==========   ============  ===========  ==============
</TABLE>

(1)  Calculated for the quarter ended December 31, 1996.

(2)  Includes leasehold, option and seismic rights.

Denver-Julesburg Basin

The D-J Basin is located in Northeastern Colorado, and over recent years has
been the Company's primary producing region.  HSR's D-J Basin production and
reserves are largely contained in the Codell and Niobrara formations, with
additional production from the deeper D-Sand, J-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 flows and long-lived reserves.  Production also tends to be a
combination of oil and natural gas.  Natural gas produced in the central part
of the D-J Basin, including the Wattenberg Field area ("Wattenberg"), has an
energy content of approximately 1,250 Btu per Mcf, which enhances wellhead
value.

One of the attractive features of D-J Basin geology is its multi-pay potential.
In a section only 3,500 feet thick, there are at least seven major potentially
productive formations.  Three of the formations, the Codell, Niobrara and J-
Sand, are "blanket" zones in the area of the Company's Wattenberg holdings,
while others, such as the D-Sand and the shallower Shannon and Sussex, are more
localized.

Wattenberg Field Area.  The majority of the Company's D-J Basin properties are
concentrated in Wattenberg, located approximately 35 miles north of Denver.
The primary geologic objectives of the Company's Wattenberg activities are the
Codell and Niobrara formations, found at depths ranging from 6,400 to 7,700
feet.  Codell/Niobrara wells usually take five to six days to drill and are
typically brought into production within 20 days from commencement of drilling.
The generally predictable, quick and trouble-free drilling characteristics of
these wells allow multiple-well, multiple-rig development drilling programs to
be conducted efficiently.  Codell/Niobrara wells typically produce
approximately 50% of their reserves in the first three to five years. The
remaining





                                       12
<PAGE>   13
reserves are recovered at a declining rate over the next 15 to 20 years.  The
Codell and Niobrara formations produce both oil and natural gas, with reserves
generally being approximately 70% natural gas and 30% oil.

Greater D-J Basin.  The Greater D-J Basin is that portion of the D-J Basin
located generally south and east of Wattenberg.  Production in the Greater D-J
Basin is generally found in D-Sand and J-Sand channels, and can produce oil,
natural gas or both.  Within the D-Sand and J-Sand, high porosities and
permeabilities can yield higher flow rates than Codell and Niobrara wells.
D-Sand and J-Sand channels, while not "blanket" formations in the Greater D-J
Basin, can be prolific when encountered.  The D-Sand and J-Sand are
stratigraphically located below the Codell and Niobrara formations at depths
ranging from 6,800 to 7,800 feet.

Mid-Continent

The Company's Mid-Continent properties are primarily located in four geological
areas (i) the Anadarko Basin in western Oklahoma and the Texas panhandle, (ii)
the Arkoma Basin in southeastern Oklahoma and western Arkansas, (iii) southern
Oklahoma and (iv) southeast New Mexico and south and east Texas.

Anadarko Basin.  The Anadarko Basin is a major Mid-Continent oil and natural
gas producing area located in western Oklahoma and the Texas panhandle.  The
greatest concentration of oil fields occurs on the eastern flank of the basin,
with natural gas fields dominating the shelf to the west, the Texas panhandle
area and the deep basin located in southwestern Oklahoma.  The majority of the
Company's production comes from the Red Fork, Springer-Morrow, Chester,
Mississippi and Hunton geological formations.  Oil and natural gas are produced
in this basin from depths of only a few hundred feet to over 20,000 feet, and
most of the Company's wells produce from depths between 6,000 and 16,000 feet.

Arkoma Basin.  The Arkoma Basin is a crescent-shaped region straddling the
Arkansas-Oklahoma border.  The Arkoma Basin is a major natural gas region, with
most wells producing from depths between 5,000 and 12,000 feet. The majority of
the Company's production comes from the Booch, Hartshorne, Atoka, Spiro and
Cromwell geological formations, primarily at depths between 5,000 and 10,000
feet.

South Oklahoma.  The southern Oklahoma area is a faulted and folded geologic
province that extends across seven counties in south-central Oklahoma.  The
Company's production is mainly from Pennsylvanian Hoxbar, Deese and Springer
sands, the Hunton and Viola carbonates, and the Simpson sand.  The Company's
wells in this region produce from depths ranging from 5,000 to 17,000 feet.

New Mexico/Texas.  In these areas, the Company's properties are found
principally in the Delaware Basin and south and east Texas.  These geologic
areas are oil prone and are comprised of numerous stratigraphic and faulted
sandstone reservoirs.  The Company's Delaware Basin properties are located in
New Mexico, with most of its oil production coming from the Delaware formation
at depths of 4,000 to 6,000 feet.  Natural gas production is principally from
the Abo formation at depths of 4,000 to 5,000 feet. The East Texas Basin
properties are located in Houston, Freestone, Cherokee and Henderson Counties
in Texas and DeSoto Parish in Louisiana.  The predominant





                                       13
<PAGE>   14
reservoirs are normally pressured Cretaceous sandstones and carbonates at
depths ranging from 5,000 to 11,000 feet.  The Company produces mostly natural
gas from the Woodbine, Glen Rose, Rodessa, Pettet and Hosston reservoirs.

Gulf Coast

The Company has established a core geographic area in the on-shore Gulf Coast
area of south Texas and Louisiana primarily through two joint ventures,
SouthTech and Chenier.  Both joint ventures are staffed with explorationists
who are experienced in the integration of interpretive geology and advanced 3-D
seismic techniques.  The Company's Gulf Coast activities focus on both shallow
exploitation and deeper exploration targets in the on-shore areas of South
Louisiana and the upper Texas Gulf Coast.  Focus areas of SouthTech are Acadia,
Jefferson Davis and Calcasieu Parishes of South Louisiana and Chambers County
in the upper Texas Gulf Coast.  The primary focus areas of Chenier are Saint
Landry and Evangeline Parishes of Louisiana.  Wells in the area target the
Frio, Vicksburg, Cockfield, Sparta and Wilcox formations at depths ranging from
1,500 to 11,500 feet.  The complex faulted and prolific salt dome dominated
region possesses more than 20 reservoir targets that, in various combinations,
provide attractive multi-zone drilling prospects from as shallow as 6,500 feet
to deeper than 12,000 feet.

Northern Rocky Mountains

HSR produces in two areas of the Northern Rocky Mountains, the Williston and
Green River Basins.  The Company operates wells in two fields in the Daniels
County, Montana portion of the Williston Basin.  These wells produce from the
Ratcliffe, McGowan and Mission Canyon formations at depths ranging from 5,900
to 6,500 feet.  The Company operates 18 wells in the Blue Forest Unit on the
Moxa Arch portion of the Green River Basin in Wyoming.  The Blue Forest Unit
currently produces from the Frontier and Muddy formations found at depths
ranging from 10,500 to 11,000 feet.  Although most of HSR's natural gas
production in Blue Forest Unit has been sold under the TCW Facility, the
Company has retained development, operating and certain marketing rights.

PROJECT INVENTORY

The following table summarizes the Company's inventory of projects identified
on its properties as of December 31, 1996.

<TABLE>
         <S>                                                               <C>
         Development and exploitation drilling (potential drillsites)....  1,200
         Infill (potential drillsites)...................................    750
         Recompletions...................................................    500
         Exploration prospects and leads.................................    100
         3-D seismic data (square miles).................................    476
</TABLE>


                                       14
<PAGE>   15
Denver-Julesburg Basin Projects

The Company has a significant inventory of investment opportunities in the D-J
Basin.  That inventory consists of development drilling on existing spacing,
behind-pipe recompletions, potential increased density drilling, wellbore
extensions, high angle drilling and exploration leads.

Wattenberg Field Area.  While Wattenberg has experienced high levels of
development activity in recent years, management believes significant untapped
reserves remain. HSR has, in its inventory, 890 development drillsites, of
which 663 are included in proved undeveloped reserves. In addition, the Company
has identified approximately 391 recompletion opportunities in Wattenberg.

A more significant opportunity may exist in the potential for increased density
or infill drilling in the Codell and Niobrara formations within Wattenberg.
HSR has undertaken a rigorous analysis to determine the potential for recovery
of additional economic reserves through increased density drilling.  This study
included extensive computer simulation to model the producing characteristics
of the formations as well as a pilot field program of drilling, completion and
production.  The initial conclusions of the feasibility study indicate that
there is significant potential to recover additional reserves at reduced costs,
both within currently producing fault blocks and by tapping fault blocks that
are isolated from existing wellbores, thereby minimizing surface disturbance.
Five lateral test wells have been successfully drilled and cased and are
producing from existing wellbores.  Five additional pilot wells were drilled
during the fourth quarter of 1996 and are being evaluated.  The Company
estimates that there are at least 750 potentially economic infill drillsites on
its Wattenberg acreage.

Finally, management believes that substantial opportunities may exist to tap
additional reserves through existing wellbore extensions and high angle
drilling.  The Company is conducting studies to evaluate these applications.

Greater D-J Basin.  The Greater D-J Basin, in which the Company owns rights to
more than 194,000 gross undeveloped acres, provides HSR with significant
exploitation and exploration potential through the use of advanced technologies
such as 3-D seismic continuity processing and geostatistical analysis.  To
date, the Company has drilled 449 wells in the area, with an estimated 8.6
MMBoe of proved reserves, and has 22 active prospects and leads under refinement
by geotechnical staff.  Geostatistical analysis using seismic responses shows
significant promise in helping not only to reduce dry-hole risk, but to also
target wells at optimal locations.  Recently the Company has drilled three
successful wells in its last three attempts.  Using advanced 3-D seismic
interpretation techniques, the Cervi-Federal #6-29, (producing 100 BOPD and 90
MCFPD), the Cervi-Federal #10-29, (producing 130 BOPD and 35 MCFPD), and the
Shoeneman #1-24, (which had an initial production of 110 BOPD, has been
successfully fracture treated and is currently producing at rates of 450 BOPD
and 300 MCFPD) have all been successful.

Mid-Continent Projects

Prior to the Merger, Tide West had established a reputation as an excellent
acquirer and efficient operator of oil and natural gas properties in the
Mid-Continent region, though it was not focused on aggressive geotechnical
exploitation of its properties.  Tide West owned interests in approximately 75
fields located in several Mid-Continent basins.  In the Company's opinion, this
presents an





                                       15
<PAGE>   16
opportunity to apply its expertise to prove-up and produce new reserves from
the Tide West properties.  HSR has added geological and geophysical staff to
the Mid-Continent district and has begun the process of high-grading
opportunities identified at the time of the Merger and applying technology to
uncover new opportunities.  The Company has drilled six wells since the Merger,
all of which were successfully completed, and has performed a number of
successful recompletions.

The Company has outlined an extensive inventory of exploitation and exploration
projects in the Mid-Continent region, many of which have been identified in the
limited time since the Merger.  At the present time, HSR has identified over
200 potential development and exploitation drilling opportunities and 84
recompletion opportunities on its primary focus list.  The following are a few
examples of such opportunities.

In the Anadarko Basin, the Company owns interests in 804 wells in numerous
fields, including Mocane-Laverne, Bivins Ranch, Bishop and Watonga, each of
which provides potentially attractive exploitation opportunities. The Company
has identified approximately 51 drilling opportunities and 30 recompletions in
these four fields.  Further work is under way, including processing of 13
square miles of 3-D seismic data on Bivins Ranch, which the Company anticipates
will lead to additional activity in these areas.

In the Arkoma Basin, the Company owns interest in 205 wells in Kinta, Bokoshe,
Russellville and other fields.  In those three fields alone, the Company has
identified approximately 129 drilling and 22 recompletion opportunities.

Other areas present additional opportunities.  For example, with the use of 3-D
seismic, the Company has identified further drilling opportunities at La
Reforma Field in northwestern Hidalgo County, Texas, where the Company owns
interests in a 5,100 acre contiguous block.

Gulf Coast Projects

Through SouthTech and Chenier, the Company has assembled a growing inventory of
both exploitation and exploration projects.  These joint ventures have 16
active major project areas and are aggressively pursuing others.  Six large 3-D
seismic surveys have been acquired, four additional surveys are planned and all
are being integrated into extensive subsurface mapping.

SouthTech has assembled seismic rights, options and leasehold interests in
approximately 90,000 gross undeveloped acres and intends to expand this
position in 1997.  SouthTech also has acquired over 140 square miles of 3-D
seismic data and has identified approximately 60 exploration prospects and
leads.  Chenier has assembled seismic rights, options and leases in
approximately 23,000 gross undeveloped acres.  South Devillier prospect is
typical of the opportunities available to the Company through SouthTech and
Chenier.  South Devillier is the first of the Company's Gulf Coast project
areas to be imaged by advanced 3-D seismic technology and fully interpreted.
This interpretation has allowed the Company to image several untested
prospective fault blocks within a known productive fairway of the Vicksburg Lox
"B" sandstone.  The first well drilled by HSR based on the South Devillier 3-D
interpretation encountered the Lox "B" as anticipated, although the well is not
capable of production in paying quantities.  HSR's second well on this shoot,
the Cooper #2, encountered 33' of reservoir quality Lox "B" sandstone in an
adjacent, untested fault block.  Pipe has been set on this well and HSR is
currently waiting on completion operations to





                                       16
<PAGE>   17
commence.  Based on the 3-D interpretation, there could be as many as 12
additional exploration opportunities on South Devillier alone.

The Company anticipates similar opportunities on many of its other Gulf Coast
projects.  On the Roanoke 3-D survey, HSR's first test, the Kratzer #1, has
encountered approximately 95' of apparent pay in 8 different zones of the Frio.
Intermediate casing has been set to protect these zones, while the well is
drilled deeper to test a high pressure Hackberry formation prospect, based on
the 3-D seismic.

Management believes that its expanding Gulf Coast activities will generate a
substantial inventory of exploitation and exploration opportunities in 1997 and
beyond.

Northern Rocky Mountain Projects

The Company has a significant inventory of undeveloped acreage and 3-D seismic
data in the northern Rocky Mountain area.  In the Williston Basin, HSR has
approximately 344,000 gross (186,000 net) undeveloped acres and nearly 150
square miles of 3-D seismic data.  In the Sand Wash Basin the Company has
approximately 123,000 gross (49,000 net) undeveloped acres and has entered into
agreements with two major oil companies that include 3-D seismic survey
commitments (18 square miles of which have been recently acquired) and options
to spend exploration capital on additional 3-D seismic surveys and exploratory
wells over the next 18 months.  HSR also has approximately 84,000 gross (57,000
net) undeveloped acres in the Greater Green River Basin.  The combination of
large acreage positions, high-quality reservoirs, 3-D seismic and
geostatistical applications and, with respect to the Williston Basin,
horizontal drilling, gives HSR exposure to significant potential in the Rocky
Mountain area.

ACREAGE

The Company's acreage positions have increased significantly, from
approximately 9,000 developed and 37,000 undeveloped net acres as of December
31, 1991 to approximately 327,000 developed and 721,000 undeveloped net acres
as of December 31, 1996.

The following table sets forth the gross and net developed and undeveloped
acres on which the Company owns the rights to conduct exploration and
development activity as of December 31, 1996.

<TABLE>
<CAPTION>
                                          Developed Acres                    Undeveloped Acres (1)
                                  ----------------------------          ----------------------------
                                    Gross               Net               Gross               Net
                                  ---------          ---------          ---------          ---------
<S>                               <C>                <C>                <C>                <C>    
D-J Basin                           179,277            144,301            269,610            234,972
Mid-Continent                       458,897            177,580             60,058             48,611
Gulf Coast                            3,107                537            130,094             49,603
Northern Rocky Mountains             13,141              4,244            652,022            387,411
                                  ---------          ---------          ---------          ---------
Total                               654,422            326,662          1,111,784            720,597
                                  =========          =========          =========          =========
</TABLE>

(1) Includes acres upon which the Company owns the rights to conduct seismic,
exploration and development activity but is not the lessee.





                                       17
<PAGE>   18
OIL AND GAS RESERVES

Two independent petroleum engineering consulting firms were engaged to review
the Company's estimates of its proved reserves, projected future production and
estimated future net revenues from production of proved reserves as of December
31, 1996.  Williamson Petroleum Consultants, Inc. reviewed HSR's DJ Basin,
Northern Rockies and Gulf Coast properties, and Netherland, Sewell &
Associates, Inc. reviewed the Company's Mid-Continent reserves.  Such estimates
were based upon a review of production histories and other geologic, economic,
ownership and engineering data provided by or available to the Company.  In
determining the estimates of the reserve quantities that are economically
recoverable, the Company used selling prices and estimated development and
production costs which were in effect as of December 31, 1996.  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, 1996, derived from the Company's 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 the
Company. In the aggregate, 78.4% of the Company's total reserves were reviewed
by the two engineering firms.

<TABLE>
<CAPTION>
                                                                     Net Proved Reserves
                                                                   as of December 31, 1996
                                                      --------------------------------------------------
                                                       Developed         Undeveloped             Total
                                                      ----------         -----------          ----------
<S>                                                       <C>                 <C>                 <C>   
Oil and condensate (MBbl)                                 23,111              11,503              34,614
Natural gas (MMcf)                                       508,923             135,498             644,421
Equivalent barrels (MBoe)                                107,932              34,086             142,018
Present value of estimated
    future net revenues before income
    taxes (discounted at 10%) (in thousands)          $  915,102          $  215,821          $1,130,923
</TABLE>

There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company.  The
reserve data set forth herein 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 an estimate may
justify revision of such estimates, and such revisions may be material.
Accordingly, reserve estimates are often different from the quantities of oil
and gas that are ultimately recovered. Furthermore, the estimated future net
revenues from proved reserves and the present value thereof are based upon
certain assumptions, including prices, future production levels and cost, that
may not prove over time to have been correct.

Predictions about prices and future production levels are subject to great
uncertainty, and this is particularly true as to proved undeveloped reserves,
which are inherently less certain than proved developed reserves, and which
comprise a significant portion of the Company's proved reserves.





                                       18
<PAGE>   19
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 the Company's
proved reserves and future net revenue therefrom at December 31, 1996, were
$24.92 per Bbl of oil and $3.39 per Mcf of gas.  Oil and gas prices as of the
date of this 10-K Report are significantly lower than the 1996 year end prices
used in the foregoing Securities and Exchange Commission analysis.  For
cautions regarding forward- looking statements made or implied by the Company
see Item 7.  "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Disclosure Regarding Forward-Looking Statements."

For further information concerning the present value of future net revenue from
the Company's proved reserves, see Note 15 of the Notes to Consolidated
Financial Statements.

Since December 31, 1990, as an operator of domestic oil and gas properties, the
Company 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 herein.  The difference
is attributable to the fact that 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 that on a net interest basis), while reserves reported herein are net to
the Company.

DRILLING ACTIVITY

The following table sets forth the net wells drilled and completed by the
Company during the periods indicated.  Substantially all of the Company's wells
produce both oil and gas.

<TABLE>
<CAPTION>
                         Year Ended December 31,
                      ----------------------------
                        1996      1995      1994
                      --------  --------  --------
<S>                      <C>        <C>      <C>  
Development:
      Productive         116.7      69.7     184.7
      Non-productive       0.0       5.4       6.2
                      --------  --------  --------
          Total          116.7      75.1     190.9
                      --------  --------  --------
Exploratory:
      Productive           3.5      21.3      18.7
      Non-productive       0.0      12.3       5.6
                      --------  --------  --------
          Total            3.5      33.6      24.3
                      --------  --------  --------
Total wells              120.2     108.7     215.2
                      ========  ========  ========
</TABLE>


                                       19
<PAGE>   20
PRODUCTIVE OIL AND GAS WELLS

The number of productive oil and gas wells, operated and non-operated, in which
the Company had an interest as of December 31, 1996, are as follows:

<TABLE>
<CAPTION>
                     Gross Productive Wells          Net Productive Wells
                   --------------------------    ------------------------------
                               Non-                            Non-
                   Operated  Operated   Total    Operated    Operated    Total
                   --------  --------   -----    --------    --------   -------
<S>                 <C>         <C>     <C>       <C>            <C>    <C>    
Oil                 2,041       311     2,352     1,903.8        79.3   1,983.1
Gas                   598       612     1,210       474.8        98.1     572.9
                    -----     -----     -----     -------     -------   -------
    Total           2,639       923     3,562     2,378.6       177.4   2,556.0
                    =====     =====     =====     =======     =======   =======
</TABLE>

Wells are classified as oil or gas producers as described in statutory
definitions based on oil/gas ratios.  As a result, most of the Company's wells
are 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 sets forth certain information regarding the costs incurred
by the Company in its development, exploration and acquisition activities
during the periods indicated.

<TABLE>
<CAPTION>
                                        Year Ended December 31,
                                 ----------------------------------
                                   1996         1995         1994
                                 --------     --------     --------
<S>                              <C>          <C>          <C>     
Acquisition costs:
(dollars in thousands)
    Unproved properties          $ 35,227     $  4,343     $ 11,444
    Proved properties             338,814       25,015        2,600
    Development costs              37,819       29,989       64,564
    Exploration costs               2,100        2,748        3,293
                                 --------     --------     --------
        Total costs incurred     $413,960     $ 62,095     $ 81,901
                                 ========     ========     ========
</TABLE>


                                       20
<PAGE>   21
PRODUCTION

The following table sets forth the Company's oil and gas production data during
the periods indicated.

<TABLE>
<CAPTION>
                                    Year Ended December 31,
                                   -------------------------- 
                                     1996     1995     1994
                                   --------  -------  -------
<S>                                <C>       <C>      <C>  
Net production:
    Oil and condensate (MBbl)         1,923    1,582    1,664
    Natural gas (MMcf)               34,163   21,049   20,108
    Equivalent barrels (MBoe)         7,617    5,090    5,015
Average net daily production (1):
    Oil and condensate (Bbl)          6,121    4,333    4,559
    Natural gas (Mcf)               118,930   57,670   55,090
    Equivalent barrels (Boe)         25,942   13,945   13,740
Average sales price per unit:
    Oil and condensate ($/Bbl)     $  20.90  $ 16.52  $ 14.83
    Natural gas ($/Mcf)            $   1.96  $  1.30  $  1.70
Lease operating expense ($/Boe)    $   2.32  $  1.95  $  1.66
</TABLE>

(1) Average daily production for 1996 was calculated for the quarter ended
    December 31, 1996, as these results are believed to be more indicative of
    current performance.

Item 3.          LEGAL PROCEEDINGS AND ENVIRONMENTAL ISSUES

Litigation.      At this time, the Company is involved in no material
litigation, however, the Company is involved in various claims and lawsuits
incidental to its business.

Environmental Proceedings.  The owner of an oil field waste disposal facility,
a major oil company and the Company were named as respondents by the United
States Environmental Protection Agency ("EPA") in an administrative order
brought by the EPA against Weld County Waste Disposal, Inc. ("WCWDI") under
section 7003 of the Resource Conservation and Recovery Act ("RCRA") on May 11,
1995.  WCWDI operated and continues to own an evaporation pit in Colorado for
the disposal of non-hazardous production wastes.  The EPA order requires that
work be performed to abate a perceived endangerment to wildlife, the
environment or public welfare.  The Company and other non-operator respondents
are working together with the EPA to develop plans and characterization
studies, and have caused the facility to be permanently closed.

The Company has utilized this facility in past years to dispose of its
production and flowback water.  During the period of its use, the Company
believed that the facility was operating in compliance with all applicable
legal requirements and, along with other oil and gas operators, paid a fee to
WCWDI for using this disposal facility.  There were a number of other
significant contributors to the facility during the period reviewed by the EPA
(1988 through 1994) and additional contributors during the period from 1977,
when it was constructed, through 1988.  The Company and the major oil company
were named because they were deemed the major





                                       21
<PAGE>   22
contributors of waste volumes to the facility for the period reviewed by the
EPA.  Certain other contributors are participating in their share of the
reclamation costs.

Based on the Company's current knowledge and its expectation of proportionate
reimbursement from other parties who utilized the facility, the Company does
not believe that its share of the reclamation costs will have a material impact
on its financial condition or results of operations.  By agreement with other
contributing parties, the Company is currently paying approximately 50% of the
costs associated with the project, but after recovery from additional liable
parties, the Company's percentage share of overall costs may be reduced to as
low as 40%.  The Company has spent approximately $460,000 on its behalf to date
on the project.  The Company's share of total costs associated with the
project, at the 50% level of participation, are currently estimated to range
from $1 to $2 million over three years.  The full amount of the Company's
estimated liability is reflected in the December 31, 1996 financial statements.
See Note 2 of Notes to Consolidated Financial Statements.

Item 4.          SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.





                                       22
<PAGE>   23
                                    PART II


Item 5.      MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
             MATTERS

The Company's common stock (NYSE symbol "HSE") began trading publicly on the
NYSE effective June 22, 1994.  Prior to that, the Company was traded on the
NASDAQ National Market System under the symbol "HSRS" effective November 24,
1992.  There was no public market for the common stock before November 24,
1992.  The following table presents the high and low sales prices reported by
the NASDAQ and 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, 1994                       $  24 3/4                 $  18 3/4
June 30, 1994                           22 5/8                    18
September 30, 1994                      22 7/8                    19 1/4
December 31, 1994                       21 1/2                    17 1/8
March 31, 1995                          17 1/2                    13 3/4
June 30, 1995                           16 7/8                    13 3/4
September 30, 1995                      15 1/8                    13 1/8
December 31, 1995                       14 7/8                    12 5/8
March 31, 1996                          13 1/8                     9 1/4
June 30, 1996                           13 1/4                    10 3/8
September 30, 1996                      14 1/8                    11 3/4
December 31, 1996                       17 5/8                    12 7/8
</TABLE>

As of December 31, 1996, there were 449 holders of record of the common stock.

The Company has never paid any cash dividends on its common stock, and the
Board of Directors of the Company does not currently intend to declare cash
dividends on its common stock.  The Company instead intends to retain its
earnings to support the growth of the Company's business.  Any future cash
dividends would depend on future earnings, capital requirements and the
Company's financial condition and other factors deemed relevant by the Board of
Directors.  The Company's credit facility currently prohibits payment of
dividends and the indentures governing its outstanding 9 1/4% and 9 7/8% senior
subordinated notes due in 2006 and 2003, respectively also limit the Company's
ability to pay dividends.





                                       23
<PAGE>   24
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 herein.  See
also, Management's Discussion and Analysis of Financial Condition and Results
of Operations.

                    (In thousands, except per share amounts and average prices)
                                               For the Years Ended December 31,
<TABLE>
<CAPTION>
                                                 1996          1995          1994          1993          1992
                                              ----------    ----------    ----------    ----------    ----------
<S>                                           <C>           <C>           <C>           <C>           <C>       
STATEMENT OF OPERATIONS DATA
   Oil and natural gas sales                  $  107,281    $   53,394    $   58,827    $   45,382    $   25,950
   Trading and transportation                     46,373          --            --            --            --
   Other revenues                                  3,302         1,946         1,574         2,095         1,683
                                              ----------    ----------    ----------    ----------    ----------
       Total revenues                            156,956        55,340        60,401        47,477        27,633
                                              ----------    ----------    ----------    ----------    ----------
   Production taxes                                8,195         4,050         5,134         4,222         2,493
   Lease operating expenses                       17,692         9,936         8,310         5,470         2,831
   Cost of trading and transportation             45,699          --            --            --            --
   Depreciation, depletion and amortization       42,335        26,609        25,079        15,299         8,829
   General and administrative expenses             5,642         4,076         4,228         3,123         1,874
   Interest expense                               22,936        10,219         7,539         3,118         4,039
                                              ----------    ----------    ----------    ----------    ----------
       Total expenses                            142,499        54,890        50,290        31,232        20,066
                                              ----------    ----------    ----------    ----------    ----------
   Income before provision for income
       taxes and extraordinary item               14,457           450        10,111        16,245         7,567
   Provision for income taxes                     (5,508)         (176)       (3,852)       (6,189)       (2,883)
   Extraordinary item, net of tax                   --            --            --            --            (994)
                                              ----------    ----------    ----------    ----------    ----------
   Net income                                 $    8,949    $      274    $    6,259    $   10,056    $    3,690
                                              ----------    ----------    ----------    ----------    ----------
   Net income per share, assuming
       full dilution                          $     0.61    $     0.02    $     0.53    $     0.92    $     0.55
                                              ----------    ----------    ----------    ----------    ----------
   Weighted average number of shares
       outstanding, assuming full dilution        14,769        11,450        11,724        10,938         6,747
                                              ----------    ----------    ----------    ----------    ----------
BALANCE SHEET DATA
   Working capital (deficiency)               $   13,749    $  (16,115)   $   (2,384)   $   16,221    $    3,606
   Oil and gas properties, net                   652,180       278,811       242,009       184,188       102,517
   Total assets                                  731,285       302,089       269,070       228,260       120,452
   Long-term debt, net of current portion        398,563       125,537       103,478        74,420        20,640
   Deferred income taxes                          84,829        23,604        23,432        19,589         9,868
   Stockholders' equity                          192,724       119,174       119,358       113,299        78,731
OPERATING DATA
   Average sales price per barrel of oil      $    20.90    $    16.52    $    14.83    $    16.09    $    19.16
   Average sales price per thousand
       cubic feet of natural gas              $     1.96    $     1.30    $     1.70    $     2.03    $     1.78
PRODUCTION
   Oil (MBbls)                                     1,923         1,582         1,664           967           539
   Natural gas (MMcf)                             34,163        21,049        20,108        14,684         8,770
   MBoe                                            7,617         5,090         5,015         3,414         2,000

NET CASH PROVIDED BY
   OPERATING ACTIVITIES                       $   52,251    $   31,179    $   36,553    $   33,745    $   20,469
</TABLE>


                                       24
<PAGE>   25
Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
           RESULTS OF OPERATIONS

GENERAL  Over the past 12 months, the Company has undertaken several strategic
initiatives that have positioned the Company for a period of significant growth
in reserves, production, cash flow and earnings.  In 1995, the Company
articulated a strategy that included (i) consolidating in its core geographic
areas, particularly the D-J Basin, (ii) diversifying its asset base outside of
the D-J Basin, (iii) capturing more of the value stream by marketing its
production and (iv) maximizing its financial flexibility.  By completing the
Acquisitions and the Merger and by forming two important, exploration-focused
Gulf Coast joint ventures, SouthTech and Chenier, HSR has taken the fundamental
initial steps to implement its strategy.  Management's focus for the
foreseeable future will be to continue to execute this strategy with particular
emphasis on activities that maximize the financial returns from HSR's expanded
asset base.

The Company now has three significant core areas of operations, the geologic
and geographic diversity of which combine to create an oil and natural gas
company with attractive, long-lived reserves balanced with meaningful exposure
to exploration and technologically-driven upside.  The Company has also created
a strategically important and profitable presence in the natural gas marketing,
trading and transportation business, which provides the opportunity for the
Company to increase its operating margins on production from both the D-J Basin
and Mid-Continent areas and has begun an oil trading and transportation
business to be engaged in the purchase, sale and transport of crude oil.

The United States oil and gas industry is subject to large variations in
profitability due in part, to fluctuating commodity prices and related changes
in rates of reinvestment by industry participants.  Over the past year the
industry has seen increases in both oil and natural gas prices from the
relatively low price levels experienced in 1995.  Several factors have lead to
a positive fundamental outlook for the oil and gas industry and improved
economics for production in the Company's core geographic areas.  These include
(i) low natural gas storage levels combined with relatively high wellhead
capacity utilization, (ii) increasing overall natural gas demand, (iii)
deregulation of distribution and marketing channels, particularly for D-J Basin
and Rocky Mountain production, and expansion of pipeline capacity to transfer
gas to markets outside the Colorado Front Range and (iv) successful application
of advanced oil and natural gas exploration, drilling and production
technologies.  Since the end of 1996, oil and natural gas prices have decreased
in certain areas of the country, in part due to weather conditions.

NATURAL GAS PRICE CONSIDERATIONS  Approximately 76% of the Company's proved
producing reserves consist of natural gas located in the D-J Basin and
Mid-Continent areas.  The absolute level and volatility of natural gas prices
have  a material impact on the Company.

During 1995 and early 1996, prices for Rocky Mountain natural gas were
substantially below prices for natural gas in markets outside the Rocky
Mountain region.  This disparity was caused by low demand for Rocky Mountain
gas due to an unusually warm winter season and above-normal availability of
hydro-electric power in the western United States.  This resulted in excess
natural gas supply in the Rocky Mountains which led to downward price pressure
in the Colorado Front Range market.  However, through the end of 1996, the
market for the Company's





                                       25
<PAGE>   26
D-J Basin natural gas had strengthened substantially due to several factors.
First, the excess supply from Wyoming natural gas producers has declined as a
result of increased demand from West Coast markets.  Second, in October 1995,
the Colorado Public Utilities Commission approved tariff changes that
effectively eliminated transportation costs for D- J Basin natural gas sold to
the Colorado Front Range market, resulting in an approximately $0.40 per MMBtu
transportation cost advantage for D-J Basin producers.  Third, the supply of
D-J Basin natural gas has declined over the last two years due to reduced
drilling in the D-J Basin and natural production declines.  The average natural
gas price received by the Company for its D-J Basin production has increased
from $1.28 per Mcf in 1995 to $1.90 per Mcf in 1996.  In addition, expansion of
pipeline capacity has begun, which will, in mid-to-late 1997, provide
additional transportation outlets for Wyoming producers to markets other than
the Colorado Front Range.  The Company believes that these developments will
further reduce the disparity between D-J Basin pricing and pricing generally
available elsewhere in the United States.

The D-J Basin provides a significant portion of the Company's natural gas
production.  Historically, the price of D-J Basin natural gas (on a
Btu-equivalent basis) has been linked closely to the Colorado Interstate Gas
pipeline ("CIG") Rocky Mountain Index.  However, more recently, as a result of
the tariff changes and the seasonal nature of demand in the Colorado Front
Range, the price for D-J Basin natural gas tends to reflect the CIG Rocky
Mountain Index during the low demand summer months (generally April through
October) and Mid-Continent indices during the high demand winter periods
(generally November through March).

Gas prices in the Mid-Continent are closely tied to established indices which
are influenced by national supply and demand factors.  Average natural gas
prices received by the Company in the Mid-Continent  generally fluctuate with
changes in Mid-Continent posted prices, which for the years 1993 through 1996
averaged $0.25 per MMbtu less than the Henry Hub price.  The average natural
gas price received in the Mid-Continent since the Merger in June 1996 through
December 31, 1996, was $2.24 per Mcf, or $0.29 below the Henry Hub price
(before hedging).

OIL PRICE CONSIDERATIONS  Oil prices are established in a highly liquid
international market.  Average oil prices received by the Company in the D-J
Basin and Mid-Continent generally fluctuate with changes in the NYMEX West
Texas Intermediate ("NYMEX-WTI") crude oil closing prices.  The Company's
average oil price for 1995 was approximately $1.77 per Bbl below NYMEX-WTI
closing prices.  The average oil price for 1996 was approximately $0.45 below
NYMEX-WTI closing prices.  The increase in the relative value of the Company's
oil production during 1996 is a result of renegotiation of several oil sales
contracts, as well as the general increase in the market value of the Company's
D-J Basin oil production.

RESULTS OF OPERATIONS  During 1996 the Company continued drilling and
development activity in the D-J Basin and completed the Merger and the
Acquisitions.  At December 31, 1996, the Company owned interests in more than
3,500 producing wells (of which it operated more than 2,600) compared to 1,300
wells (of which it operated more than 1,100) at December 31, 1995. The
Company's results of operations have been significantly affected by the
Acquisitions, the Merger and its drilling program.  Fluctuations in oil and
natural gas prices have also significantly affected the Company's results.





                                       26
<PAGE>   27
COMPARISON OF YEARS ENDED DECEMBER 31, 1996 AND 1995

OIL AND GAS REVENUES  For the comparative periods, oil production increased
from 1,582 MBbls to 1,923 MBbls and gas production increased from 21,049 MMcf
to 34,163 MMcf, or 22% and 62%, respectively.  Average oil prices realized
increased by 27% from $16.52 to $20.90 per Bbl and average gas prices realized
increased by 51% from $1.30 to $1.96 per Mcf.  The production increases were
the result of additional production from the properties acquired in the
Acquisitions and the Merger and new wells drilled by the Company.  The net
effect of these changes resulted in an increase in oil and gas revenues from
$53.4 million to $107.3 million or 101%.  The Company also recognized $2.7
million in other gas revenues from the sale of tax credits with respect to its
Section 29 tax credit agreements for the year ended December 31, 1996, as
discussed in Note 12 of the Notes to Consolidated Financial Statements.

The Company, through its gas marketing division and its wholly owned
subsidiary, TWTT, actively markets a portion of its own natural gas production,
markets natural gas to third parties and supplies natural gas to end-users.
Trading and transportation net margins were $673,553 at December 31, 1996.
There were no comparable revenues in 1995.

INTEREST INCOME AND OTHER INCOME  Interest and other income increased by
$418,557, or 256%, for the year ended December 31, 1996.  The increase in
interest and other income was mainly due to short term investing of the
Company's available funds, as well as a gain recorded on the sale of assets of
$118,649.

PRODUCTION EXPENSES  Lease operating expenses increased by $7,755,693, or 78%,
due to an increase in the number of producing wells.  On a Boe basis, lease
operating expenses increased from $1.95 to $2.32 for the comparative periods.
This increase is primarily the result of a different mix of wells in the
current year, including wells with historically higher operating costs which
were acquired as a result of the Acquisitions.  Production taxes increased by
$4,144,906, or 102%, due to increased production and prices.  Production taxes
in 1996 reflect an adjustment for a reduction in the Company's severance tax
rate.  A cumulative rate adjustment for 1995 was recorded in the third quarter
of 1995.

DEPRECIATION, DEPLETION AND AMORTIZATION  Depreciation, depletion and
amortization ("DD&A"), a non-cash expense, increased $15,725,997, or 59%, due
to an increase in production and an increase in the depletion rate.  For the
year ended December 31, 1996, the Company had a weighted depletion rate of
$5.33 per Boe ($5.41 for the quarter end December 31, 1996).  The Company
adjusts its DD&A rate based on material changes in its reserves and on an
annual basis based on year end engineering.

GENERAL AND ADMINISTRATIVE EXPENSE  General and administrative expense reflects
costs incurred net of administrative costs directly attributable to drilling
and well operations, which costs are included in lease operating expenses or
are capitalized.  General and administrative expenses increased $1,566,812, or
38%.  The increase for the comparative periods is primarily attributable to the
Merger and retention of the former Tide West employees.  On a Boe basis,
general and administrative expenses decreased from $0.80 to $0.74 for the
comparative periods.





                                       27
<PAGE>   28
INTEREST EXPENSE  Interest expense increased $12,717,285 or 124%, due to
increased borrowings on the Company's long-term bank debt.  Also, in November
1996, the Company issued $150 million of its 9  1/4% senior subordinated notes
due in 2006.

PROVISION FOR INCOME TAXES  The Company follows the provisions of Statement of
Financial Accounting Standards ("SFAS") No. 109.  Pursuant to SFAS 109, the
Company has recorded a tax provision based on tax rates in effect during the
period.  Accordingly, the Company accrued taxes at the rate of 38.1% in 1996
and 1995.  Due to significant intangible drilling costs, which are deductible
for tax purposes, substantially all of the Company's tax provision in both
periods is deferred.

COMPARISON OF YEARS ENDED DECEMBER 31, 1995 AND 1994

OIL AND GAS REVENUES  For the comparative periods, oil production decreased
from 1,664 MBbls to 1,582 MBbls and gas production increased from 20,108 MMcf
to 21,049 MMcf, or 5% and 5%, respectively.  The average price of oil increased
by 11% from $14.83 to $16.52 per Bbl, and gas prices decreased by 24%, from
$1.70 to $1.30 per Mcf.  The net effect of these changes resulted in an oil and
gas revenue decrease of 9% from $58.8 million to $53.4 million.  The Company
also recognized $1.8 million in other gas revenues from the sale of tax credits
for the year ended December 31, 1995, as discussed in Note 11 and Note 12 of
the Notes to Consolidated Financial Statements.

INTEREST AND OTHER INCOME  Interest and other income decreased by $75,841 or
32%, for the year ended December 31, 1995.  This was due primarily to short
term investing of additional funds in the prior year, which were available as a
result of the November 1993 offerings.  By the end of the second quarter of
1994, the Company's drilling programs absorbed any remaining available funds
from those offerings.

PRODUCTION EXPENSES  Lease operating expenses increased by $1.6 million or 20%,
due to the increase in the number of producing wells.  Production taxes, which
are a direct result of oil and gas sales, decreased by $1.1 million or 21%, for
the period ended December 31, 1995, as a result of the decrease in oil and gas
sales, as well as a reduction in the Company's effective severance tax rate.

DEPRECIATION, DEPLETION AND AMORTIZATION  Depreciation, depletion and
amortization increased by $1.5 million or 6%, for the year ended December 31,
1995, due to an overall increase in production and an increase in the depletion
rate from $4.80 per Boe to $4.97 per Boe.

GENERAL AND ADMINISTRATIVE EXPENSES  General and administrative expenses
reflect costs incurred, net of administrative costs directly attributable to
drilling and well operations.  Such costs are included in lease operating
expenses or are capitalized.  General and administrative expenses decreased
$152,891 or 4%, for the period ended December 31, 1995.  The decrease is due to
the increased well-related reimbursements resulting from an increase in the
number of wells operated.





                                       28
<PAGE>   29
INTEREST EXPENSE  Interest expense for the period ended December 31, 1995,
increased $2.7 million or 36%.  The increase is due to increased borrowings on
the Company's long-term bank debt.

PROVISION FOR INCOME TAXES  Pursuant to SFAS 109, the Company has recorded a
tax provision based on tax rates in effect during the period.  Accordingly, the
Company accrued taxes at the rate of 38.1% in 1995 and 1994.  Due to
significant intangible drilling costs, which are deductible for tax purposes,
all of the Company's tax provision in both periods is deferred.

LIQUIDITY AND CAPITAL RESOURCES

Financing Sources

The Company is committed to reducing its debt to total book capitalization
ratio and is currently evaluating various alternatives by which to do so,
including asset divestitures.  The Company believes that it will be able to
arrange a favorable combination of financing alternatives to fund its ongoing
capital requirements and reduce its overall financial leverage.  Until this
debt ratio is reduced, the Company currently plans to fund capital expenditures
attributable to exploration and drilling activities primarily out of its
expected cash flow from operations.  The Company has financed, and expects to
continue to finance, its acquisition activities, if any, with (i) cash flow
from operations, (ii) borrowings under the Chase Facility (defined below),
(iii) public offerings of equity and debt, (iv) divestitures (including asset
monetizations) of non-core assets and (v) the TCW Facility (as defined).
Borrowings in connection with acquisitions may have the affect of increasing
the Company's leverage.

On June 7, 1996, the Company entered into a $180 million revolving and senior
bank credit facility with The Chase Manhattan Bank, as agent (the "Chase
Facility").  On June 14, 1996, the Company amended the terms of the Chase
Facility to increase the maximum credit amount to $350 million.  Under the
terms of the Chase Facility, no principal payments are required until June 14,
2001, assuming the Company maintains a Borrowing Base sufficient to support the
outstanding loan balance.  The Borrowing Base is based on the underlying value
of the Company's oil and natural gas properties.  The Chase Facility bears
interest at the Base Rate plus 0% to 0.5% or LIBOR plus 0.75% to 1.5%.  As part
of the amendment to the Chase Facility, Tide West's senior bank debt in the
amount of $39.5 million was fully repaid.

In November 1996, the Company issued $150 million of its 9 1/4% senior
subordinated notes due in 2006 (the "Notes"). The offering of the Notes (the
"Offering") was undertaken in order to replace a portion of the Company's
outstanding indebtedness under the Chase Facility with fixed rate term debt.
Upon consummation of the Offering and the application of the estimated net
proceeds therefrom, the borrowing base under the Chase Facility was amended to
$275 million, resulting in an amount available for borrowing of $101 million at
December 31, 1996.

The Notes issued are general, unsecured obligations of the Company,
subordinated in right of payment to all existing and any future senior
indebtedness of the



                                       29
<PAGE>   30
Company.  The Notes rank pari passu with existing and any future senior
subordinated indebtedness (including the Company's   9 7/8% senior subordinated
notes) and senior to any future subordinated indebtedness of the Company.  The
Notes are fully and unconditionally guaranteed, jointly and severally, on an
unsecured, senior subordinated basis by two of the Company's subsidiaries,
Orion Acquisition, Inc. and HSRTW, Inc. (the Subsidiary Guarantors").  There
are no significant contractual restrictions on distributions from each of the
Subsidiary Guarantors to the Company.

In August 1995, the Company signed a Term Sheet with a Trust Company of the
West-related entity covering a proposed $90 million non-recourse, volumetric
overriding royalty facility (the "TCW Facility").  The proceeds from the TCW
Facility may be used by the Company at its discretion for a variety of
corporate purposes, including acquisitions of new properties, exploration and
development drilling and monetization of existing corporate properties.
Effective July 1996, the Company sold certain non-strategic properties under
the TCW Facility for total consideration of $9.4 million.  The Company used the
sale proceeds to repay indebtedness under the Chase Facility.

The Company anticipates that its available borrowing capacity under the Chase
Facility, combined with its operating cash flow and the TCW Facility, provide
the Company with the financial resources and flexibility to fund current and
ongoing development activities and to meet other financial obligations.  Since
the consummation of the Merger and the Acquisitions, the Company has monetized
$20 million of non-strategic properties (including the TCW sale), using the
proceeds to reduce outstanding borrowings under the Chase Facility.  The nature
of the Company's current development strategies and other activities provide
the Company with considerable flexibility in terms of the timing and magnitude
of its capital expenditures.  If the Company experiences unforeseen changes in
its working capital position or capital resources, management may revise the
capital expenditure program accordingly or alternatively may supplement the
capital position of the Company through, among other things, the issuance of
additional equity or debt securities or by entering into joint venture
arrangements.

Capital Commitments

For the twelve months ended December 31, 1996, the Company incurred total
exploration, development and leasehold capital expenditures of $50.6 million.
The Company estimates capital expenditures for 1997 will be approximately $65
million, which will be allocated in varying amounts primarily to activities in
the Company's three core geographic areas:  the D- J Basin of the Rocky
Mountains, the Anadarko and Arkoma Basins of the Mid-Continent and the on-shore
Gulf Coast region.  The Company continuously evaluates its inventory of
drilling opportunities and adjusts the amount and allocation of its capital
program based on a number of factors, including seismic results, prospect
readiness, product prices, service company availability and rates, acquisitions
and capital position.

A major component of the Company's capital expenditure program includes costs
associated with the consolidation and development drilling in the D-J Basin,
and, to a lesser extent, the development of its other Rocky Mountain
properties.  In the second quarter of 1996, the Company acquired Basin's D-J
Basin properties for a total cash consideration of $125.5 million.  The
Acquisitions increased the Company's D-J Basin reserves by 35 MMBoe and
production by 5,500 Boe per day.  The Company also incurred approximately $31.3
million in capital





                                       30
<PAGE>   31
expenditures in 1996 for drilling and recompleting wells and building gathering
systems on the Company's existing Wattenberg Field area properties, compared to
$14.9 million in 1995.

The second component of the Company's capital expenditure program is the
continued exploitation of the properties acquired as a result of the Merger
with Tide West.  Since the completion of the Merger in June 1996, the Company
has incurred total exploitation and development expenditures in the
Mid-Continent area of $4.7 million.  The Company is currently evaluating a
variety of opportunities that include increased exploitation, exploration and
density drilling, recompletions and field extensions.

The final component of the Company's capital expenditure program is to develop
exploitation and exploration prospects in the Gulf Coast.  As described below,
the Company has entered into two joint ventures.  In 1996, the Company incurred
total capital expenditures of $7.6 million in the Gulf Coast.  The Company
spent approximately $2.0 million under the SouthTech joint venture in 1995 for
seismic, leasehold and overhead costs.  In 1996, the Company spent
approximately $3.3 million in similar costs and for drilling.

In June 1996, the Company entered into an exploration and development agreement
with Chenier Exploration, Inc. ("CEI"), pursuant to which the Company purchased
from CEI and a third party interests in properties in the Gulf Coast for
approximately $1.9 million, of which $1.2 million was paid in cash and the
remaining portion was funded with a promissory note.  Under the terms of the
agreements, CEI will be responsible for the generation and development of
prospects in the project areas.  In 1996, the Company spent $2.3 for seismic,
leasehold, drilling and overhead costs.

In 1994, the Company entered into an exploration agreement with Union Pacific
Resources Company covering drilling locations in the D-J Basin, pursuant to
which the Company committed to spend $9.3 million during the two years ended
June 1996 and meet certain other minimum obligations.  All such commitments
have been met.  In 1996, the Company elected to extend the agreement and
committed to spend approximately $2.4 million by June 1997.  The Company has
also entered into a number of other standard industry arrangements that require
the drilling of wells or other activities.  The Company believes that it will
meet its obligations under these arrangements, which individually and in the
aggregate are not material.

Working Capital and Cash Flow

Working capital at December 31, 1996 was $13.7 million.  Net cash provided by
operating activities for the year ended December 31, 1996, was $52.3 million,
up from $ 31.2 million in the same period in 1995.  This increase is primarily
the result of increased oil and natural gas production revenues attributable to
the larger number of producing wells resulting from its drilling activities and
the wells acquired in the Acquisitions and the Merger, as well as higher
product prices.  Future cash flows will be influenced by, among other factors,
the number of producing wells on line, product prices and production
constraints.

Risk Management.  The Company uses financial instruments to reduce its exposure
to market fluctuations in the price and transportation cost of oil and natural
gas.  The Company's general





                                       31
<PAGE>   32
strategy is to hedge price and location risk with swap, collar, floor and
ceiling arrangements.  When utilizing such instruments, the Company strives to
hedge its production back to the wellhead, to minimize basis risk.  In addition
to hedging activities, the Company is engaged in using the financial markets to
capture trading margins.  The Company has established policies with respect to
open positions which limit its exposure to market risk and requires reporting
to management of the potential financial exposure on a daily basis resulting
from both hedging and trading activities.

Hedging Activities.  Activities for hedging purposes are entered into by the
Company to manage its exposure to price and location risks in the marketing of
its oil and natural gas production and, in the case of its marketing
activities, third party natural gas.  Gains and losses on hedging positions are
deferred and recognized in the period the underlying physical transactions
occur in "oil and natural gas sales" and "trading and transportation revenues"
(for third party natural gas).

The Company has entered into the following forward sales and swap arrangements
with respect to its natural gas production for the quarters indicated below
(total average daily natural gas production for the quarter ended December 31,
1996 was 118,930 Mcf/day):

<TABLE>
<CAPTION>
                               Average Daily Volume              Average Price
Period Hedged                         (MCFD)                    for the Period
<S>         <C>                       <C>                            <C>  
1st Quarter 1997                      36,000                         $1.98
2nd Quarter 1997                      31,720                         $1.99
3rd Quarter 1997                      10,000                         $1.99
October 1-31, 1997                    10,000                         $1.99
</TABLE>




The Company has hedged through collar arrangements approximately two-thirds of
its oil production at a floor price of $20.00 and a ceiling price of $24.00 per
Bbl through the first quarter of 1997.  Additionally, with respect to the
hedging of third party natural gas, the Company has hedged 8.6 Bcf through
December 1997 with offsetting physical positions at settlement prices which are
based upon NYMEX future prices or other published indices.

Trading Activities.  The Company engages 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 variable
price for the commodity, swap or other contractual arrangement.  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 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 the Company's position in an
orderly manner over a reasonable period of time under present market
conditions.





                                       32
<PAGE>   33
Company policy requires that financial instrument purchase and sales contracts
be balanced in terms of contract volumes and the timing of performance and
delivery obligations.  As of December 31, 1996, all open positions were
balanced with an offsetting position.  During 1996, gains of $462,000 were
recognized in connection with these 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 investment grade financial institutions.  Accordingly, the
Company does not anticipate any material impact to its financial position or
results of operations as a result of nonperformance by the third parties on
financial instruments related to hedging activities or trading activities.

Interest rate swaps.  During the second quarter of 1995, the Company entered
into an interest rate exchange agreement with a financial institution to hedge
its interest rate on $40 million of the Company's borrowings at 7.76% through
May 2002.  Under the terms of the agreement, the difference between the
Company's fixed rate of 7.76% and the three month LIBOR rate plus 1.125% is
received or paid by the Company.

The Company, through the Merger, assumed interest rate exchange agreements with
two financial institutions to hedge its interest rate on a total of $40 million
of the Company's borrowings at rates ranging from 6.16% to 7.32% for 1997
through 1999.  Under the terms of these agreements, the difference between the
Company's fixed rate and the three month LIBOR rate is received or paid by the
Company.

Contingencies

In May 1995, the Company was named as a respondent by the United States
Environmental Protection Agency (the "EPA") in an administrative order brought
under the Resource Conservation and Recovery Act ("RCRA") by the EPA against
the owner/operator of an oilfield production water evaporation facility.  Based
on its evaluation of the above matters, and after consideration of reserves
established, the Company believes the resolution of such matters will not have
a material adverse effect on the Company's financial position or results of
operations.  See Item 3.  "Legal Proceedings--Environmental Issues" and Note 10
to Consolidated Financial Statements.





                                       33
<PAGE>   34
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This 10-K Report 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 the Company's expectations, hopes,
beliefs, intentions or strategies regarding the future.  All statements other
than statements of historical facts included in this 10-K Report, including
without limitation, statements under "Business," "Properties," "Legal
Proceedings and Environmental Issues" and "Management's Discussion and Analysis
of Financial Condition and Results of Operations" regarding reserves and their
values, planned capital expenditures, increases in oil and natural gas
production, trends or expectations concerning oil and gas prices, the number
and prospective nature of anticipated wells to be drilled in 1997 and
thereafter, development potential, infill potential, drillsite potential,
exploitation and exploration prospects and leads, drilling prospects,
consolidation opportunities and the Company's financial position, business
strategy and other plans and objectives for future operations, potential
liabilities or the expected absence thereof, the potential outcome of
environmental matters, litigation or other proceedings, are forward-looking
statements.  All forward-looking statements included or incorporated by
reference in this 10-K Report are based on information available to the Company
on the date hereof, and the Company assumes no obligation to update such
forward-looking statements.  Although the Company believes that the assumptions
and expectations reflected in such forward-looking statements are reasonable,
it can give no assurance that such expectations will prove to have been correct
or that the Company will take any actions that may presently be planned.

There are numerous uncertainties inherent in estimating quantities of proved
oil and natural gas reserves and projecting future rates of production and
timing of development expenditures, including many factors beyond the control
of the Company.  See Item 2.  "Properties--Oil and Gas Reserves."

Many factors may affect the Company's expectations and plans.  Capital
expenditure and financing plans may change in connection with the success of
drilling activities, the general availability of capital, interest rates, and
cash flow available from operations.  Cash flow available from operations may
change depending on costs of materials and services, regulatory burdens and
commodity prices. Oil and natural gas prices are volatile, and there are
several potentially significant adverse effects to the Company which can result
if product prices decline materially.  First, lower product prices will
adversely impact the Company's cash flow and could cause the Company to (i)
curtail its capital program, (ii) borrow additional amounts under its revolving
credit agreement, or (iii) issue additional debt or equity securities.  Second,
lower product prices could cause the borrowing base under the Company's bank
credit agreement to be reduced and certain covenant tests to be adversely
affected.  Third, under rules promulgated by the Securities and Exchange
Commission, companies that follow the full cost accounting method are required
to make quarterly "ceiling test" calculations.  Lower product prices adversely
impact the ceiling calculation.  Should the Company realize sustained lower
product prices, it could be required to write down its oil and gas properties,
resulting in a non-cash charge against earnings.





                                       34
<PAGE>   35
Certain additional important factors that could cause actual results to differ
materially from the Company's forward looking statements are disclosed under
"Business," "Properties," other portions of "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and elsewhere in
this 10-K Report and in the Company's 8-K Report filed February 26, 1997.  All
subsequent written or oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by the factors mentioned above.





                                       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 natural 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
natural 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 charge.  A charge made by the operator of a well for the account of all
working interests, the payment of which constitutes reimbursement for the
operator's administrative costs attributable to operating the well.

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 proved undeveloped reserves.

Dry hole.  A well found to be incapable of producing either oil or natural gas
in sufficient quantities to justify completion as an oil or gas well.

Estimated future net revenues.  Revenues from production of oil and natural
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.





                                       36
<PAGE>   37
Farmout.  An assignment of an interest in a drilling location and related
acreage, typically conditional upon the drilling of a well on that drilling
location.

Finding Cost.  The capital costs associated with finding and developing oil and
natural 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 natural gas contract, located in
southern Louisiana.

Horizontal drilling.  Horizontal drilling involves deviating the angle of a
wellbore approximately 90 degrees from vertical to near horizontal in the
formation of interest. Horizontal drilling permits the wellbore to contact and
intersect a larger portion of the producing horizon than is permitted by
conventional vertical drilling techniques and can result in increased
production rates and greater ultimate recovery of hydrocarbons.

Hydraulic fracturing.  A mechanical technique used to enhance productivity and
ultimate reserve recovery. Fluids and a proppant are injected into a particular
reservoir at rates and pressure sufficient to create a series of fractures or
cracks in that reservoir.

Increased density, or infill, drilling.  Somewhat similar to development
drilling, increased density drilling involves wells drilled within the proved
area of an oil or gas reservoir to a zone known to be productive. However,
infill drilling generally involves an increase in well density based on
engineering and geological studies which demonstrate that the existing well
density does not adequately drain the reservoir.

Lead.  An area with respect to which the Company has very preliminary
information warranting further geoscientific investigation and analysis with
the hope that one or more prospects may be developed.

Lease operating expense.  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.

MBtu.  One thousand Btus.

Mcf.  One thousand cubic feet of natural gas.

MMBbl.  One million barrels of crude oil or other liquid hydrocarbons.

MMBoe.  One million barrels of oil equivalent.





                                       37
<PAGE>   38
MMBtu.  One million Btus.

MMcf.  One million cubic feet of natural gas.

Multi-pay horizons.  A well bore with more than one zone that may potentially
produce oil and/or natural gas.

Net acres or net wells.  The sum of the working interests owned in gross acres
or gross wells.

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 by a factor of ten percent per annum
and with no price or cost escalation or de-escalation in accordance with
guidelines promulgated by the Commission.

Productive well.  A well that is producing or that is capable of producing oil
or natural gas.

Prospect.  An area with respect to which the Company has geologic and possibly
geophysical information and analysis indicating the possible presence of
producible hydrocarbons at one or more reasonably focused locations.  The term
prospect refers to many types of areas with a wide range of completeness of
concept, information and analysis but, in any event, is based on more complete
information than a lead.

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, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

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 for recompletion.

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.

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
natural gas property entitling the owner to a share of oil and natural gas
production free of costs of drilling, completion and production.

Tcf.  One trillion cubic feet of natural gas.





                                       38
<PAGE>   39
3-D seismic projects.  3-D seismic projects involve the use of seismic
reflections to assist in mapping in three dimensions 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 acreage.  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 natural gas regardless of whether such acreage contains proved
reserves.

Waterflood.  A waterflood is the injection of water into a reservoir to (i)
fill pores vacated by produced fluids or (ii) push hydrocarbons from the
injector well to another wellbore from which reserves can be produced.
Waterfloods are intended to maintain reservoir pressure, assist production and
enhance reservoir recovery rates.

Wattenberg.  The geographic region in the D-J Basin located approximately 35
miles north 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.





                                       39
<PAGE>   40
Item 8.          FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


CONSOLIDATED BALANCE SHEETS
HS Resources, Inc.

<TABLE>
<CAPTION>
                                                                                         December 31,
                                                                        1996                 1995
                                                                     -------------      -------------
<S>                                                                  <C>                <C>          
ASSETS
Current Assets
   Cash and cash equivalents                                         $   8,764,756      $     116,581
   Margin deposits                                                         575,712                 --
   Accounts receivable
          Oil and gas sales                                             40,387,602          6,344,672
          Trade                                                          2,255,359          1,300,244
          Other                                                          5,625,980          2,461,966
   Lease and well equipment inventory, at cost                           1,724,944            709,613
   Prepaid expenses and other                                              513,471            152,569
                                                                     -------------      -------------
          Total current assets                                          59,847,824         11,085,645
                                                                     -------------      -------------
OIL AND GAS PROPERTIES, AT COST, USING THE FULL COST METHOD
   Undeveloped acreage                                                  54,709,553         26,778,702
   Costs subject to depreciation, depletion and amortization           727,411,293        341,382,375
   Less accumulated depreciation, depletion and amortization          (129,940,868)       (89,350,067)
                                                                     -------------      -------------
          Net oil and gas properties                                   652,179,978        278,811,010
                                                                     -------------      -------------
GAS GATHERING AND TRANSPORTATION FACILITIES,
   at cost, net of accumulated depreciation of $1,032,224 and
   $739,010 at December 31, 1996 and 1995, respectively                  4,674,075          4,913,692
                                                                     -------------      -------------
OTHER ASSETS
   Deferred charges and other, net                                       8,954,781          3,652,769
   Office and transportation equipment and other property,
          net of accumulated depreciation of $3,401,739 and
          $2,457,070 at December 31, 1996 and 1995, respectively         4,708,436          3,626,149
   Investment in Oil and Gas Limited Partnership                           920,285                 --
                                                                     -------------      -------------
          Total other assets                                            14,583,502          7,278,918
                                                                     -------------      -------------
TOTAL ASSETS                                                         $ 731,285,379      $ 302,089,265
                                                                     =============      =============
</TABLE>


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


                                       40
<PAGE>   41
CONSOLIDATED BALANCE SHEETS
HS Resources, Inc.
<TABLE>
<CAPTION>
                                                                             December 31,
                                                                  1996               1995
                                                             -------------    -------------
<S>                                                          <C>              <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
   Accounts payable
       Trade                                                 $   9,124,831    $   4,638,286
       Revenue                                                   8,134,201        2,091,073
       Gas purchases                                            13,878,187             --
   Accrued expenses
       Ad valorem and production taxes                           7,516,095        4,386,969
       Interest                                                  3,179,627        1,494,667
       Other                                                     4,235,410        2,159,324
   Short-term note                                                    --         12,400,000
   Current portion of long-term debt                                30,000           30,000
                                                             -------------    -------------
       Total current liabilities                                46,098,351       27,200,319
                                                             -------------    -------------
ACCRUED AD VALOREM TAXES                                         9,005,922        6,574,405
                                                             -------------    -------------
LONG-TERM OIL AND GAS PRODUCTION NOTE PAYABLE                      734,696             --
                                                             -------------    -------------
LONG-TERM BANK DEBT, NET OF CURRENT PORTION                    174,000,000       51,000,000
                                                             -------------    -------------
9 7/8% SENIOR SUBORDINATED NOTES,
   due 2003, net of unamortized discount of
   $404,625 and $463,125 at December 31, 1996
   and 1995, respectively                                       74,595,375       74,536,875
                                                             -------------    -------------
9 1/4% SENIOR SUBORDINATED NOTES,
   due 2006, net of unamortized discount of
   $767,287 at December 31, 1996                               149,232,713             --
                                                             -------------    -------------
DEFERRED INCOME TAXES                                           84,828,612       23,603,540
                                                             -------------    -------------
COMMITMENTS AND CONTINGENCIES (NOTE 10)
                                                             -------------    -------------
MINORITY INTEREST IN OIL AND GAS LIMITED PARTNERSHIP                66,149             --
                                                             -------------    -------------
STOCKHOLDERS' EQUITY
   Preferred stock (Note 7)                                           --               --
   Common stock, $.001 par value, 30,000,000 shares
       authorized; 17,127,861 and 10,948,680 shares issued
       and outstanding at December 31, 1996 and 1995,
       respectively                                                 17,128           10,949
   Additional paid-in capital                                  163,114,868       97,717,908
   Retained earnings                                            31,433,399       22,484,572
   Deferred compensation                                          (171,300)            --
   Treasury stock, at cost, 121,952 and 75,077 shares at
       December 31, 1996 and 1995, respectively                 (1,670,534)      (1,039,303)
                                                             -------------    -------------
       Total stockholders' equity                              192,723,561      119,174,126
                                                             -------------    -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                   $ 731,285,379    $ 302,089,265
                                                             =============    =============
</TABLE>

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



                                       41
<PAGE>   42
CONSOLIDATED STATEMENTS OF OPERATIONS
HS Resources, Inc.

<TABLE>
<CAPTION>
                                                                     For the Years Ended December 31,
                                                          1996              1995            1994
                                                       ------------     ------------     ------------
<S>                                                    <C>              <C>              <C>         
REVENUES
   Oil and natural gas sales                           $107,280,873     $ 53,394,029     $ 58,827,315
   Trading and transportation                            46,372,707               --               --
   Other gas revenues                                     2,720,423        1,782,349        1,334,755
   Interest income and other                                582,067          163,510          239,351
                                                       ------------     ------------     ------------
       Total revenues                                   156,956,070       55,339,888       60,401,421
                                                       ------------     ------------     ------------
EXPENSES
   Production taxes                                       8,195,389        4,050,483        5,133,851
   Lease operating                                       17,691,502        9,935,809        8,310,409
   Cost of trading and transportation                    45,699,154               --               --
   Depreciation, depletion and amortization              42,334,882       26,608,885       25,079,222
   General and administrative                             5,642,393        4,075,581        4,228,472
   Interest                                              22,935,840       10,218,555        7,538,611
                                                       ------------     ------------     ------------
       Total expenses                                   142,499,160       54,889,313       50,290,565
                                                       ------------     ------------     ------------
INCOME BEFORE PROVISION FOR INCOME TAXES                 14,456,910          450,575       10,110,856
PROVISION FOR INCOME TAXES                                5,508,083          176,419        3,852,236
                                                       ------------     ------------     ------------
NET INCOME                                             $  8,948,827     $    274,156     $  6,258,620
                                                       ------------     ------------     ------------
EARNINGS PER SHARE
   Earnings per common and common equivalent share     $       0.61     $       0.02     $       0.53
                                                       ------------     ------------     ------------
   Earnings per common and common equivalent share
       assuming full dilution                          $       0.61     $       0.02     $       0.53
                                                       ------------     ------------     ------------
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING
   Weighted average number of common and common
       equivalent shares                                 14,568,000       11,440,000       11,713,000
                                                       ------------     ------------     ------------
   Weighted average number of common and common
       equivalent shares assuming full dilution          14,769,000       11,450,000       11,724,000
                                                       ------------     ------------     ------------
</TABLE>


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


                                       42
<PAGE>   43
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
HS Resources, Inc.

<TABLE>
<CAPTION>
                                                                               For the Years Ended December 31, 1996, 1995, and 1994

                                           Common Stock        Additional                                       Treasury Stock
                                     ----------------------    Paid-In         Retained         Deferred    -----------------------
                                       Shares       Amount     Capital         Earnings       Compensation    Shares       Amount
                                     ----------  ----------  --------------   -------------  -------------  ---------   -----------
<S>                                  <C>         <C>          <C>             <C>             <C>             <C>       <C>
Balance, December 31, 1993           10,948,680  $  10,949    $97,713,613     $15,951,796     $     --      (28,913)     $ (377,591)
  Common stock options exercised,                                                                      
    including income tax benefit             --         --          5,945              --           --        1,500          19,590
  Purchase of treasury stock                 --         --             --              --           --      (13,500)       (233,962)
  Exercise of options by issuance                                                                      
    of treasury stock, including                                                                       
    income tax benefit                       --         --            798              --           --          600           7,854
  Net income                                 --         --             --       6,258,620           --          --              --
                                     ----------  ---------  -------------   -------------  -----------    ---------   -------------
Balance, December 31, 1994           10,948,680     10,949     97,720,356      22,210,416           --      (40,313)       (584,109)
  Purchase of treasury stock                 --         --             --              --           --      (63,700)       (846,625)
  Transfer of treasury stock                                                                           
    to 401(k) Plan                           --         --          3,328              --           --       26,536         358,287
  Exercise of options by issuance                                                                      
    of treasury stock, including                                                                       
    income tax benefit                       --         --         (5,776)             --           --        2,400          33,144
  Net income                                 --         --             --         274,156           --           --              --
                                     ----------  ---------  -------------   -------------  -----------    ---------    ------------
Balance, December 31, 1995           10,948,680     10,949     97,717,908      22,484,572           --      (75,077)     (1,039,303)
  Purchase of treasury stock                 --         --             --              --           --     (113,817)     (1,460,490)
  Transfer of treasury stock to                                                                        
    401(k) Plan                              --         --        (53,961)             --           --       20,025         246,708
  Issuance of common stock for                                                                         
    Tide West acquisition             6,169,181      6,169     65,231,025              --           --          --               --
  Exercise of options by issuance                                                                      
    of treasury stock, including                                                                       
    income tax benefit                       --         --         48,606              --           --      46,917          582,551
  Issuance of restricted stock           10,000         10        171,290              --     (171,300)         --               --
  Net income                                 --         --             --       8,948,827           --          --               --
                                     ----------  ---------  -------------   -------------  -----------   ---------   --------------
Balance, December 31, 1996           17,127,861  $  17,128  $ 163,114,868   $  31,433,399  $  (171,300)   (121,952)  $   (1,670,534)
                                     ==========  =========  =============   =============  ===========   =========   ==============
</TABLE>


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


                                       43
<PAGE>   44
CONSOLIDATED STATEMENTS OF CASH FLOWS
HS Resources, Inc.

<TABLE>
<CAPTION>
                                                                                  For the Years Ended December 31,
                                                                         1996            1995            1994
                                                                     -------------   -------------   -------------
<S>                                                                  <C>             <C>             <C>          
CASH FLOWS FROM OPERATING ACTIVITIES
   Net income                                                        $   8,948,827   $     274,156   $   6,258,620
   Adjustments to reconcile net income to net cash
          provided by operating activities
       Depreciation, depletion and amortization                         42,334,882      26,608,885      25,079,222
       Amortization of deferred charges and debenture issue costs        1,082,988         615,368       1,131,548
       Transfer of treasury stock to 401(k) Plan                           192,747         378,141              --
       Gain on sale of fixed assets                                       (118,649)        (52,545)        (65,386)
       Deferred income tax provision                                     5,135,328         171,482       3,843,198
   Changes in assets and liabilities net of effect from purchase
          of Tide West
       Decrease (increase) in accounts and notes receivable            (21,784,122)      1,113,301      (1,465,832)
       Increase in accounts payable and accrued expenses                16,157,951       2,596,066       1,252,290
       Increase (decrease) in unearned income, net                              --      (1,206,154)        500,488
       Other                                                               301,197         680,242          19,330
                                                                     -------------   -------------   -------------
   Net cash provided by operating activities                            52,251,149      31,178,942      36,553,478
                                                                     -------------   -------------   -------------
CASH FLOWS FROM INVESTING ACTIVITIES
   Exploration, development and leasehold costs                        (50,626,521)    (62,094,658)    (81,900,942)
   Purchase of unproved and proved properties                         (129,982,687)             --              --
   Cash payment for the purchase of Tide West, net of cash acquired    (85,125,084)             --              --
   Gas gathering and transportation facilities additions                   (53,597)       (649,469)       (706,611)
   Other property additions                                             (1,056,547)       (141,881)     (3,605,825)
   Proceeds from the sale of properties                                  9,678,851              --              --
   Proceeds from the sale of fixed assets and other property               157,043         419,116              --
   Increase (decrease) in property related payables                          8,130      (2,817,069)        119,507
   Other                                                                        --              --         300,868
                                                                     -------------   -------------   -------------
   Net cash used in investing activities                              (257,000,412)    (65,283,961)    (85,793,003)
                                                                     -------------   -------------   -------------
CASH FLOWS FROM FINANCING ACTIVITIES
   Proceeds from debt                                                  536,316,596      48,400,000      29,000,000
   Repayments of debt                                                 (315,258,900)    (14,000,000)        (22,570)
   Tide West acquisition costs                                          (2,623,792)             --              --
   Debt issuance costs                                                  (4,328,056)             --              --
   Exercise of options                                                     631,157          10,842          34,187
   Purchase of treasury stock                                           (1,460,490)       (846,625)       (233,962)
   Minority interest                                                       120,923              --              --
                                                                     -------------   -------------   -------------
   Net cash provided by financing activities                           213,397,438      33,564,217      28,777,655
                                                                     -------------   -------------   -------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                     8,648,175        (540,802)    (20,461,870)
   Cash and cash equivalents, beginning of year                            116,581         657,383      21,119,253
                                                                     -------------   -------------   -------------
   Cash and cash equivalents, end of year                            $   8,764,756   $     116,581   $     657,383
                                                                     -------------   -------------   -------------
SUPPLEMENTAL CASH FLOW DISCLOSURE
   Interest paid, net of capitalized interest                        $  20,078,634   $   9,072,167   $   6,507,063
   Cash paid for income taxes                                        $     418,296   $          --   $          --
                                                                     -------------   -------------   -------------
</TABLE>


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


                                       44
<PAGE>   45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
HS Resources, Inc.


NOTE 1 - THE COMPANY

HS Resources, Inc., a Delaware corporation, (the "Company") was organized in
January 1987.  The Company, directly or through subsidiaries, acquires,
develops, and exploits oil and gas properties. The Company's primary properties
are located in the D-J Basin of the Rocky Mountains, the Anadarko and Arkoma
Basins of the Mid-Continent and the on-shore Gulf Coast area.  The Company,
through its gas marketing division and its wholly owned subsidiary, TWTT,
actively markets a portion of its own natural gas production, markets natural
gas to third parties and supplies natural gas to end-users.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

OIL AND GAS PROPERTIES   The Company accounts for its oil and gas activities
using the full cost method of accounting.  Under the full cost method of
accounting, all costs of exploration for and development of oil and gas
reserves, including costs of surrendered and abandoned leaseholds, delay lease
rentals, dry hole costs, geological and geophysical costs and direct overhead
related to exploration and development activities are capitalized.  Payroll and
other internal costs capitalized include salaries and related fringe benefits
paid to employees directly engaged in the acquisition, exploration, and
development of oil and gas properties, as well as all other directly
identifiable internal costs associated with these activities, such as rentals,
utilities, and insurance.  Payroll and other internal costs associated with
production, operation, and general corporate activities are expensed in the
period incurred.  Future development, site restoration, dismantlement, and
abandonment costs, net of salvage values, are estimated on a property-
by-property basis based on prevailing prices and are amortized to expense,
along with the capitalized costs discussed above, using the unit-of-production
method based upon production and estimates of proved reserve quantities.
Accumulated depreciation, depletion, and amortization is recorded on the
balance sheets as a reduction to property, plant, and equipment costs.  No
gains or losses are recognized upon the sale or other disposition of oil and
gas properties unless a significant portion of the reserves are sold.

Capitalized costs associated with undeveloped properties are excluded from
amortization until a determination has been made as to the existence of proved
reserves or an impairment has occurred.  At December 31, 1996 and 1995, the
Company excluded costs aggregating $54,709,553 and $26,778,702, respectively,
from capitalized costs being amortized.  Of the costs excluded at December 31,
1996, $34,203,488 were incurred in 1996, $5,879,125 in 1995, $12,371,811 in
1994, $1,957,038 in 1993, and $298,091 in 1990.  The Company capitalizes
interest related to its undeveloped properties.  During 1996, 1995, and 1994,
the Company capitalized $3,259,053, $2,001,436, and $1,852,633 of interest,
respectively.

Net capitalized costs of oil and gas properties less related deferred income
taxes may not exceed an amount equal to the present value discounted at 10% of
estimated future net revenue from proved oil and gas reserves plus the lower of
costs or estimated fair market value of unproved properties (the "full cost
ceiling").  Should capitalized costs exceed the full cost ceiling, an
impairment would be provided.  The full cost ceiling may be particularly
sensitive to changes in the near term in pricing





                                       45
<PAGE>   46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


and production rates.  The above limitation is applied on a quarterly basis
using current prices at the end of the quarter.

INCOME TAXES   The Company follows the liability method of accounting for
income taxes as prescribed by SFAS 109.  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 bases 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.

FINANCIAL INSTRUMENTS  The Company engages in price and location risk
management activities for both hedging and trading purposes.  Activities for
hedging purposes are entered into by the Company to manage its exposure to
price and location risks in the marketing of its oil and natural gas production
and, in the case of its marketing activities, third party natural gas.  Gains
and losses on hedging positions are deferred and recognized in the period the
underlying physical transactions occur in "oil and natural gas sales" and
"trading and transportation revenues" (for third party natural gas).
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 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 the Company's position
in an orderly manner over a reasonable period of time under present market
conditions.

EARNINGS PER SHARE  Earnings per share is computed based on the weighted
average number of common shares actually outstanding plus the shares that would
be outstanding assuming exercise of dilutive stock options and warrants, which
are considered to be common stock equivalents.  The number of shares that would
be issued from the assumed exercise of stock options and warrants has been
reduced by the number of shares that could have been repurchased from the
proceeds at the assumed fair market value price of the Company's stock.

ACCRUED AD VALOREM TAXES  The Company considers ad valorem taxes payable within
one year to be current.  Other ad valorem taxes are classified as non-current
because the required payment dates are not within one year.

DEFERRED CHARGES  Legal and accounting fees, printing costs and other expenses
associated with the issuance of the Company's debt have been capitalized and
are being amortized over the remaining term of the debt.





                                       46
<PAGE>   47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


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.

GAS IMBALANCES  Gas imbalances are accounted for under the sales method whereby
revenues are recognized based on actual production sold.  At December 31, 1996,
the Company's gas balancing position was approximately 615,000 Mcf
overproduced.

USE OF ESTIMATES  The preparation of financial statements in conformity with
generally accepted accounting principles 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.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET EFFECTIVE  Effective January 1,
1997, the Company will adopt the provisions of Statement of Position ("SOP")
No. 96-1.  Environmental Remediation Liabilities.  This Statement provides
authoritative guidance for recognition, measurement, display and disclosure of
environmental remediation liabilities in financial statements.  The Company has
recorded environmental remediation liabilities of $1 million at December 31,
1996.  SOP 96-1 is not expected to have a material impact on the Company's
financial position or results of operations upon adoption.

NOTE 3 - BASIN ACQUISITIONS AND TIDE WEST MERGER

In March and June 1996, the Company acquired all of the Denver-Julesburg
("D-J") Basin oil and gas properties of Basin Exploration, Inc. ("Basin") (the
"Acquisitions") for aggregate cash consideration of $125.5 million.  The
Acquisitions included a total of 850 gross wells with approximately 35 MMBoe of
net proved reserves at December 31, 1995 and approximately 5,500 Boe of net
daily production.  Subsequent to the March acquisition, the Company sold $23.5
million of such assets to a limited liability company (the "Third Party") under
an arrangement whereby the Third Party assumed all of the Company's liability
for (and the Company was fully released from) $23.5 million of the Company's
debt.  On November 1, 1996, the Company exercised its option to repurchase the
properties and assumed the debt of the Third Party.  The assumed debt has been
reflected as long-term bank debt in the December 31, 1996 financial statements.
These Acquisitions were accounted for using the purchase method of accounting
and the Company began consolidating the results of operations as of March and
June, 1996.





                                       47
<PAGE>   48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


On June 17, 1996, the Company completed the merger of Tide West Oil Company
("Tide West") into a wholly owned subsidiary of the Company (the "Merger").
Pursuant to the Merger, Tide West shareholders received 0.6295 shares (totaling
6,169,181 shares in aggregate) of the Company's common stock and $8.704 cash
for each outstanding share of Tide West common stock for an aggregate
consideration of $187.7 million. The Merger added 1,259 gross wells,
approximately 39.1 MMBoe of net proved reserves (at December 31, 1995) and
9,985 Boe of net daily production to the Company.  Tide West was an independent
oil and gas company with principal operations in portions of the Anadarko and
Arkoma geologic basins located within Oklahoma and Texas, as well as additional
operations located in Southern Oklahoma, Texas and New Mexico.  The Company
accounted for the Merger using the purchase method of accounting and began
consolidating Tide West's results as of June 17, 1996.

NOTE 4 - PRO FORMA STATEMENTS

The following table sets forth the condensed unaudited pro forma operating
results of the Company for the twelve months ended December 31, 1996 and 1995.
The condensed pro forma operating results assume that both the Acquisitions and
the Merger (as discussed in Note 3) had occurred on January 1, 1995.  The
condensed pro forma results are not necessarily indicative of the results of
operations had the Acquisitions and the Merger been consummated on January 1,
1995, and may not necessarily be indicative of future performance.

<TABLE>
<CAPTION>
                                                                  Twelve Months Ended December 31,
                                                                  -------------------------------- 
                                                                   1996                      1995
                                                                           (Unaudited)
<S>                                                                <C>             <C>
Revenues                                                           $ 236,450,687   $ 203,407,171
Net income (loss)                                                  $  13,247,335   $  (2,446,727)
Net income (loss) per common and common equivalent share           $        0.75   $       (0.14)
Weighted average common and common equivalent shares outstanding      17,625,000      17,611,312
</TABLE>


NOTE 5 - RISK MANAGEMENT

The Company uses financial instruments to reduce its exposure to market
fluctuations in the price and transportation cost of oil and natural gas.  The
Company's general strategy is to hedge price and location risk with swap,
collar, floor and ceiling arrangements.  When utilizing such instruments, the
Company strives to hedge its production back to the wellhead, to minimize basis
risk.  In addition to hedging activities, the Company is engaged in using the
financial markets to capture trading margins.  The Company has established
policies with respect to open positions which limit its exposure to market risk
and requires reporting to management of the potential financial exposure on a
daily basis resulting from both hedging and trading activities.





                                       48
<PAGE>   49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


Hedging Activities  Activities for hedging purposes are entered into by the
Company to manage its exposure to price and location risks in the marketing of
its oil and natural gas production and, in the case of its marketing
activities, third party natural gas.

The Company has entered into the following forward sales and swap arrangements
with respect to its natural gas production for the quarters indicated below
(total average daily natural gas production for the quarter ended December 31,
1996 was 118,930 Mcf/day):

<TABLE>
<CAPTION>
                                 Average Daily Volume             Average Price
Period Hedged                           (MCFD)                   for the Period
<C>                                     <C>                            <C>  
1st Quarter 1997                        36,000                         $1.98
2nd Quarter 1997                        31,720                         $1.99
3rd Quarter 1997                        10,000                         $1.99
October 1-31, 1997                      10,000                         $1.99
</TABLE>

The Company has hedged through collar arrangements approximately two-thirds of
its oil production at a floor price of $20.00 and a ceiling price of $24.00 per
Bbl through the first quarter of 1997.  Additionally, with respect to the
hedging of third party natural gas, the Company has hedged 8.6 Bcf through
December 1997 with offsetting physical positions at settlement prices which are
based upon NYMEX future prices or other published indices.

Trading Activities  The Company engages 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 variable
price for the commodity, swap or other contractual arrangement.  Company policy
requires that financial instrument purchase and sales contracts be balanced in
terms of contract volumes and the timing of performance and delivery
obligations.  As of December 31, 1996, all open positions were balanced with an
offsetting position.

The Company accounts for these activities using the mark-to-market method of
accounting.  During 1996, gains of $462,000 were recognized in connection with
these 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 investment grade financial institutions.  Accordingly, the
Company does not anticipate any material impact to its financial position or
results of operations as a result of nonperformance by the third parties on
financial instruments related to hedging activities or trading activities.





                                       49
<PAGE>   50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


NOTE 6 - LONG-TERM DEBT

Debt at December 31, 1996 and 1995 consists of the following:

<TABLE>
<CAPTION>
                                                        1996              1995
                                                   -------------    -------------
<S>                                                <C>              <C>          
LONG-TERM BANK AND OTHER DEBT
Bank debt                                          $ 174,000,000    $  51,000,000
Other debt                                               764,696       12,430,000
                                                   -------------    -------------
                                                     174,764,696       63,430,000
Less-Current portion                                     (30,000)     (12,430,000)
                                                   -------------    -------------
Long-term bank debt and other debt,
      net of current portion                         174,734,696       51,000,000
                                                   =============    =============
9 7/8% SENIOR SUBORDINATED NOTES,
      due 2003, net of unamortized discount of
      $404,625 and $463,125 at December 31, 1996
      and 1995, respectively                       $  74,595,375    $  74,536,875
                                                   =============    =============
9 1/4% SENIOR SUBORDINATED NOTES,
      due 2006, net of unamortized
      discount of $767,287 at December 31, 1996    $ 149,232,713    $        --
                                                   =============    =============
</TABLE>




BANK DEBT  On June 7, 1996, the Company entered into a $180 million revolving
and senior term credit facility with The Chase Manhattan Bank, N.A., as Agent.
On June 14, 1996, the Company amended the terms of its senior credit facility
to increase the maximum credit amount to $350 million.  Under the terms of the
credit facility, no principal payments are required until June 14, 2001,
assuming the Company maintains a borrowing base sufficient to support the
outstanding loan balance.  The borrowing base is based on the underlying value
of the Company's oil and gas properties.  This facility bears interest at a
base rate plus 0% to 0.5% or LIBOR plus 0.75% to 1.5%.  As part of the
amendment to the credit facility, Tide West's senior bank debt in the amount of
$39.5 million was fully repaid.  Upon consummation of the $150 million senior
subordinated notes offering (discussed below) and the application of the net
proceeds therefrom, the borrowing base was amended to $275 million.

During the second quarter of 1995, the Company entered into an interest rate
exchange agreement with a financial institution to hedge its interest rate on
$40 million of the Company's borrowings at 7.76% through May 2002.  Under the
terms of the agreement, the difference between the Company's fixed rate of
7.76% and the three-month LIBOR rate plus 1.125% is received or paid by the
Company.  The Company, through the Merger with Tide West, was assigned interest
rate exchange agreements with two financial institutions to hedge its interest
rate on a total of $40 million of the Company's borrowings at rates ranging
from 6.16% to 7.32% for 1997 through 1999.  Under the terms of the agreement,
the difference between the Company's fixed rate and the three-month LIBOR rate
is received or paid by the Company.





                                       50
<PAGE>   51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


SENIOR SUBORDINATED NOTES  In November 1993, the Company issued $75 million of
its 9 7/8% senior subordinated notes due in 2003.  The notes were priced to
yield 10% and the Company received net proceeds of $71.9 million after
underwriting commissions and offering costs.  The proceeds of the notes were
used to repay all outstanding indebtedness under the Company's bank credit
facility and for working capital purposes.  The notes pay interest
semi-annually on June 1 and December 1.  Under the terms of the notes, there
are no sinking fund requirements and the Company is limited as to certain
additional indebtedness beyond its existing credit facility if certain
financial covenants are not maintained.

In November 1996, the Company issued $150 million of its 9  1/4% senior
subordinated notes due in 2006.  The notes pay interest semi-annually on May 15
and November 15.  The notes were priced to yield 9.33% and the Company received
net proceeds of $144.9 million after underwriting commissions and offering
costs.  The proceeds of the notes were used to replace a portion of the
outstanding indebtedness under the Company's bank debt with fixed rate term
debt.

OTHER DEBT  In December 1995, the Company signed a $12.4 million non-interest
bearing short-term note for the purchase of certain oil and gas properties.
This note was repaid subsequent to year-end with proceeds from an additional
draw on the Company's bank debt.

CARRYING VALUE  At December 31, 1996 and 1995, the carrying amount of the
Company's 9 7/8% senior subordinated notes was $74.6 million and $74.5 million
and the estimated fair value was $78.3 million and $73.5 million, respectively.
At December 31, 1996 the carrying amount of the 9  1/4% senior subordinated
notes of $149.2 million approximated the fair value.  The fair value is
estimated based on the quoted market prices for the same or similar issues, or
on the current rates offered to the Company for debt of the same remaining
maturity.

Based on borrowing rates available for bank loans with similar collateral, the
fair values of the borrowings under the bank debt and other debt at December
31, 1996, are estimated to be their carrying value of $174 million and $.8
million, respectively.

NOTE 7 - STOCKHOLDERS' EQUITY

SERIES A CONVERTIBLE PARTICIPATING PREFERRED STOCK  The Company has authorized
15,000,000 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 and a liquidation preference of $1.00 per share.

SERIES A JUNIOR PREFERRED STOCK  In February 1996, the Company 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 the Company and Harris Trust Company of
California, as Rights Agent (the "Rights Agreement").  The Rights Agreement was
designed to protect the Company's shareholders in the event of takeover action
that would deny them the full value of their investment (the "Rights Plan").





                                       51
<PAGE>   52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


Terms of the Rights Plan provide for a dividend distribution of one right for
each share of HS Resources, Inc. 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 the Company's common stock.  The
Rights will become exercisable only in the event, with certain exceptions, an
acquiring party accumulates 15% or more of HS Resources, Inc.'s voting stock,
or if a party announces an offer to acquire 30% or more of HS Resources' voting
stock.  No separate rights certificates will be issued until after these
thresholds are met.  The Rights will expire on March 14, 2006.

Under the Rights Plan, if any person or group becomes the beneficial owner of
15 percent or more of the Company's 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 HS Resources stock or shares in an
"acquiring entity" at a 50 percent discount of the then current market value.
HS Resources 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 percent position
in the Company's voting stock.

WARRANTS  The Company had 746,262 warrants outstanding and exercisable at $8.98
per share as of December 31, 1996, 1995 and 1994.

RESTRICTED STOCK  In connection with the issuance of 10,000 shares of
restricted stock on December 2, 1996, the Company recorded $171,300 of deferred
compensation for the difference between the deemed fair value for accounting
purposes and the stock price as determined by the Company at the date of grant.
This amount is presented as a reduction of stockholders' equity and will be
amortized over the three year vesting period of the related stock.

NOTE 8 - PROVISION FOR INCOME TAXES

The provision for income taxes consists of the following:

<TABLE>
<CAPTION>
                    1996         1995         1994
                ----------   ----------   ----------
<S>             <C>          <C>          <C>     
Current:
      Federal   $  250,000   $     --     $     --
      State         50,000         --           --
                ----------   ----------   ----------
                   300,000         --           --
                ----------   ----------   ----------
Deferred:
      Federal    4,647,633      157,434    3,437,691
      State        560,450       18,985      414,545
                ----------   ----------   ----------
                 5,208,083      176,419    3,852,236
                ----------   -----------  -----------
                $5,508,083   $  176,419   $3,852,236
                ==========   ==========   ==========
</TABLE>

                                       52
<PAGE>   53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


The deferred income tax expense during the years ended December 31, 1996, 1995
and 1994 results from the following:

<TABLE>
<CAPTION>
                                              1996          1995          1994
                                           -----------   -----------   -----------
<S>                                        <C>           <C>           <C>      
TYPE OF TEMPORARY DIFFERENCE
Alternative minimum tax                    $  (250,000)  $        --   $        --
Depletion, depreciation and amortization    (2,797,220)       32,871       636,192
Intangible drilling costs                    1,212,361     4,873,778     4,601,741
Sales of properties                          1,424,878    (8,268,363)           --
Operating loss carryforwards                 5,618,064     3,533,383    (1,385,697)
                                           -----------   -----------   -----------
Deferred tax provision                     $ 5,208,083   $   171,669   $ 3,852,236
                                           ===========   ===========   ===========
</TABLE>




The components of the net deferred tax liability as of December 31, 1996 and
1995 are as follows:
<TABLE>
<CAPTION>
                                                 1996          1995
                                           ------------    ------------
<S>                                        <C>             <C>         
DEFERRED TAX LIABILITIES
Depreciation and basis difference          $ 96,901,658    $ 39,312,159
                                           ------------    ------------
Deferred tax liability                       96,901,658      39,312,159
DEFERRED TAX ASSETS
Tax effect of regular net operating loss      8,770,756      13,092,314
Alternative minimum tax credit                  982,000            --
Statutory depletion carryforwards             2,320,290       2,320,290
Investment tax credit carryforwards             168,772         323,776
All other                                          --           296,015
                                           ------------    ------------
                                             12,241,818      16,032,395
Valuation allowance                            (168,772)       (323,776)
                                           ------------    ------------
Deferred tax assets, net                     12,073,046      15,708,619
                                           ------------    ------------
Net deferred tax liability                 $ 84,828,612    $ 23,603,540
                                           ============    ============
</TABLE>

The Company recorded $58,117,144 of deferred tax liabilities and $2,027,400 of
deferred tax assets in connection with its acquisition of Tide West.

The effective tax rate during 1996, 1995 and 1994 differs from the statutory
rate of 34% principally because of the effects of state income taxes, net of
federal tax benefit.

The Company has net tax operating loss carryforwards aggregating approximately
$23 million available at December 31, 1996, to offset future taxable income.
These carryforwards, if not previously utilized, expire in 2004 through 2010.
Included in these carryforwards are approximately $3.4 million of losses
acquired in the purchase of Tide West.  The Company's ability to utilize these
losses is subject to the "ownership change" limitation.  The ownership change
rules will limit the amount of Tide West's losses that can be used to
approximately $.8 million annually.





                                       53
<PAGE>   54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


The Company has an alternative minimum tax (AMT) credit carryforward of
approximately $982,000.  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.  The Company also has a percentage depletion
carryforward of approximately $6 million which can be used to reduce taxable
income in the future and is not subject to expiration.  Finally, the Company
has investment tax credit carryforwards of approximately $169,000 which expire
from 1997 through 1999.  Due to the uncertainty that the investment tax credits
will be applied against future tax liabilities, the Company has not given
effect for the benefit of these amounts in calculating its deferred tax
liability.

NOTE 9 - EMPLOYEE BENEFIT PLANS

401(K) AND PROFIT SHARING PLANS  Effective June 30, 1989, the Company adopted
two qualified defined contribution plans, the HS Resources, Inc. Employee
Investment 401(k) Plan (the "401(k) Plan") and the HS Resources, Inc. Profit
Sharing Plan (the "Profit Sharing Plan").  Employees are eligible to
participate in both plans after one year of service.  Under the 401(k) Plan,
participants may make regular pretax contributions of up to 10% of their
compensation (up to a maximum of $9,500)  and receive matching contributions
from the Company in an amount determined by the Board of Directors.  All
contributions to the 401(k) Plan are vested 100% upon participation.  Under the
Profit Sharing Plan only the Company can make contributions.  Company
contributions are determined by the Board of Directors and are vested to
participants over five years of service.  Company contributions to both plans
are included in general and administrative expenses in the accompanying
statements of operations.

At December 31, 1996, the Company accrued approximately $450,000 for the 1996
contribution to the 401(k) Plan.  Contributions to the plans were $211,596 and
$378,141 in 1995 and 1994, respectively.

STOCK OPTION PLAN  The Company has an Employee Stock Incentive Plan (the
"Plan") whereby directors, officers, key employees, and consultants of the
Company are entitled to receive incentive stock options, non-qualified stock
options, and stock appreciation rights.  One million five hundred thousand
shares of the Company's common stock are subject to the Plan.  Additionally,
the Company may grant restricted stock pursuant to the Plan.  Options granted
pursuant to the Plan shall be exercisable for no more than ten years at no less
than fair market value (85% of fair market value in the case of non-qualified
stock options) on the date of the grant.  The Plan expires in April 1997.  The
Company currently intends to present a new equity incentive plan for approval
by the shareholders at this years annual shareholders meeting.  The Company
accounts for this plan under Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees, under which no compensation cost was
recognized during 1996 and 1995.  During 1996, 1995 and 1994, the Company
implemented SFAS No. 123, Accounting for Stock Based Compensation.  The
implementation of SFAS 123 did not result in a material impact on the Company's
net income and earnings per share.





                                       54
<PAGE>   55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


The following table summarizes activity with respect to outstanding stock
options for the years 1996, 1995 and 1994:

<TABLE>
<CAPTION>
                                                         Weighted Average
                                            Shares         Option Price
                                            -------      ----------------
<S>                                         <C>           <C> 
Outstanding at December 31, 1993
     (497,770 shares exercisable)           707,270           $10.31
     Granted                                 75,000            20.25
     Exercised                               (2,100)           13.79
     Forfeited                                 --               --
                                            -------           ------
Outstanding at December 31, 1994
     (565,070 shares exercisable)           780,170            11.25
     Granted                                 14,000            17.00
     Exercised                               (2,400)           12.00
     Forfeited                              (47,333)           19.83
                                            -------           ------
Outstanding at December 31, 1995
     (613,369 shares exercisable)           744,437            10.81
     Granted                                 94,000            12.37
     Exercised                              (46,917)           12.00
     Forfeited                              (18,000)           23.92
                                            -------           ------
Outstanding at December 31, 1996
     (626,670 shares exercisable)           773,520           $10.63
                                            =======           ======
</TABLE>

Of the 773,520 options outstanding at December 31, 1996, 470,770 options are
fully vested and have exercise prices between $6.67 and $12.00, with a weighted
average exercise price of $7.26 and a weighted average remaining contractual
life of 2.7 years.  The remaining 302,750 options have exercise prices between
$10.13 and $25, with a weighted average exercise price of  $15.87 and a
weighted average remaining contractual life of 6.43 years.  Of these options
155,900 are exercisable; their weighted average exercise price is $17.00.

The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted average
assumptions used for grants in 1996 and 1995, respectively:  risk free interest
rate of 5.8%; expected dividend yield of 0%; expected life of 6 years; expected
volatility of 67%.

NOTE 10 - COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL MATTERS  In May 1995, the Company was named by the EPA pursuant
to a RCRA 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.  The Company and





                                       55
<PAGE>   56
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


other non-operator respondents are working together with the EPA to develop
characterization studies of the site, and have caused the facility to be
permanently closed.  Based on the Company's current knowledge and its
expectation of proportionate reimbursement from other parties who utilized the
facility, the Company does not believe that its share of the reclamation costs
will have a material impact on its financial condition or results of
operations.  By agreement with other contributing parties, the Company is
currently paying approximately 50% of the costs associated with the project,
but after recovery from additional liable parties, the Company's percentage
share of overall costs may be reduced to as low as 40%.  The Company has spent
approximately $460,000 on its behalf to date on the project.  The Company's
share of total costs associated with the project, at the 50% level of
participation, are currently estimated to range from $1 to $2 million over
three years.  The full amount of the Company's estimated liability is reflected
in the December 31, 1996 financial statements.  See Note 2 of Notes to
Consolidated Financial Statements.


The Company is subject to minor lawsuits incidental to operations in the oil
and gas industry.  The Company believes it has meritorious defenses to all
lawsuits in which it is a defendant and will vigorously defend against them.
The resolution of such lawsuits, regardless of the outcome, will not have a
material adverse effect on the Company's financial position or results of
operations.

OPERATING LEASES  The Company is obligated under noncancelable operating leases
for office space and certain equipment.  Total rental expense related to these
leases was $1,653,378, $1,263,930 and $992,509 for December 31, 1996, 1995 and
1994, respectively.  Future minimum lease payments as of December 31, 1996 are:

<TABLE>
<CAPTION>
Year Ending December 31,
-----------------------------------------------------------------
<C>                                                 <C>       
1997                                                $   2,151,433
1998                                                    1,644,060
1999                                                    1,046,478
2000                                                      537,771
2001                                                      579,430
Thereafter                                              1,159,681
                                                    -------------
Total minimum lease payments                        $   7,118,853
                                                    =============
</TABLE>

NOTE 11 - UNEARNED INCOME

During the twelve months ended December 31, 1995 and 1994 the Company received
$575,000, and $2,300,000, respectively from an unaffiliated third party as
payment for tax credits associated with gas production from certain of the
Company's oil and gas properties.  The unaffiliated third party was entitled to
these tax credits as gas production occurred.  The Company recorded the
proceeds as unearned income and amortized the amount to the gas revenues as the
gas was produced and the credits were generated.  The agreement was terminated
as of December 1, 1995.  The Company





                                       56
<PAGE>   57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


recognized approximately $1,600,000 and $1,300,000, of other gas revenues
during the years ended December 31, 1995 and 1994, respectively, related to the
amortization of this unearned income.

NOTE 12 - OTHER GAS REVENUES

The Company and its subsidiaries continue to enter into transactions designed
to monetize the Company's Section 29 tax credits.  In nine separate
transactions, starting on December 1, 1995, the Company has sold to
unaffiliated third parties its right, title and interest in certain of its oil
and gas leases and mineral interests.  The sale will enable the third parties
to earn tax credits associated with future oil and gas production.  The Company
reserved a volumetric production payment that entitles it to 100% of the net
cash flows from the properties.  The Company will receive periodic payments
from the third parties based on tax credits generated from the gas production
on the sold properties.  The Company recognized approximately $2.7 million and
$177,000 of other gas revenues associated with the tax credits during the years
ended December 31, 1996 and 1995, respectively.

NOTE 13 - OIL AND GAS ACTIVITIES

MAJOR PURCHASERS  In 1996, sales to Amoco Production Company and Panenergy
accounted for approximately $29,300,000 and $22,800,000 or 27.3% and 21.2%, of
total oil and gas sales, respectively.  In 1995, sales to Amoco Production
Company and K N Marketing, Inc. accounted for approximately $24,600,000 and
$6,120,000 or 46% and 11.5%, of total oil and gas sales, respectively.  In
1994, sales to Amoco Production Company accounted for approximately $46,548,000
or 79%, of total oil and gas sales.

COSTS INCURRED  Costs incurred in oil and gas operations and the related
depreciation, depletion, and amortization per equivalent unit-of-production are
as follows:
<TABLE>
<CAPTION>
                                                            Year Ended December 31,
                                          1996            1995             1994
                                     ------------     ------------     ------------
<S>                                  <C>              <C>              <C>         
Property acquisition costs
     Unproved                        $ 35,227,230     $  4,342,722     $ 11,443,820
     Proved                          $338,813,429     $ 25,014,756     $  2,600,005
                                     ------------     ------------     ------------
Exploration costs                    $  2,100,119     $  2,747,920     $  3,293,367
                                     ------------     ------------     ------------
Development costs                    $ 37,818,991     $ 29,989,260     $ 64,563,750
Depreciation, depletion and
     amortization                    $ 40,590,801     $ 25,292,193     $ 24,080,619
Depreciation, depletion and
     amortization per equivalent
     unit-of-production              $       5.33     $       4.97     $       4.80
                                     ============     ============     ============
</TABLE>

                                       57
<PAGE>   58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


NOTE 14 - SUMMARY OF GUARANTEES ON 9 1/4% SENIOR SUBORDINATED NOTES

In November 1996, the Company issued $150 million of its 9 1/4% senior
subordinated notes due in 2006.  The Notes are general, unsecured obligations
of the Company, subordinated in right of payment to all existing and any future
senior indebtedness of the Company.  The Notes rank pari passu with existing
and any future senior subordinated indebtedness and senior to any future
subordinated indebtedness of the Company.  The Notes are fully and
unconditionally guaranteed, jointly and severally, on an unsecured, senior
subordinated basis by two of the Company's subsidiaries, Orion Acquisition,
Inc. and HSRTW, Inc (the "Subsidiary Guarantors").

Sections 13 and 15(d) of the Securities Exchange Act of 1934 require
presentation of the following supplemental condensed consolidating financial
statements of the  Subsidiary Guarantors.  Separate complete financial
statements of the respective Subsidiary Guarantors are not material to
investors.  There are no significant contractual restrictions on distributions
from each of the Subsidiary Guarantors to the Company.

Investments in subsidiaries are accounted for by the parent under the equity
method for purposes of the supplemental condensed consolidated financial
statement presentation.  Under this method, investments are recorded at cost
and adjusted for the parent company's ownership share of the subsidiaries'
cumulative results of operations.  In addition, investments increase in the
amount of contributions to subsidiaries and decrease in the amount of
distributions from subsidiaries.  The elimination entries eliminate the equity
method investment in subsidiaries and equity in earnings of subsidiaries,
intercompany payables and receivables and other transactions between
subsidiaries including contributions and distributions.





                                       58
<PAGE>   59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.

                     CONDENSED CONSOLIDATING BALANCE SHEETS

                            DECEMBER 31, 1996

<TABLE>
<CAPTION>
                                  ASSETS
                                                                                        NON-
                                                          SUBSIDIARY GUARANTORS       GUARANTOR     ELIMINATION
                                             HSR           HSRTW          ORION      SUBSIDIARIES     ENTRIES      CONSOLIDATION
                                       -------------  -------------  -------------  -------------  -------------   -------------
<S>                                    <C>            <C>            <C>            <C>            <C>             <C>
Cash and cash equivalents              $   5,129,513  $     454,230  $        --    $   3,181,013  $        --     $   8,764,756
Intercompany receivables                  11,890,714      8,921,050      6,145,420     26,074,938    (53,032,122)           --
Other current assets                      16,690,349      6,373,241      5,567,981     22,844,145       (392,648)     51,083,068
                                       -------------  -------------  -------------  -------------  -------------   -------------
  Total current assets                    33,710,576     15,748,521     11,713,401     52,100,096    (53,424,770)     59,847,824
                                       -------------  -------------  -------------  -------------  -------------   -------------

Oil and gas properties, net              286,119,371    231,268,305    121,885,574     12,906,728           --       652,179,978
Gas gathering and transportation
  facilities, net                               --             --             --        4,674,075           --         4,674,075
Office and transportation equipment
  and other property, net                  3,414,251      1,249,814           --           44,371           --         4,708,436
Investments in subsidiaries and other
  investments                            346,850,777     22,415,437           --          920,285   (369,266,214)        920,285
Other noncurrent assets                    8,564,232           --          354,227         36,322           --         8,954,781
                                       -------------  -------------  -------------  -------------  -------------   -------------
  Total assets                         $ 678,659,207  $ 270,682,077  $ 133,953,202  $  70,681,877   (422,690,984)   $731,285,379
                                       =============  =============  =============  =============  =============   =============

            LIABILITIES, STOCKHOLDERS' EQUITY AND PARTNERS' CAPITAL

Current liabilities                    $  24,112,205  $   6,006,909  $      82,129  $  16,289,756  $    (392,648)  $  46,098,351
Intercompany payables                     32,220,358      3,749,379      4,511,218     12,551,167    (53,032,122)           --
Long-term bank debt and other debt,
  net of current portion                 174,734,696           --             --             --             --       174,734,696
9 7/8% subordinated notes, due 2003       74,595,375           --             --             --             --        74,595,375
9 1/4% subordinated notes, due 2006      149,232,713           --             --             --             --       149,232,713
Other noncurrent liabilities               9,005,922           --             --             --             --         9,005,922
Deferred income taxes                     22,034,377     58,663,252      1,489,473      2,641,510           --        84,828,612
Minority interest                               --             --             --             --           66,149          66,149
Stockholders' equity and partners'
  capital                                192,723,561    202,262,537    127,870,382     39,199,444   (369,332,363)    192,723,561
                                       -------------  -------------  -------------  -------------  -------------   -------------
  Total liabilities, stockholders'
    equity and partners' capital       $ 678,659,207  $ 270,682,077  $ 133,953,202  $  70,681,877  $(422,690,984)  $ 731,285,379
                                       =============  =============  =============  =============  =============   =============
</TABLE>


                                       59
<PAGE>   60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.

               CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
                     TWELVE MONTHS ENDED DECEMBER 31, 1996

<TABLE>
<CAPTION>
                                                                                             NON-
                                                              SUBSIDIARY GUARANTORS        GUARANTOR    ELIMINATION
                                                 HSR           HSRTW         ORION        SUBSIDIARIES     ENTRIES    CONSOLIDATION
                                                 ---           -----         -----        ------------     -------    -------------
<S>                                              <C>            <C>          <C>          <C>          <C>            <C>         
Revenues
 Oil and gas sales                               $ 51,885,399   $21,480,541  $16,219,774  $17,156,849  $    538,310   $107,280,873
 Trading and transportation                         6,041,420          --           --     54,676,969   (14,345,682)    46,372,707
 Other revenues                                     2,915,034       193,334         --        387,399      (193,277)     3,302,490
                                                 ------------   -----------  -----------  -----------  ------------   ------------
     Total revenues                                60,841,853    21,673,875   16,219,774   72,221,217   (14,000,649)   156,956,070
                                                 ------------   -----------  -----------  -----------  ------------   ------------
Expenses
  Production taxes and lease operating             11,760,851     4,966,435    4,864,496    4,295,109          --       25,886,891
  Cost of trading and transportation                6,335,444          --           --     53,171,082   (13,807,372)    45,699,154
  Depreciation, depletion and amortization         20,093,779     9,064,970    6,072,844    7,103,289          --       42,334,882
  General and administrative                        4,330,365       695,343         --        616,685          --        5,642,393
  Interest expense                                 21,438,796       192,514    1,373,056      124,751      (193,277)    22,935,840
                                                 ------------   -----------  -----------  -----------  ------------   ------------
      Total expenses                               63,959,235    14,919,262   12,310,396   65,310,916   (14,000,649)   142,499,160
                                                 ------------   -----------  -----------  -----------  ------------   ------------
Income (loss) before provision for income taxes    (3,117,382)    6,754,613    3,909,378    6,910,301          --       14,456,910
Provision (benefit) for income taxes               (1,187,723)    2,573,508    1,489,473    2,632,825          --        5,508,083
                                                 ------------   -----------  -----------  -----------  ------------   ------------
                                                   (1,929,659)    4,181,105    2,419,905    4,277,476          --        8,948,827
Equity in earnings of subsidiaries                  9,437,192     1,441,294         --           --     (10,878,486)          --
                                                 ------------   -----------  -----------  -----------  ------------   ------------
Net income                                       $  7,507,533   $ 5,622,399  $ 2,419,905  $ 4,277,476  $(10,878,486)  $  8,948,827
                                                 ============   ===========  ===========  ===========  ============   ============
</TABLE>


               CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
                     TWELVE MONTHS ENDED DECEMBER 31, 1996

<TABLE>
<CAPTION>
                                                                                             NON-
                                                               SUBSIDIARY GUARANTORS       GUARANTOR     ELIMINATION
                                                  HSR            HSRTW        ORION       SUBSIDIARIES     ENTRIES     CONSOLIDATION
                                              ------------   ------------   ----------    ------------   -----------   -------------
<S>                                           <C>            <C>            <C>            <C>          <C>            <C>         
Cash flow provided by (used in) operating     
      activities                              $ 39,213,549   $  8,311,612   $ 2,507,941    $4,357,742   $ (2,139,695)  $ 52,251,149
                                              ------------   ------------   ------------   ----------   ------------   ------------
Cash flows from investing activities          
Exploration, development and leasehold costs   (42,464,970)    (6,654,564)      (689,441)    (817,546)          --      (50,626,521)
Purchase of proved and unproved properties      (2,713,710)          --     (127,268,977)        --             --     (129,982,687)
Cash payment for the purchase of Tide West,   
      net of cash acquired                            --      (86,427,593)          --      1,302,509           --      (85,125,084)
Contributions to subsidiaries                 (250,250,792)          --             --           --      250,250,792           --
Other                                            8,867,656        (75,540)          --        (58,236)          --        8,733,880
                                              ------------   ------------   ------------   ----------   ------------   ------------

     Net cash used in investing activities    (286,561,816)   (93,157,697)  (127,958,418)     426,727    250,250,792   (257,000,412)
                                              ------------   ------------   ------------   ----------   ------------   ------------
Cash flows from financing activities          
Proceeds from debt                             575,816,596    (39,500,000)          --           --             --      536,316,596
Repayments of debt                            (315,258,900)          --             --           --             --     (315,258,900)
Contributions from equity holders                     --      124,800,315    125,450,477   (2,150,000)  (248,100,792)          --
Other                                           (7,781,181)          --             --        131,228        (10,305)    (7,660,258)
                                              ------------   ------------   ------------   ----------   ------------   ------------
     Net cash provided by financing           
       activities                              252,776,515     85,300,315    125,450,477   (2,018,772)  (248,111,097)   213,397,438
                                              ------------   ------------   ------------   ----------   ------------   ------------
Net increase (decrease) in cash and cash      
     equivalents                                 5,428,248        454,230           --      2,765,697           --        8,648,175
Cash and cash equivalents, beginning          
     of the year                                  (298,735)          --             --        415,316           --          116,581
                                              ------------   ------------   ------------   ----------   ------------   ------------
Cash and cash equivalents, end of the period  $  5,129,513   $    454,230   $       --     $3,181,013   $       --     $  8,764,756
                                              ============   ============   ============   ==========   ============   ============
</TABLE>


Certain non cash transactions have taken place between HSR and its subsidiaries
related to the equity contributions. Accordingly, these transactions are not
reflected in the statements of cash flows.




                                       60
<PAGE>   61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


NOTE 15 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

OIL AND GAS NET RESERVES  The following unaudited tables set forth the
estimated quantities of proved oil and gas reserves for the Company and the
changes in total proved reserves as of December 31, 1996, 1995 and 1994.  All
such reserves are located in the United States.  The amounts as of December 31,
1996, 1995 and 1994, were prepared by the Company and substantially all were
reviewed by either Williamson Petroleum Consultants, Inc. or by Netherland,
Sewell & Associates, Inc., each an independent petroleum engineering consulting
firm.

ANALYSIS OF CHANGES IN PROVED RESERVES

<TABLE>
<CAPTION>
                                                      Oil           Gas
                                                   --------------------------
                                                                (Thousands of
                                                   (Barrels)      Cubic Feet)
                                                   ----------    -----------
<S>                                                <C>           <C>        
Proved developed and undeveloped reserves
Balance, December 31, 1993                         16,300,450    252,412,600
    Revision of previous estimates                   (415,407)   (12,096,649)
    Extensions, discoveries and other additions     4,037,122     43,451,028
    Production                                     (1,663,745)   (20,107,559)
    Purchases of reserves in place                     42,800      1,618,380
                                                   ----------    -----------
Balance, December 31, 1994                         18,301,220    265,277,800
    Revision of previous estimates                 (1,293,758)    (1,363,766)
    Extensions, discoveries and other additions     1,127,196     11,851,415
    Production                                     (1,581,586)   (21,049,484)
    Purchases of reserves in place                  3,124,140     45,353,782
    Sales of reserves in place                        (89,452)    (1,292,347)
                                                   ----------    -----------
Balance, December 31, 1995                         19,587,760    298,777,400
    Revision of previous estimates                      4,868       (880,400)
    Extensions, discoveries and other additions     1,424,288     41,786,934
    Production                                     (1,923,435)   (34,163,010)
    Purchases of reserves in place                 15,648,402    351,707,690
    Sales of reserves in place                       (127,503)   (12,807,314)
                                                   ----------    -----------
Balance, December 31, 1996                         34,614,380    644,421,300
                                                   ==========    ===========
Proved developed reserves
    December 31, 1994                              10,852,870    187,358,100
                                                   ==========    ===========
    December 31, 1995                              11,557,200    219,262,100
                                                   ==========    ===========
    December 31, 1996                              23,111,490    508,923,100
                                                   ==========    ===========
</TABLE>



                                       61
<PAGE>   62
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


STANDARDIZED MEASURE  The standardized measure of discounted future net cash
flows, and changes therein related to proved oil and gas reserves are as
follows:

<TABLE>
<CAPTION>
                                                                                                Year Ended December 31,
                                                                         1996              1995              1994
                                                                    ---------------   ---------------   ---------------
<S>                                                                 <C>               <C>               <C>            
Future cash inflows                                                 $ 3,045,480,000   $   857,074,500   $   755,941,800
Future production costs                                                (646,925,700)     (219,076,680)     (201,204,540)
Future development costs                                               (170,708,400)     (105,043,800)      (91,434,640)
                                                                    ---------------   ---------------   ---------------
Undiscounted future pre-tax cash flows                                2,227,845,900       532,954,020       463,302,620
Undiscounted future income taxes                                       (619,110,885)     (129,776,984)      (85,709,360)
                                                                    ---------------   ---------------   ---------------
Undiscounted future pre-tax cash flows, net of future income taxes    1,608,735,015       403,177,036       377,593,260
10% discount factor                                                    (790,717,180)     (203,918,587)     (183,339,959)
                                                                    ---------------   ---------------   ---------------
Standardized measure of discounted future net cash flows            $   818,017,835   $   199,258,449   $   194,253,301
                                                                    ===============   ===============   ===============
Discounted future pre-tax cash flows excluding income taxes         $ 1,130,923,000   $   257,044,900   $   230,331,400
                                                                    ===============   ===============   ===============
</TABLE>

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.  However, for ceiling test purposes, future income taxes
are estimated using the "short-cut" method.

The following are the principal sources of change in the standardized measure
of discounted future net cash flows:

<TABLE>
<CAPTION>
                                                                                 Year Ended December 31,
                                                               1996             1995           1994
                                                           -------------   -------------   -------------
<S>                                                        <C>             <C>             <C>          
Standardized measure of discounted future net cash flows,
     beginning of the year                                 $ 199,258,449   $ 194,253,301   $ 165,785,621
Sales and transfers of oil and gas produced, net of
     production costs                                        (80,450,583)    (38,528,808)    (43,962,756)
Sales of reserves in place                                   (14,892,716)     (1,338,530)             --
Net changes in prices and production costs:
     on beginning of year reserves                           281,677,346       3,996,469     (15,045,652)
     on reserves purchased during the year                   200,295,822              --              --
Extensions, discoveries and improved recovery,
     less related costs                                       80,749,964      11,194,559      37,157,649
Changes in future development costs                           (2,088,801)    (14,744,408)      4,812,549
Development costs incurred during the period that reduced
     future development costs                                 32,335,836      33,402,053      45,086,667
Revisions of previous quantity estimates                      (1,679,406)     (6,918,919)    (10,390,834)
Purchase of reserves in place                                345,252,515      36,213,033       1,451,166
Accretion of discount                                         25,704,490      23,033,140      21,053,690
Net change in income taxes                                  (255,118,714)    (21,708,352)      8,673,180
Changes in production rates (timing) and other                 6,973,633     (19,595,089)    (20,367,979)
                                                           -------------   -------------   -------------
Standardized measure of discounted future net cash flows,
     end of the year                                       $ 818,017,835   $ 199,258,449   $ 194,253,301
                                                           =============   =============   =============
</TABLE>



                                       62
<PAGE>   63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


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 the Company 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
$24.92/Bbl of oil and $3.39/Mcf of gas at December 31, 1996, $18.59/Bbl of oil
and $1.65/Mcf of gas at December 31, 1995 and $15.65/Bbl of oil and $1.77/Mcf
of gas at December 31, 1994.

These estimates were determined in accordance with SFAS No. 69.  Because of
unpredictable variances in expenses and capital forecasts, crude oil and
natural gas price changes, and the fact that the basis for such estimates vary
significantly, management believes 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 the
Company.  Management's investment and operating decisions may be based upon
reserve estimates that include price, cost and production assumptions which 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 the
Company has 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 justify revisions,
either upward or downward, of reserve estimates.  Such adjustments may be
material.





                                       63
<PAGE>   64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


NOTE 16 - QUARTERLY FINANCIAL DATA (UNAUDITED)

The Company's quarterly results of operations are summarized as follows (in
thousands, except per share data):

<TABLE>
<CAPTION>
                                                                                            1996
                                                       Mar. 31    June 30   Sept. 30     Dec. 31
                                                       -------    -------   --------     -------
<S>                                                  <C>        <C>        <C>         <C>     
Oil and gas revenues                                 $ 14,154   $ 21,913   $ 32,882    $ 41,052
Operating expenses                                      3,891      4,735      8,100       9,161
                                                     --------   --------   --------    --------
Operating income                                       10,263     17,178     24,782      31,891
                                                     --------   --------   --------    --------
Net income                                           $    191   $  1,645   $  1,357    $  5,756
                                                     --------   --------   --------    --------
Net income
    common and common
    equivalent share assuming full dilution          $   0.02   $   0.14   $   0.08    $   0.33
                                                     --------   --------   --------    --------

<CAPTION>                                                                                
                                                                                         1995
                                                      Mar. 31    June 30   Sept. 30     Dec. 31
                                                      -------    -------   --------     -------
<S>                                                  <C>        <C>        <C>         <C>     
Oil and gas revenues                                 $ 15,737   $ 14,810   $ 11,921    $ 12,709
Operating expenses                                      4,029      3,825      2,870       3,263
                                                     --------   --------   --------    --------
Operating income                                       11,708     10,985      9,051       9,446
                                                     --------   --------   --------    --------
Net income (loss)                                    $    640   $    180   $   (383)   $   (163)
                                                     --------   --------   --------    --------
Net income (loss) per common and common
    equivalent share assuming full dilution          $   0.06   $   0.02   $  (0.03)   $  (0.01)
                                                     --------   --------   --------    --------

<CAPTION>
                                                                                          1994
                                                       Mar. 31    June 30   Sept. 30     Dec. 31
                                                       -------    -------   --------     -------
<S>                                                  <C>        <C>        <C>         <C>     
Oil and gas revenues                                 $ 13,977   $ 14,927   $ 15,738    $ 15,520
Operating expenses                                      3,145      3,274      3,496       3,529
                                                     --------   --------   --------    --------
Operating income                                       10,832     11,653     12,242      11,991
                                                     --------   --------   --------    --------
Net income                                           $  1,729   $  1,592   $  1,682    $  1,256
                                                     --------   --------   --------    --------
Net income per common and common
    equivalent share assuming full dilution          $   0.15   $   0.14   $   0.14    $   0.11
                                                     --------   --------   --------    --------
</TABLE>





                                       64
<PAGE>   65
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,
1996 and 1995, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1996.  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 generally accepted auditing
standards.  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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.

/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP

Denver, Colorado

February 24, 1997





                                       65
<PAGE>   66
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, 1997, a
definitive proxy statement which will include information with respect to the
election of directors.





                                       66
<PAGE>   67
                                    PART IV

Item 14.         EXHIBITS

         (a)  Exhibits.


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       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.)

10.1      Amended Note and Warrant Purchase Agreement dated January 15, 1991,
          among NGP, Resolute Resources, Inc., and the Company. (Incorporated
          by reference to Exhibit 4.4.1 to the Company's Quarterly Report on
          Form 10-Q for the quarter ended December 31, 1990, filed February 14,
          1991.)

10.1.1    Amendment No. 1 to Note and Warrant Purchase Agreement dated June
          28, 1991, between the Company and NGP.  (Incorporated by reference
          to Exhibit 4.4.2 to the Company's Annual Report on Form 10-K for the
          fiscal year ended June 30, 1991, filed September 30, 1991.)

10.1.2    Second Amendment to Note and Warrant Purchase Agreement dated August
          17, 1992, between the Company and NGP.  (Incorporated by reference
          to Exhibit 4.2.2 to Amendment No. 2 to the Company's Registration
          Statement on Form S-1, No. 33-52774, filed November 19, 1992.)

10.1.3    Third Amendment to Note and Warrant Purchase Agreement dated October
          21, 1993, between the Company and NGP.  (Incorporated by reference
          to Exhibit 4.1.3 to Amendment No. 2 to the Company's Registration
          Statement on Form S-3, No. 33-70354, filed November 23, 1993.)

10.2      Amended and Restated Warrant Agreement dated January 15, 1991,
          between NGP and the Company.  (Incorporated by reference to Exhibit
          4.5.1 to the Company's Quarterly Report on Form 10-Q for the quarter
          ended December 31, 1990, filed February 14, 1991.)
          




                                       67
<PAGE>   68
10.3       Amended Warrant No. W-1, dated January 15, 1991, and issued by the
           Company to NGP. (Incorporated by reference to Exhibit 4.6.1 to the
           Form 8, Second Amendment to Form 10, filed April 8, 1991.)

10.3.1     Amendment No. 1 to Amended Warrant No. W-1, dated December 30, 1991,
           and issued by the Company to NGP.  (Incorporated by reference to
           Exhibit 4.6.2 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended December 31, 1991, filed on February 14, 1991.)

10.4       Form of Warrant No. W-10, dated January 28, 1992, and issued by the
           Company to NGP. (Incorporated by reference to Exhibit 4.16 to
           Amendment No. 1 to the Company's Registration Statement on Form S-1,
           No.  33-52774, filed November 9, 1992.)

10.5*      1987 Stock Incentive Plan, as amended December 2, 1996.

10.6       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.)

10.7       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.)

10.8       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.)

10.8.1     1993 Directors' Stock Option Plan. (Incorporated by reference to
           Exhibit 10.8.1 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.))

10.9       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.)

10.10      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.))

10.11      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.)

10.12      Interest exchange agreement between The Chase Manhattan Bank, N.A.
           and the Company dated May 9, 1995.  (Incorporated by reference to
           Exhibit 10.19 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1995, filed August 14, 1995.)

10.13      Amended and Restated Agreement and Plan of Merger, dated as of April
           29, 1996, among the Company, HSR Acquisition, Inc. and Tide West Oil
           Co. (Incorporated by reference as Annex A to Amendment No. 2 to the
           Company's Registration Statement on Form S-4, No. 333-01991, filed
           on May 2, 1996.)





                                       68
<PAGE>   69
10.14      Agreement for Purchase and Sale of Assets, dated as of February 24,
           1996, among the Company, Basin Exploration, Inc. ("Basin") and Orion
           Acquisition, Inc. ("Orion"). (Incorporated by reference to Exhibit
           2.3 to the Company's Form 8-K, filed March 12, 1996.)

10.15      Agreement for Purchase and Sale of Assets [Wattenberg], dated as of
           February 24, 1996, among the Company, Orion and Basin. (Incorporated
           by reference to Exhibit A to the Company's Schedule 13D relating to
           Basin Exploration, Inc. filed on March 6, 1996.)

10.16      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.)

10.17      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.)

10.18      Purchase and Sale Agreement dated March 25, 1996 between Orion
           Acquisition, Inc., 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.)

10.19      Credit Agreement, dated as of June 7, 1996, among the Company and
           The Chase Manhattan Bank, N.A. ("Chase"), as agent of the Banks
           signatory thereto. (Incorporated by reference to the Company's
           Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
           filed August 14, 1996.)

10.20      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 the Company's Quarterly Report on Form
           10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)

10.21      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
           the Company's Quarterly Report on Form 10-Q for the quarter ended
           June 30, 1996,filed August 14, 1996.)

10.22      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.)

10.23      Assignment of Liens and Amendment of Amended, Restated and
           Consolidated Mortgage,   Assignment of Production, Security
           Agreement and Financing Statement, dated June 14, 1996, among Chase
           (Assignor), Chase (Assignee) and the Company. (Incorporated by
           reference to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)

10.24      Guaranty Agreement by HSR Acquisition, Inc. in favor of Chase, as
           Agent, dated June 14, 1996. (Incorporated by reference to the
           Company's Quarterly Report on Form 10-Q for the quarter ended June
           30, 1996, filed August 14, 1996.)





                                       69
<PAGE>   70
10.25      Guaranty Agreement by Orion Acquisition, Inc. in favor of Chase, as
           Agent, dated   June 14, 1996.  (Incorporated by reference to the
           Company's Quarterly Report on Form 10-Q for the quarter ended June
           30, 1996, filed August 14, 1996.)

10.26      First Amendment to Guaranty Agreement dated as of June 17, 1996, by
           and among Orion Acquisition, Inc. and Chase, in its individual
           capacity and as agent for the Lenders.  (Incorporated by reference
           to the Company's Quarterly Report on Form 10-Q for the quarter ended
           June 30, 1996, filed August 14, 1996.)

10.27      First Amendment to Guaranty Agreement dated as of June 17, 1996, by
           and among HSRTW, Inc. (formerly HSR Acquisition, Inc.) and Chase, in
           its individual capacity and as agent for the Lenders. (Incorporated
           by reference to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)

10.28      Third Amendment and Supplement to Amended, Restated and Consolidated
           Mortgage, Assignment of Production, Security Agreement and Financing
           Statement, dated as of July 15, 1996, by and between the Company and
           Chase.  (Incorporated by reference to the Company's Quarterly Report
           on Form 10-Q for the quarter ended June 30, 1996, filed August 14,
           1996.)

10.29      Hedging Agreement between Chase and the Company dated May 1, 1996.
           (Incorporated by reference to the Company's Quarterly Report on Form
           10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)

10.30      Hedging Agreement between Chase and the Company dated May 1, 1996.
           (Incorporated by reference to the Company's Quarterly Report on Form
           10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)

10.31      Hedging Agreement between Chase and the Company dated June 1, 1996.
           (Incorporated by reference to the Company's Quarterly Report on Form
           10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)

11         Purchase and Sale Agreement between the Company and Wattenberg Gas
           Investments, LLC dated April 25, 1996.  (Incorporated by reference
           to the Company's Quarterly Report on Form 10-Q for the quarter ended
           June 30, 1996, filed August 14, 1996.)

11         Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
           and Wattenberg Gas Investments, LLC dated May 21, 1996.
           (Incorporated by reference to the Company's Quarterly Report on Form
           10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)

10.33      Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
           and Wattenberg Gas Investments, LLC dated May 21, 1996.
           (Incorporated by reference to the Company's Quarterly Report on Form
           10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)

10.34      Purchase and Sale Agreement between Orion Acquisition, Inc. and
           Wattenberg Gas Investments, LLC dated June 14, 1996. (Incorporated
           by reference to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)





                                       70
<PAGE>   71
10.35      Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
           and Wattenberg Gas Investments, LLC dated June 14, 1996.
           (Incorporated by reference to the Company's Quarterly Report on Form
           10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)

10.36      Purchase and Sale Agreement between Orion Acquisition, Inc. and
           Wattenberg Gas Investments, LLC dated June 14, 1996. (Incorporated
           by reference to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)

10.37      Purchase and Sale Agreement between the Company and Wattenberg Gas
           Investments, LC dated June 28, 1996.  (Incorporated by reference to
           the Company's Quarterly Report on Form 10-Q for the quarter ended
           June 30, 1996, filed August 14, 1996.)

10.38      Purchase and Sale Agreement between HSRTW, Inc. and Westtide
           Investments, LLC dated August 9, 1996.  (Incorporated by reference
           to the Company's Quarterly Report on Form 10-Q for the quarter ended
           September 30, 1996, filed November 7, 1996.)

10.39      Acquisition Agreement between the Company and TCW Portfolio No. 1555
           DR V Sub-Custody Partnership, L.P. dated August 30, 1996.
           (Incorporated by reference to the Company's Quarterly Report on Form
           10-Q for the quarter ended September 30, 1996, filed November 7,
           1996.)

10.40      Purchase Agreement dated November 27, 1996 among the Company, Orion
           Acquisition, Inc., HSRTW, Inc., Salomon Brothers Inc., Chase
           Securities Inc., Lehman Brothers Inc., and Prudential Securities
           Incorporated.  (Incorporated by reference to Exhibit 10.40 to the
           Company's Registration Statement on Form S-4, No 333- 19433, filed
           January 8, 1997.)

10.41      Registration Agreement dated November 27, 1996 among the Company,
           Orion Acquisition,Inc., HSRTW, Inc. and Salomon Brothers Inc. in its
           individual capacity and as agent for Chase Securities Inc., Lehman
           Brothers Inc., and Prudential Securities Incorporated.
           (Incorporated by reference to Exhibit 10.41 to the Company's
           Registration Statement on Form S-4, No 333-19433, filed January 8,
           1997.)

10.42*     Employment Agreement between James Piccone and the Company dated
           April 21, 1995.  

27*        Finanacial Data Schedule 

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





                                       71
<PAGE>   72
                                   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 17th 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 17th day of March.

      Signature                                      Title
      ---------                                      -----
                                         
                                         
/s/ Nicholas J. Sutton                    Chairman of the Board, Chief
-------------------------                      Executive Officer      
  Nicholas J. Sutton                     (Principal Executive Officer)
                                                                      
                                         
                                         
/s/ P. Michael Highum                        President and Director
-------------------------                                          
  P. Michael Highum                      
                                         
                                         

  /s/ James E. Duffy                        Chief Financial Officer
-------------------------                         and Director        
    James E. Duffy                       (Principal Financial Officer)
                                                                      
                                         
                                         
 /s/ Annette Montoya                      Vice President - Accounting
-------------------------                        and Controller        
   Annette Montoya                       (Principal Accounting Officer)
                                                                       
                                         
                                         
 /s/ Kenneth A. Hersh                               Director
-------------------------                                   
   Kenneth A. Hersh                      
                                         

                                         
/s/ Michael J. Savage                               Director
-------------------------                                   
  Michael J. Savage                      
                                         

                                         
 /s/ Philip B. Smith                                Director
-------------------------                                   
   Philip B. Smith                       






                                       72
<PAGE>   73
                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
Exhibit                Description
<S>                    <C>

10.5*                  1987 Stock Incentive Plan, as amended December 2, 1996

10.42*                 Employment Agreement between James Piccone and the Company dated April 21, 1995

27*                    Financial Data Schedule
</TABLE>